item 14 exhibits financial statement schedules reports form 8k following documents filed part report 1 financial statements following consolidated financial statements company included part ii item 8 report b reports form 8k none el paso energy corporation exhibit list december 31 1998 exhibit identified filed part report exhibits incorporated reference prior filing designated asterisk exhibits designated incorporated herein reference prior filing indicated exhibits designated constitute management contract compensatory plan arrangement required filed exhibit report pursuant item 14c form 10k signatures pursuant requirements section 13 15d securities exchange act 1934 amended el paso energy corporation duly caused report signed behalf undersigned thereunto duly authorized 9th day march 1999 el paso energy corporation registrant william wise william wise chairman board president chief executive officer pursuant requirements securities exchange act 1934 amended report signed following persons behalf el paso energy corporation capacities dates indicated exhibit indexitem 14 exhibits financial statement schedules reports form 8k following documents filed part report 1 financial statements following consolidated financial statements company included part ii item 8 report b reports form 8k el paso filed current report form 8k dated october 26 1999 regarding completion merger el paso sonat inc el paso filed current report form 8k dated october 29 1999 providing consolidated financials sonat inc el paso filed current report form 8k dated december 1 1999 announcing results operations first thirty days following merger el paso sonat inc accounted pooling interests transaction el paso filed current report form 8k dated january 18 2000 announcing el paso entered agreement plan merger coastal corporation el paso filed current report form 8ka dated january 20 2000 providing additional disclosure exhibits regarding agreement plan merger el paso coastal corporation el paso filed current report form 8k dated february 3 2000 announcing el paso agreed acquire certain assets pge gas transmission texas corporation pge gas transmission teco inc el paso energy corporation exhibit list december 31 1999 exhibit identified filed part report exhibits incorporated reference prior filing designated asterisk exhibits designated incorporated herein reference prior filing indicated exhibits designated constitute management contract compensatory plan arrangement required filed exhibit report pursuant item 14c form 10k signatures pursuant requirements section 13 15d securities exchange act 1934 amended el paso energy corporation duly caused report signed behalf undersigned thereunto duly authorized 21st day february 2000 el paso energy corporation registrant william wise william wise president chief executive officer pursuant requirements securities exchange act 1934 amended report signed following persons behalf el paso energy corporation capacities dates indicated exhibit index exhibit identified filed part report exhibits incorporated reference prior filing designated asterisk exhibits designated incorporated herein reference prior filing indicated exhibits designated constitute management contract compensatory plan arrangement required filed exhibit report pursuant item 14c form 10kitem 14 exhibits financial statement schedules reports form 8k following documents filed part report 1 financial statements consolidated financial statements included part ii item 8 report b reports form 8k filed current report form 8k dated october 18 2000 filing exhibits connection offering medium term notes pursuant registration statement form s3 filed current report form 8k dated december 6 2000 updating pro forma financial statements relating proposed merger coastal corporation filed current report form 8k dated december 8 2000 filing exhibits connection offering medium term notes pursuant registration statement form s3 filed current report form 8k dated december 19 2000 filing exhibits connection offering medium term notes pursuant registration statement form s3 filed current report form 8k dated january 3 2001 announcing completion acquisition pges texas midstream operations filed current report form 8k dated january 29 2001 announcing completion merger coastal corporation filed current report form 8k dated february 5 2001 announcing completion merger coastal corporation exchange issuance shares el paso filed current report form 8k dated february 6 2001 announcing name change el paso corporation filed current report form 8k dated february 14 2001 announcing several events including opening new european trading floor purchase texas midstream operations recent developments california approval dividend increase announcement record earnings completion post merger restructuring 2001 analysts meetings filed current report form 8ka dated february 21 2001 announcing information debt issuances clarifying items contained february 14 2001 form 8k filed current report form 8k dated february 23 2001 announcing plans offer private offering zero coupon convertible debentures convertible el paso common stock filed current report form 8k dated march 2 2001 announcing combined operating results first 30 days following merger coastal el paso corporation exhibit list december 31 2000 exhibit identified filed part report exhibits incorporated reference prior filing designated asterisk exhibits designated incorporated herein reference prior filing indicated exhibits designated constitute management contract compensatory plan arrangement required filed exhibit report pursuant item 14c form 10k undertaking hereby undertake pursuant regulation sk item 601b paragraph 4iii furnish securities exchange commission upon request constituent instruments defining rights holders longterm debt consolidated subsidiaries filed herewith reason total amount securities authorized instruments exceed 10 percent total consolidated assets signatures pursuant requirements section 13 15d securities exchange act 1934 amended el paso corporation duly caused report signed behalf undersigned thereunto duly authorized 21st day march 2001 el paso corporation registrant william wise william wise chairman board president chief executive officer pursuant requirements securities exchange act 1934 amended report signed following persons behalf el paso corporation capacities dates indicated exhibit index exhibit identified filed part report exhibits incorporated reference prior filing designated asterisk exhibits designated incorporated herein reference prior filing indicated exhibits designated constitute management contract compensatory plan arrangement required filed exhibit report pursuant item 14c form 10kitem 14 exhibits financial statement schedules reports form 8k following documents filed part report 1 financial statements consolidated financial statements included part ii item 8 report b reports form 8k filed current report form 8k dated december 14 2001 announcing el pasos balance sheet enhancement plan filed current report form 8k dated december 26 2001 filing exhibits connection filing el paso shelf registration statement offering 20294118 shares el pasos common stock pursuant registration statement form s3 filed current report form 8k dated january 4 2002 reporting computation ratio earnings fixed charges five years ended december 31 2000 nine months ended september 30 2000 2001 filed amended current report form 8ka dated january 8 2002 correcting typographical error appearing january 4 2002 report form 8k filed current report form 8k dated january 11 2002 filing exhibits connection offering mediumterm notes pursuant registration statement form s3 el paso corporation exhibit list december 31 2001 exhibit identified filed part report exhibits incorporated reference prior filing designated asterisk exhibits designated incorporated herein reference prior filing indicated exhibits designated constitute management contract compensatory plan arrangement required filed exhibit report pursuant item 14c form 10k undertaking hereby undertake pursuant regulation sk item 601b paragraph 4iii furnish securities exchange commission upon request constituent instruments defining rights holders longterm debt consolidated subsidiaries filed herewith reason total amount securities authorized instruments exceed 10 percent total consolidated assets signatures pursuant requirements section 13 15d securities exchange act 1934 amended el paso corporation duly caused report signed behalf undersigned thereunto duly authorized 15th day march 2002 el paso corporation registrant william wise william wise chairman board president chief executive officer pursuant requirements securities exchange act 1934 amended report signed following persons behalf el paso corporation capacities dates indicated exhibit index exhibit identified filed part report exhibits incorporated reference prior filing designated asterisk exhibits designated incorporated herein reference prior filing indicated exhibits designated constitute management contract compensatory plan arrangement required filed exhibit report pursuant item 14c form 10kitem 14 controls procedures evaluation controls procedures supervision participation management including principal executive officer principal financial officer evaluated effectiveness design operation disclosure controls procedures disclosure controls internal controls internal controls within 90 days filing date annual report pursuant rules 13a15 15d15 securities exchange act 1934 exchange act definition disclosure controls internal controls disclosure controls procedures designed ensure information required disclosed us reports file submit exchange act recorded processed summarized reported within time periods specified exchange act disclosure controls include without limitation controls procedures designed ensure information required disclosed us reports file exchange act accumulated communicated management including principal executive officer principal financial officer appropriate allow timely decisions regarding required disclosure internal controls procedures designed objective providing reasonable assurance 1 transactions properly authorized 2 assets safeguarded unauthorized improper use 3 transactions properly recorded reported permit preparation financial statements conformity generally accepted accounting principles limitations effectiveness controls el pasos management including principal executive officer principal financial officer expect disclosure controls internal controls prevent errors fraud control system matter well conceived operated provide reasonable absolute assurance objectives control system met design control system must reflect fact resource constraints benefits controls must considered relative costs inherent limitations control systems evaluation controls provide absolute assurance control issues instances fraud within company detected inherent limitations include realities judgments decisionmaking faulty breakdowns occur simple errors mistakes additionally controls circumvented individual acts persons collusion two people management override controls design system controls also based part upon certain assumptions likelihood future events assurance design succeed achieving stated goals potential future conditions time control may become inadequate changes conditions degree compliance policies procedures may deteriorate inherent limitations costeffective control system misstatements due error fraud may occur detected significant changes internal controls sought determine whether significant deficiencies material weaknesses el pasos internal controls whether company identified acts fraud involving personnel significant role el pasos internal controls information important controls evaluation generally principal executive officer principal financial officer required disclose information boards audit committee independent auditors report related matters section annual report principal executive officer principal financial officer note date controls evaluation date annual report significant changes internal controls factors could significantly affect internal controls including corrective actions regard significant deficiencies material weaknesses effectiveness disclosure controls based controls evaluation principal executive officer principal financial officer concluded subject limitations discussed disclosure controls effective ensure material information relating el paso consolidated subsidiaries made known management including principal executive officer principal financial officer particularly period periodic reports prepared officer certifications principal executive officer principal financial officer required sections 302 906 sarbanesoxley act 2002 included herein exhibits annual report appropriate part iv item 15item 14 principal accountant fees services aggregate fees professional services rendered el paso pricewaterhousecoopers llp years ended december 31 2003 2002 audit fees years ended december 31 2003 2002 respectively professional services rendered audits consolidated financial statements el paso statutory subsidiary equity investee audits review documents filed securities exchange commission consents issuance comfort letters audit related fees years ended december 31 2003 professional services rendered carveout audits businesses disposed el paso sarbanesoxley act 2002 section 404 readiness assessment responding inquiries certain federal agencies related audit work performed working capital review certain discontinued operations accounting consultations attest services fees year ended december 31 2002 services rendered internal audit services due diligence related acquisitions accounting consultations pertaining divestitures attest services tax fees years ended december 31 2003 2002 respectively professional services related tax compliance tax planning fees year ended december 31 2003 professional services rendered advisory services fees year ended december 31 2002 services rendered risk management environmental advisory services policy approval audit nonaudit fees 2003 audit committee approved types audit nonaudit services pricewaterhousecoopers llp perform year range fees categories required applicable law audit committees current practice consider preapproval annually categories audit nonaudit services proposed provided independent auditors fiscal year audit committee also consider preapproval annually range fees manner fees determined type preapproved audit nonaudit services proposed provided independent auditors fiscal year audit committee must separately preapprove service included approved list services proposed services exceeding preapproved cost levels audit committee delegated preapproval authority chairman audit committee services need addressed audit committee meetings audit committee informed preapproval decisions next meeting audit committee selecting pricewaterhousecoopers llp independent auditor audit committee believes provision audit nonaudit services rendered pricewaterhousecoopers llp compatible maintaining firms independence audit committee considered whether provision nonaudit services pricewaterhousecoopers llp compatible maintaining auditor independence determined auditor independence compromised part iv item 15item 14 principal accountant fees services information appearing caption “principal accountant fees services” proxy statement 2005 annual meeting stockholders incorporated herein reference part iv item 15nanitem 14 principal accountant fees services information appearing caption “proposal 2 ratification appointment ernst young llp independent registered public accountant principal accountant fees services” “information board directors policy approval audit nonaudit fees” proxy statement 2007 annual meeting stockholders incorporated herein reference part iv item 15item 14 principal accountant fees services information appearing caption “proposal 2 ratification appointment ernst young llp independent registered public accountant principal accountant fees services” “information board directors policy approval audit nonaudit fees” proxy statement 2008 annual meeting stockholders incorporated herein reference part iv item 15item 14 principal accountant fees services information appearing caption “proposal 4 ratification appointment ernst young llp independent registered public accountant principal accountant fees services” “information board directors committees policy approval audit nonaudit fees” proxy statement 2009 annual meeting stockholders incorporated herein reference part iv item 15item 14 principal accountant fees services information appearing caption “proposal 3 ratification appointment ernst young llp independent registered public accounting firm principal accountant fees services” “information board directors committees policy approval audit nonaudit fees” proxy statement 2010 annual meeting stockholders incorporated herein reference part iv item 15item 14 principal accountant fees services information appearing caption “proposal 4 ratification appointment ernst young llp independent registered public accounting firm principal accountant fees services” “information board directors committees policy approval audit nonaudit fees” proxy statement 2011 annual meeting stockholders incorporated herein reference part iv item 15item 14 principal accountant fees services information required item incorporated reference definitive proxy statement 2012 annual meeting stockholders event prepare file proxy statement information shall filed amendment form 10k information shall filed later april 30 2012 part iv item 15 item 7 managements discussion analysis financial condition results operations general past four years company engaged numerous activities transactions designed significantly improve ability compete effectively rapidly evolving world energy industry late 1995 company acquired two energy marketing businesses eastex energy inc premier gas company first quarter 1996 company completed organizational review workforce reduction program reducing total workforce 2400 1600 may 1996 company completed placed service chaco plant largest facility kind continental us june 1996 company acquired cornerstone natural gas inc expanding gathering processing operations louisiana east texas company completed 4 billion acquisition eptpc december 1996 expanding natural gas pipeline systems coast continuing expansion nonregulated business operations connection eptpc acquisition company completed workforce reduction program first quarter 1997 reducing workforce combined companies approximately 800 4300 following acquisition eptpc 3500 late 1997 company acquired additional natural gas gathering processing assets completing purchases gulf states gas pipeline company certain texas gulf coast subsidiaries pacificorp tpc august 1998 company acquired deeptech additionally throughout 1996 1997 1998 companys international operations expanding latin south america asia pacific region australia europe changes makeup company significantly increased companys operating results ability generate operating cash flows needs cash investment opportunities consequently companys credit facilities substantially expanded period meet needs company adopted provisions sfas 131 disclosures segments enterprise related information effective january 1 1998 accordingly company segregated business activities five segments tennessee gas pipeline segment el paso natural gas segment el paso field services segment el paso energy marketing segment el paso energy international segment segments strategic business units offer variety different energy products services managed separately business segment requires different technology marketing strategies certain business segments earnings largely derived earnings equity investments accordingly company evaluates segment performance based ebit holding company reorganization taxfree internal reorganization effective august 1 1998 company reorganized holding company organizational structure whereby epec delaware corporation became parent holding company see item 8 financial statements supplementary data note 1 discussion holding company reorganization december 31 1998 company completed taxfree internal reorganization assets operations subsidiaries accordance private letter ruling received irs reorganization substantial number subsidiaries transferred company andor entities owned company neither creation holding company structure taxfree internal reorganization impact presentation herein results operations consolidated ebit year ended december 31 1998 increased 11 percent 644 million compared 578 million year ago period consolidated ebit year ended december 31 1997 403 million higher period 1996 variances discussed segment results segment results extent practicable results operations 1997 1996 reclassified conform current business segment presentation although results necessarily indicative results would achieved revised business segment structure effect periods operating revenues expenses segment include intersegment sales expenses eliminated consolidation energy commodity price volatility company believes gross margin revenue less cost sales rather operating revenue provides accurate indicator el paso field services el paso energy marketing segments discussion individual segments see item 8 financial statements supplementary data note 13 tennessee gas pipeline year ended december 31 1998 compared year ended december 31 1997 operating revenues year ended december 31 1998 32 million lower period 1997 primarily lower throughput resulting warmer average temperatures northeastern midwestern markets downward revision amount recoverable interest gsr costs operating expenses year ended december 31 1998 60 million lower period 1997 primarily due lower system fuel usage associated operating efficiencies attained period lower throughput reduced operation maintenance expenses largely due lower payroll costs lower franchise taxes net year ended december 31 1998 12 million higher period 1997 due interest income favorable sales use tax settlement gains sale assets year ended december 31 1997 compared year ended december 31 1996 results operations 1996 represents epecs ownership segment 20 days eptpc merger december 1996 operating revenues year ended december 31 1997 750 million higher period 1996 due acquisition eptpc december 1996 operating expenses year ended december 31 1997 460 million higher period 1996 due acquisition eptpc december 1996 net year ended december 31 1997 12 million higher period 1996 due acquisition eptpc december 1996 el paso natural gas year ended december 31 1998 compared year ended december 31 1997 operating revenues year ended december 31 1998 45 million lower period 1997 primarily due lower net revenues resulting pge contract expiration effective december 31 1997 decrease revenues loss pge contract significantly offset risk sharing revenue nontraditional revenues including revenue sale capacity dynegy favorable resolution contested rate matter see commitments contingencies rates regulatory matters discussion dynegy contracts operating expenses year ended december 31 1998 5 million lower period 1997 primarily due lower fuel costs recovery receivable previously deemed uncollectible partially offsetting decrease higher operating depreciation expenses year ended december 31 1997 compared year ended december 31 1996 operating revenues year ended december 31 1997 9 million higher period 1996 primarily due higher accruals takeorpay issues 1996 increase nontraditional revenues associated system expansion increase partially offset lower revenues resulting contract expirations occurring late 1996 early 1997 operating expenses year ended december 31 1997 37 million lower period 1996 primarily due lower labor benefits payroll tax expenses 1997 resulted reduction staffing levels 1996 net year ended december 31 1997 9 million lower period 1996 due gains disposition assets 1996 el paso field services year ended december 31 1998 compared year ended december 31 1997 total gross margin year ended december 31 1998 21 million higher period 1997 increase gathering treating margin primarily resulted higher gathering rates compared 1997 increase gathering treating volumes largely attributable acquisition tpc december 1997 inclusion results operations channel pipeline channel el paso field services segment beginning january 1998 versus el paso energy marketing segment decrease processing margin largely attributable lower liquids prices 1998 compared period 1997 liquids prices directly impact epfss processing revenues 1998 liquids prices lowest level since 1990 company expects trend continue 1999 company attempts mitigate impact lower liquids prices utilizing hedging strategies possible operating expenses year ended december 31 1998 27 million higher period 1997 primarily result additional expenses associated addition tpc channel well higher general administrative expenses net year ended december 31 1998 7 million higher period 1997 reflecting higher earnings equity investments higher capitalized interest year ended december 31 1997 compared year ended december 31 1996 total gross margin year ended december 31 1997 46 million higher period 1996 increase gathering treating margin processing margin primarily result higher natural gas prices san juan basin increase gathering treating volumes due acquisitions eptpc december 1996 cornerstone natural gas inc june 1996 operating expenses year ended december 31 1997 15 million higher period 1996 primarily due acquisition eptpc cornerstone natural gas inc net year ended december 31 1997 8 million higher period 1996 primarily due acquisition eptpc el paso energy marketing year ended december 31 1998 compared year ended december 31 1997 total gross margin year ended december 31 1998 21 million higher period 1997 increases total gross margin 1998 reflect fundamental shift focus initiated energy marketing business segment shortterm positional trading operation longterm assetbased origination trading risk management operation 1998 energy activities emphasized longterm power gas contract management related energy services power natural gas customers including independent power producers utilities end users trading activities substantially increasing volume 1998 primarily used manage risk longterm contract positions partially offsetting increase gross margin impact reporting operations channel el paso field services segment versus el paso energy marketing segment beginning january 1998 operating expenses year ended december 31 1998 15 million lower period 1997 decrease attributable 1997 restructuring marketing organization following eptpc acquisition transfer channel operations mentioned year ended december 31 1997 compared year ended december 31 1996 total gross margin year ended december 31 1997 24 million lower period 1996 decrease resulted generally lower industrywide gas marketing margins second quarter 1997 well extreme market volatility negatively impacted companys natural gas marketing activities trading positions first quarter 1997 operating expenses year ended december 31 1997 30 million higher period 1996 primarily due costs associated marketing activities eptpc acquired december 1996 el paso energy international year ended december 31 1998 compared year ended december 31 1997 operating revenues year ended december 31 1998 45 million higher period 1997 due consolidation financial reporting purposes manaus power project may 1998 acquiring additional ownership interest increase revenue attributable ema power project company began reporting consolidated basis july 1997 operating expenses year ended december 31 1998 49 million higher period 1997 primarily due costs related consolidation ema power manaus power projects increased general administrative expenses largely due higher project development costs reflecting increase projectrelated activities 1998 net year ended december 31 1998 27 million higher period 1997 primarily due increased equity earnings gain sale surplus power equipment recognition certain net gains projectrelated activities epeis projects move development stage operational stage common recognize onetime gains fees may include management fees development fees financing fees gains selldown ownership interests company anticipates additional onetime events may result recognition income expense future year ended december 31 1997 compared year ended december 31 1996 ebit year ended december 31 1997 6 million higher period 1996 1997 epei completed first full year operations following eptpc acquisition represented significant increase international project development activities increase development activities operating results likewise increased substantially 1996 corporate expenses net year ended december 31 1998 compared year ended december 31 1997 net corporate expenses year ended december 31 1998 8 million lower period 1997 decrease results lower benefits costs nonrecurring gains partially offset administrative costs associated formation startup epps power services group established first quarter 1998 costs associated companys year 2000 project year ended december 31 1997 compared year ended december 31 1996 net corporate expenses year ended december 31 1997 71 million lower period 1996 primarily result 99 million employee separation asset impairment charge recorded first quarter 1996 8 million charge fourth quarter 1996 relocating companys headquarters el paso texas houston texas connection acquisition eptpc decrease partially offset additional costs related discontinued operations assumed part eptpc acquisition interest debt expense year ended december 31 1998 compared year ended december 31 1997 interest debt expense year ended december 31 1998 29 million higher period 1997 primarily increased borrowings fund capital expenditures acquisitions investing expenditures higher average effective interest rate 1998 generally resulting higher rates associated march 1997 issuance tgp longterm debt approximately 883 million increases partially offset higher interest expense 1997 incurred rate refunds paid epngs customers 1998 year ended december 31 1997 compared year ended december 31 1996 interest debt expense year ended december 31 1997 128 million higher period 1996 due primarily level debt assumed connection acquisition eptpc companys debt capital realignment efforts income tax expense effective tax rate 1998 34 percent compared 38 percent 1997 1996 lower rate 1998 due increase level foreign income 1998 subject foreign tax rates differ us tax rates increases permanently reinvested equity income unconsolidated foreign affiliates provision us income tax required lower state income taxes liquidity capital resources cash operating activities net cash provided operating activities 61 million lower year ended december 31 1998 compared period 1997 decrease primarily attributable working capital changes takeorpay refund paid epngs customers february 1998 lower gsr collections 1998 prepayments risk sharing revenues 1997 decrease partially offset higher net tax refunds 1998 rate refunds paid tgps customers march 1997 epngs customers august 1997 cash investing activities net cash used investing activities approximately 1 billion year ended december 31 1998 investment activities included august 1998 acquisition deeptech see item 8 financial statements supplementary data note 2 well expenditures joint ventures equity investments expansion construction projects expenditures related joint ventures equity investments primarily attributable epei segment internally generated funds supplemented financing activities used fund expenditures companys planned capital investment expenditures 1999 approximately 900 million primarily expansion international operations domestic unregulated operations pipeline systems activities facilities computer communication system enhancements funding capital expenditures acquisitions investing expenditures expected provided internally generated funds commercial paper issuances available capacity existing credit facilities andor issuance longterm debt trust securities equity cash financing activities net cash provided financing activities 463 million year ended december 31 1998 march 1998 trust convertible preferred securities issued see item 8 financial statements supplementary data note 3 net proceeds 317 million october 1998 tgp issued debentures due 2028 net proceeds 391 million proceeds supplemented internally generated funds used retire longterm debt pay dividends acquire treasury stock fund capital equity investments corporate purposes since november 1994 company authorized board repurchase shares common stock shares repurchased held epecs treasury expected used conjunction epec stock compensation plans corporate purposes pursuant november 1994 authorization company repurchased 94 million shares december 31 1997 january 1998 board approved new 10 million common stock repurchase authority replaced november 1994 repurchase authority 10 million share repurchase authority reflects twoforone stock split discussed item 5 market registrants common equity related stockholder matters 1998 company repurchased 995600 common shares weighted average cost 3577 per share timing amount future share repurchases depend upon availability alternate uses capital market conditions factors future funding longterm debt retirements dividends financing expenditures expected provided internally generated funds commercial paper issuances available capacity existing credit facilities andor issuance longterm debt trust securities equity liquidity company relies cash generated internal operations primary source liquidity supplemented available credit facilities commercial paper program october 1997 epng established new 750 million fiveyear revolving credit competitive advance facility new 750 million 364day renewable revolving credit competitive advance facility collectively revolving credit facility connection establishment revolving credit facility eptpcs revolving credit facility also terminated outstanding balance 417 million financed fiveyear portion new revolving credit facility tgp designated borrower availability revolving credit facility expected used general corporate purposes including limited backstopping epngs tgps 1 billion commercial paper programs august 1998 epec became guarantor epngs revolving credit facility october 1998 750 million 364day portion revolving credit facility amended extend termination date october 27 1999 addition october 1998 revolving credit facility amended permit tgp issue commercial paper provided total amount commercial paper outstanding epng tgp equal less unused capacity revolving credit facility december 1998 epec became borrower revolving credit facility interest rate revolving credit facility 40 basis points libor spread varying based epecs longterm debt credit rating availability borrowings companys credit agreements subject specified conditions management believes company currently meets conditions include compliance financial covenants ratios required agreements absence default agreements continued accuracy representations warranties contained agreements including absence material adverse changes since specified dates companys senior debt issues given investment grade ratings standard poors moodys company must comply various restrictive covenants contained debt agreements include among others maintaining consolidated debt guarantees capitalization ratio greater 70 percent addition companys subsidiaries consolidated basis defined agreements may incur debt obligations would exceed 300 million aggregate excluding acquisition debt project financing certain refinancings december 31 1998 epecs consolidated debt guarantees capitalization ratio defined agreements 55 percent debt obligations epec subsidiaries excess permitted debt exceed 300 million consolidated basis march 1997 tgp issued 300 million aggregate principal amount 7 12 debentures due 2017 300 million aggregate principal amount 7 debentures due 2027 300 million aggregate principal amount 7 58 debentures due 2037 proceeds approximately 883 million net issuance costs used repay portion eptpcs credit facility general corporate purposes december 1997 epec filed shelf registration statement pursuant epec may offer 900 million including 250 million transferred prior shelf registrations common preferred equities various forms debt securities including convertible debt securities various types trust securities time determined market conditions march 1998 el paso energy capital trust delaware business trust sponsored company issued 65 million 4 34 trust convertible preferred securities sole assets trust approximately 335 million principal amount 4 34 convertible subordinated debentures due 2028 company result offering epec approximately 565 million capacity remaining existing shelf registration issue public securities registered thereunder september 1998 tgp filed shelf registration permitting tgp offer 600 million including 100 million carried forward prior shelf registration debt securities october 1998 tgp issued 400 million aggregate principal amount 7 debentures due 2028 proceeds tgp approximately 391 million net issuance cost approximately 300 million proceeds used repay tgps shortterm indebtedness revolving credit facility remainder used tgp general corporate purposes issuance tgp 200 million capacity remaining shelf registration march 1998 epng retired outstanding 8 58 debentures amount 17 million august 1998 eptpc retired outstanding 10 debentures amount 38 million february 1999 deeptech retired 11 senior subordinated promissory note due 2000 amount 16 million commitments contingencies indonesia company owns 475 percent interest power generating plant sengkang south sulawesi indonesia terms projects power purchase agreement pln purchases power company indonesian rupiah indexed us dollar date payment due devaluation rupiah cost power pln significantly increased pln currently unable pass increase cost customers without creating political instability pln requested financial aid minister finance help ease effects devaluation pln paying company rupiah indexed us dollar rate effect prior rupiah devaluation commitment pay balance financial aid received difference current prior exchange rate resulted outstanding balance due pln 94 million december 31 1998 company continues meet pln regular basis resolve payment arrears issue unsuccessful date recently company met discussed situation concerns world bank international monetary fund overseas private investment corporation us treasury department attempt achieve resolution indonesian minister finance company meet pln april 1999 discuss payments arrear terms contract rationalization process proposed pln company informed pln payments arrear must first received prerequisite discussions contract rationalization company cannot predict certainty outcome discussions companys total investment sengkang project approximately 25 million december 31 1998 additionally company provided specific recourse guarantees 6 million loans project lenders project debt nonrecourse company political risk insurance sengkang project company believes current economic difficulties indonesia material adverse effect companys financial position results operations cash flows brazil company owns 100 percent 250 mw power plant manaus brazil power plant currently sold fouryear contract electronorte denominated brazilian real due devaluation real january 1999 manaus suffered 831000 exchange loss december invoice provision contract recover effects devaluation invoice however future invoices covered provision contract entitling company recover substantial portion future devaluation company believes current economic difficulties brazil material adverse effect companys financial position results operations cash flows contract manaus power project provides delay damages paid electronorte specified construction schedule met completion project delayed beyond originally scheduled completion dates provided contract delays resulted claim electronorte delay damages company discussions electronorte regarding claim event company right construction contract assert claims construction contractor delay damages believes damages material adverse effect companys financial position results operations cash flows capital commitments december 31 1998 company capital investment commitments 245 million expected funded internally generated funds andor incremental borrowings companys planned capital investment projects discretionary nature substantial capital commitments made advance actual expenditures purchase obligations connection financing commitments certain joint ventures tgp entered unconditional purchase obligations products services totaling 77 million december 31 1998 tgps annual obligations agreements 21 million years 1999 2000 11 million year 2001 4 million years 2002 2003 16 million total thereafter excluded amounts tgps obligation purchase 30 percent output great plains coal gasification projects original design capacity july 2009 january 1997 tgp executed settlement contract part gsr negotiations recorded related liability third quarter 1997 purchased annuity 42 million fund expected remaining monthly demand requirements contract settlement continue january 2004 operating leases company leases certain property facilities equipment various operating leases addition 1995 el paso new chaco company epnc entered unconditional lease chaco plant lease term expires 2002 time epnc option obligation upon occurrence certain events purchase plant price sufficient pay amount 77 million construction financing plus interest certain expenses epnc purchase plant end lease term obligation pay residual guaranty amount equal approximately 87 percent amount financed plus interest company unconditionally guaranteed obligations epnc lease minimum annual rental commitments december 31 1998 follows aggregate minimum commitments reduced minimum sublease rentals approximately 15 million due future noncancelable subleases rental expense operating leases years ended december 31 1998 1997 1996 27 million 23 million 14 million respectively guarantees december 31 1998 company parental guarantees 486 million connection international development activities well 181 million related various projects company also letters credit approximately 80 million outstanding december 31 1998 rates regulatory matters july 1998 ferc issued notice proposed rulemaking nopr seeks comments wide range initiatives change manner shortterm less one year transportation markets regulated among things nopr proposes following removing price cap shortterm capacity market ii establishing procedures make pipeline shipperowned capacity comparable iii auctioning available shortterm pipeline capacity daily basis pipeline unable set reserve price variable costs iv changing policies pipeline penalties nomination procedures services v increasing pipeline reporting requirements vi permitting negotiation terms conditions service vii potentially modifying procedures certificating new pipeline construction also july 1998 ferc issued notice inquiry noi seeking comments fercs policy pricing longterm capacity comments nopr noi due april 1999 unclear action ferc take connection nopr noi comments received response tgp february 1997 tgp filed settlement ferc issues related recovery gsr transition costs related proceedings gsr stipulation agreement april 1997 ferc approved settlement terms gsr stipulation agreement tgp entitled collect 770 million customers 693 million demand surcharge 77 million interruptible transportation surcharge december 31 1998 demand portion fully collected 41 million interruptible transportation portion collected time limit collection interruptible transportation surcharge portion terms gsr stipulation agreement also provide rate case moratorium november 2000 subject certain limited exceptions escalating rate cap indexed inflation october 2005 certain tgps customers terms gsr stipulation agreement tgp required refund customers amounts collected excess customers share transition costs december 1994 tgp filed general rate increase ferc october 1996 ferc approved settlement resolving proceeding settlement included structural rate design change results larger portion tgps transportation revenues dependent upon throughput stipulation tgps refund obligation approximately 185 million inclusive interest 161 million refunded customers march 1997 june 1997 remaining 24 million refund obligation offset gsr recoveries accordance particular customer elections tgp provided reserve rate refunds revenues collected one party competitor tgp filed petition review ferc orders court appeals court appeals remanded case ferc respond competitors argument tgps cost allocation methodology deterred development market centers centralized locations buyers sellers physically exchange gas fercs request comments filed january 1999 cost service issues related tgps 1991 general rate proceeding resolved pursuant settlement agreement approved ferc order become final however cost allocation rate design issues remained unresolved july 1996 following aljs decision cost design issues ferc ruled certain issues remanded alj issue proper allocation tgps new england lateral costs july 1997 ferc issued order denying rehearing july 1996 order clarifying among things although ultimate resolution proper allocation costs would applied retroactively july 1 1995 cost service settlement allow tgp recover customers amounts tgp may ultimately required refund february 1999 petitions review july 1996 july 1997 ferc orders denied court appeals remand proceeding alj issued decision proper allocation new england lateral costs december 1997 decision adopts methodology economically approximates one currently used tgp october 1998 ferc issued order affirming aljs decision certain parties requested rehearing order matter currently pending ferc tgp filed cash reports period september 1993 august 1998 tgps filings showed cumulative loss august 1998 3 million tgp reached settlement principle customers resolve outstanding ferc proceedings related filed cash reports well accounting customer imbalances challenged tgps customers upon fercs approval settlement provide new mechanism accounting tgps cash program substantially revenues tgp generated longterm gas transmission contracts representing approximately 70 percent tgps firm transportation capacity expiring next two years principally november 2000 although tgp cannot predict much capacity resubscribed majority expiring contracts cover service northeastern markets currently little excess capacity several projects however proposed deliver incremental volumes markets although tgp actively pursuing renegotiation extension andor replacement contracts assurance whether tgp able extend replace contracts substantial portion thereof terms renegotiated contracts favorable tgp existing contracts epng june 1995 epng filed ferc approval new system rates mainline transportation effective january 1 1996 march 1996 epng filed comprehensive offer settlement resolve proceeding well issues surrounding certain contract reductions expirations occur january 1 1996 december 31 1997 april 1997 ferc approved epngs settlement filed determined contesting party edison severed separate determination rates ultimately pays epng july 1997 ferc issued order denying requests rehearing april 1997 order settlement implemented effective july 1 1997 hearings determine edisons rates completed may 1998 initial decision issued presiding alj july 1998 epng edison filed exceptions decision ferc aljs decision affirmed ferc epng believes resulting rates edison would significant refunds excess amounts reserved would required pending final outcome edison continues pay originally filed rates subject refund epng continues provide reserve potential refunds edison filed court appeals petition review fercs april 1997 july 1997 orders challenged propriety fercs approving settlement edisons objections settlement customer socal december 1998 court appeals issued decision vacating remanding fercs order epng file motion ferc proposing procedures address deficiencies court appeals found fercs earlier orders epng cannot predict outcome certainty believes ferc ultimately approve settlement rate settlement establishes among things base rates december 31 2005 rates escalate annually beginning 1998 addition settlement provides settling customers pay 295 million including interest risk sharing obligation approximates 35 percent anticipated revenue shortfalls 8 year period resulting contract reductions expirations referred ii receive 35 percent additional revenues received epng threshold eightyear period iii base rates increase decrease certain changes laws regulations result increased decreased costs excess 10 million year accordance terms rate settlement epngs refund obligation including interest approximately 194 million epng refunded 61 million customers august 1997 accordance certain customers elections remaining 133 million refund obligation applied towards 295 million risk sharing obligation december 31 1998 additional 94 million risk sharing obligation paid remaining 68 million balance including interest collected end 2003 1996 december 31 1998 69 million risk sharing obligation recognized revenue remaining unearned risk sharing amounts totaling 226 million excluding interest recognized ratably year 2003 addition arrangements offset effects reduction firm capacity commitments referred epng entered three contracts dynegy sale substantially turned back firm capacity available california january 1 1998 approximately 13 bcf twoyear period beginning january 1 1998 rates negotiated pursuant epngs tariff provisions ferc policies epng realized 29 million revenue 1998 anticipates realizing least 41 million revenues 1999 subject revenue sharing provisions rate settlement capacity contracts transportorpay provision requiring dynegy pay minimum charge equal reservation component contractual charge least 50 percent contracted volumes month 1998 least 72 percent contracted volumes month 1999 third quarter 1999 epng intends remarket capacity pursuant epngs tariff provisions ferc regulations subject dynegys right first refusal december 1997 epng filed implement several negotiated rate contracts including dynegy protest filing three shippers producersmarketers requested ferc require epng eliminate certain provisions dynegy contracts publicly disclose repost contracts competitive bidding suspend effectiveness order issued january 1998 ferc rejected several arguments made protest allowed contracts become effective january 1 1998 subject refund outcome technical conference held march 1998 june 1998 ferc issued order rejecting protests dynegy contracts required epng file modifications ferc contracts clarifying credits reservation reduction mechanism recall rights certain capacity addition epng agreed separately post capacity covered dynegy contracts becomes available future several parties protested epngs compliance filing andor requested rehearing fercs june 1998 order june 1998 epng filed letter agreement compliance june 1998 ferc order september 1998 ferc issued order accepting letter agreement subject epng making additional modifications additional modifications letter agreement required clarification credits available dynegy reservation reduction mechanism recall rights certain capacity october 1998 epng filed revised letter agreement ferc requested rehearing september 1998 order revenue sharing provisions rate case settlement epng obligated return approximately 12 million nontraditional revenues certain customers approximately 5 million credited customers transportation invoices december 31 1998 balance 7 million credited ratably january february march 1999 december 31 1998 epng reserve 7 million ferc procedures takeorpay cost recovery filings may challenged pipeline customers prudence certain grounds certain parties sought review court appeals fercs determination october 1992 order certain buydownbuyout costs eligible recovery january 1996 court appeals remanded order ferc direction clarify basis decision takeorpay buydownbuyout costs eligible recovery march 1997 following technical conference submission statements position replies ferc issued order determining costs related one epngs disputed contracts eligible recovery costs ruled ineligible recovery totaled approximately 3 million including interest refunded customers second quarter 1997 october 1997 ferc issued order denying challenging parties request rehearing march 1997 order respects determined costs incurred pursuant two additional epng contracts ineligible recovery costs including interest totaled approximately 9 million refunded customers february 1998 challenging parties claim epng required refund additional 31 million filed petition review ferc order court appeals february 1999 court appeals affirmed fercs october 1997 order november 1996 gpm corporation filed complaint amended ferc alleging epngs south carlsbad compression facilities gathering facilities improperly functionalized epng transmission facilities accordance ferc orders south carlsbad compressor facilities transferred epfs april 1998 november 1997 order ferc reversed previous decision found epngs chaco station functionalized gathering transmission facility transferred epfs ferc denied requests rehearing epng two parties filed petitions review court appeals matter briefed argued september 1999 accordance ferc orders chaco station transferred epfs april 1998 ferc compliance audits tgp epng interstate pipelines subject ferc audits books records epng currently open audit covering years 1990 1995 ferc expected issue audit report 1999 epngs tgps property retirements currently review ferc audit staff management believes ultimate resolution aforementioned rate regulatory matters various stages finalization material adverse effect companys financial position results operations cash flows legal proceedings november 1993 transamerican filed complaint texas state court transamerican natural gas corporation v el paso natural gas company et al alleging fraud tortious interference contractual relationships negligent misrepresentation economic duress civil conspiracy violation state antitrust laws arising settlement agreement entered epng transamerican natural gas corporation transamerican others 1990 settle litigation pending potential claims complaint amended seeks actual damages 15 billion exemplary damages 6 billion epng defending matter state district court dallas county texas april 1996 former employee transamerican filed related case harris county texas vickroy e stone v godwin carlton pc et al including epng seeking indemnification damages unspecified amounts relating litigation consulting work allegedly performed various entities including epng cases involving transamerican epng filed motion summary judgment transamerican case arguing plaintiffs claims barred prior release executed transamerican statutes limitations final court judgment ending original litigation 1990 following hearing january 1998 court granted summary judgment epngs favor transamericans claims based economic duress negligent misrepresentation denied motion remaining claims february 1998 epng filed motion summary judgment stone litigation arguing claims baseless barred statutes limitations subject executed releases assigned transamerican june 1998 court granted epngs motion entirety dismissed remaining claims stone litigation august 1998 court denied stones motion new trial seeking reconsideration ruling stone appealed courts ruling texas court appeals houston texas transamerican trial set commence september 1999 based information available time management believes claims asserted cases factual legal basis ultimate resolution matters material adverse effect companys financial position results operations cash flows february 1998 united states state texas filed united states district court comprehensive environmental response compensation liability act cost recovery action united states v atlantic richfield co et al fourteen companies including following affiliates epec tgp eptpc epec corporation epec polymers inc dissolved petrotex chemical corporation relating sikes disposal pits superfund site sikes located harris county texas sikes unpermitted waste disposal site 1960s accepted waste hauled numerous houston ship channel industries suit alleges former tenneco chemicals inc petrotex chemical corporation arranged disposal hazardous substances sikes tgp eptpc epec corporation epec polymers inc alleged derivatively liable successors parent corporations suit claims united states state texas expended 125 million remediating site seeks recover amount plus interest companies named defendants include atlantic richfield company crown central petroleum corporation occidental chemical corporation exxon corporation goodyear tire rubber company rohm haas company shell oil company vacuum tanks inc defendants filed answers thirdparty complaints seeking contribution twelve entities believed prps sikes although factual investigation relating sikes preliminary stages company believes amount material disposed sikes tenneco chemicals inc petrotex chemical corporation facilities small possibly de minimis however government plaintiffs alleged defendants jointly severally liable entire remediation costs also sought declaration liability future response costs groundwater monitoring outcome matter cannot predicted certainty management expect matter material adverse effect companys financial position results operations cash flows tgp party proceedings involving federal state authorities regarding past use tgp lubricant containing pcbs starting air systems tgp executed consent order epa governing remediation certain compressor stations working relevant states regarding remediation activities tgp also working pennsylvania new york environmental agencies specify remediation requirements pennsylvania new york stations remediation activities pennsylvania complete exception longterm groundwater monitoring requirements remediation characterization work compressor stations consent order epa jurisdiction new york department environmental conservation ongoing management believes ultimate resolution matters material adverse effect companys financial position results operations cash flows november 1988 kentucky environmental agency filed complaint kentucky state court commonwealth kentucky natural resources environmental protection cabinet v tennessee gas pipeline company alleging tgp discharged pollutants waters state without permit disposed pcbs without permit agency sought injunction future discharges sought order remediate remove pcbs sought civil penalty tgp entered agreed orders agency resolve many issues raised original allegations received water discharge permits kentucky compressor stations agency continues work resolve remaining issues relevant kentucky compressor stations scheduled characterized remediated consent order epa management believes resolution issue material adverse effect companys financial position results operations cash flows number subsidiaries epec wholly owned partially owned well leviathan named defendants united states ex rel grynberg v el paso natural gas company et al generally complaint motion alleges industrywide conspiracy underreport heating value well volumes natural gas produced federal indian lands thereby depriving us government royalties complaint remains sealed company believes complaint without merit company named defendant numerous lawsuits named party numerous governmental proceedings arising ordinary course business outcome lawsuits proceedings company cannot predicted certainty management currently expect matters material adverse effect companys financial position results operations cash flows environmental company subject extensive federal state local laws regulations governing environmental quality pollution control laws regulations require company remove remedy effect environment disposal release specified substances current former operating sites december 31 1998 company reserve approximately 255 million expected remediation costs associated onsite offsite groundwater technical studies approximately 239 million costs approximately 16 million company anticipates incurring 2027 addition company estimates subsidiaries make capital expenditures environmental matters approximately 6 million 1999 capital expenditures range approximately 60 million 85 million aggregate years 2000 2007 expenditures primarily relate compliance air regulations lesser extent control water discharges since 1988 tgp engaged internal project identify deal presence pcbs substances concern including substances epa list hazardous substances compressor stations facilities operated interstate intrastate natural gas pipeline systems conducting project tgp frequent contact federal state regulatory agencies informal negotiation formal entry consent orders assure efforts meet regulatory requirements may 1995 following negotiations customers tgp filed ferc separate stipulation agreement environmental stipulation establishes mechanism recovering substantial portion environmental costs identified internal project november 1995 ferc issued order approving environmental stipulation although one shipper filed rehearing ferc denied rehearing order february 1996 environmental stipulation effective july 1 1995 december 31 1998 balance 2 million remains collected stipulation company certain subsidiaries designated received notice could designated asked information determine whether could designated prp respect 30 sites comprehensive environmental response compensation liability act cercla superfund state equivalents company sought resolve liability prp respect superfund sites indemnification third parties andor settlements provide payment companys allocable share remediation costs december 31 1998 company estimated share remediation costs sites 62 million 75 million provided reserves believes adequate costs since cleanup costs estimates subject revision information becomes available extent remediation required cases company asserted defense liability companys estimate share remediation costs could change moreover liability federal superfund statute joint several meaning company could required pay excess pro rata share remediation costs companys understanding financial strength prps considered appropriate determination estimated liability described herein company presently believes costs associated current status entities prps superfund sites referenced material adverse effect companys financial position results operations cash flows company initiated proceedings historic liability insurers seeking payment reimbursement costs liabilities associated environmental matters proceedings company contends certain environmental costs liabilities associated various entities sites including costs associated former operating sites must paid reimbursed certain historic insurers proceedings discovery stage yet possible predict outcome possible new information future developments could require company reassess potential exposure related environmental matters company may incur significant costs liabilities order comply existing environmental laws regulations also possible developments increasingly strict environmental laws regulations enforcement policies thereunder claims damages property employees persons environment resulting current discontinued operations could result substantial costs liabilities future information becomes available developments occur related accrual amounts adjusted accordingly still uncertainties relating ultimate costs may incurred based upon companys evaluation experience date company believes recorded reserve adequate discussion specific environmental matters see legal proceedings acquisition ce generation llc march 1999 epps purchased 50 percent ownership interest ce generation llc equity investment ce generation llc approximately 260 million subject certain adjustments accounted equity method ce generation llc owns 12 power generation projects qualifying facilities public utility regulatory policy act two additional generating facilities currently construction southern california collectively 14 power projects combined electric generating capacity approximately 896 mw include ten geothermal projects near imperial valley southern california four natural gasfired cogeneration projects new york pennsylvania texas arizona ppn power project march 1999 company signed sale purchase agreement acquire 26 percent interest 295 million power plant tamil nadu india project consists 346 mw combined cycle power plant serve base load facility sell power stateowned tamil nadu electricity board thirtyyear power purchase agreement construction began january 1999 operations expected commence early 2001 transfer funds complete acquisition expected finalized end march 1999 acquisition deeptech august 1998 company completed acquisition deeptech merging deeptech subsidiary epec deeptechs assets included combined 273 percent ownership interest leviathan acquisition accounted purchase total purchase price net cash received approximately 422 million company recorded 214 million goodwill connection acquisition amortized using straightline method period 40 years amount allocated goodwill based excess total purchase price estimated fair value assets liabilities acquisition date amounts may adjusted final purchase price allocation management expect ultimate resolution purchase price allocation materially impact companys financial position results operations cash flows operating results deeptech included companys consolidated statements income beginning august 15 1998 year 2000 company established executive steering committee project team coordinate phases year 2000 project assure companys key automated systems related processes remain functional year 2000 phases awareness ii assessment iii remediation iv testing v implementation necessary modifications vi contingency planning previously included component companys implementation phase recognition importance year 2000 issues potential impact company initial phase year 2000 project involved establishment companywide awareness program awareness program directed executive steering committee project team includes participation senior management core business area awareness phase substantially completed although company continually update awareness efforts duration year 2000 project companys assessment phase consists conducting companywide inventory key automated systems related processes analyzing assigning levels criticality systems processes identifying prioritizing resource requirements developing validation strategies testing plans evaluating business partner relationships portion assessment phase related internally developed computer applications hardware equipment embedded chips substantially complete company estimates finished threefourths portion assessment determine nature impact year 2000 date change thirdpartydeveloped software assessment phase project among things involves efforts obtain representations assurances third parties including third party vendors hardware equipment products embedded chip systems software products used impacting company modified year 2000 compliant date responses third parties although generally encouraging inconclusive result company cannot predict potential consequences third parties products year 2000 compliant company currently evaluating exposure associated business partner relationships remediation phase involves converting modifying replacing eliminating key automated systems identified assessment phase testing phase involves validation identified key automated systems company utilizing test tools written test procedures document validate necessary unit system integration acceptance testing company estimates approximately onehalf work phases remains expects substantially completed mid1999 implementation phase involves placing converted replaced key automated systems operation cases phase also involve implementation contingency plans needed support business functions processes may interrupted year 2000 failures outside companys control company completed onefourth implementation phase expected substantially completed mid1999 contingency planning phase consists developing risk profile companys critical business processes providing actions company pursue keep processes operational event year 2000 disruptions focus contingency planning prompt response year 2000 events plan subsequent resumption normal operations plan expected assess risk significant failure critical processes performed company address mitigation risks plan also consider significant failures related reasonably likely worst case scenario discussed may occur addition plan expected factor severity duration impact significant failure company plans contingency plan completed mid1999 year 2000 contingency plan continue modified adjusted throughout year additional information becomes available goal year 2000 project ensure critical systems processes companys direct control remain functional certain systems processes may interrelated dependent upon systems outside companys control however systems within companys control may unpredicted problems accordingly assurance significant disruptions avoided companys present analysis reasonably likely worst case scenario year 2000 disruptions includes year 2000 failures telecommunications electricity industries well interruptions suppliers might cause disruptions companys operations thus causing temporary financial losses inability deliver products services customers virtually natural gas transported companys interstate pipelines owned third parties accordingly failures natural gas producers ready year 2000 could significantly disrupt flow product companys customers many cases producers direct contractual relationship company relies customers verify year 2000 readiness producers purchase natural gas since companys revenues delivery natural gas based upon fees paid customers reservation capacity based upon volume actual deliveries short term disruptions deliveries caused factors beyond companys control significant financial impact company although could cause operational problems companys customers longerterm disruptions however could materially impact companys results operations financial condition cash flows company owns controls domestic facilities projects nearly companys international investments made conjunction unrelated third parties many cases operators international facilities sole direct control company consequence year 2000 programs instituted international facilities may different year 2000 program implemented company domestically party responsible results program may direct indirect control company addition noncontrolled programs may provide degree communication documentation coordination company achieves domestic year 2000 program moreover regulatory legal environment international facilities operate makes analysis possible disruption associated financial impact difficult many foreign countries appear substantially behind united states addressing potential year 2000 disruption critical infrastructure developing framework governing reporting requirements relative liabilities business entities accordingly year 2000 risks posed international operations whole different presented domestically part year 2000 effort company assessing differences noncontrolled programs domestic year 2000 project formulated instituted program identifying risks preparing response risks company believes international facilities significant investments addressing year 2000 issues adequate manner possible may experience significant year 2000 disruption aggregate effect problems experienced multiple international locations may material adverse company intends incorporate possibility relevant contingency plans total cost companys year 2000 project still evaluated company estimates costs incurred 1999 2000 associated assessing remediating testing internally developed computer applications hardware equipment embedded chip systems thirdpartydeveloped software 14 million 26 million estimated costs company expects 6 million 14 million capitalized remainder expensed december 31 1998 company incurred expenses approximately 6 million company previously traced incremental expenses related year 2000 project means costs year 2000 project related salaried employees company including direct salaries benefits available included estimated costs project since earlier phases project mostly involved work performed salaried employees costs expended date reflect percentage completion project company anticipates expend costs reported remediation implementation contingency planning phases project possible company may need reassess estimate year 2000 costs event company completes acquisition makes material investment substantial facilities another business entity although company expect costs year 2000 project material adverse effect financial position results operations cash flows based information available time company cannot conclude disruption caused internal external year 2000 related failures effect specific factors might affect success companys year 2000 efforts occurrence year 2000 disruption expense include failure company outside consultants properly identify deficient systems failure selected remedial action adequately address deficiencies failure companys outside consultants complete remediation timely manner due shortages qualified labor factors unforeseen expenses related remediation existing systems transition replacement systems failure third parties become year 2000 compliant adequately notify company potential noncompliance effects significant disruption international facilities company significant investments disclosure year 2000 readiness disclosure made intention comply fully year 2000 information readiness disclosure act 1998 pub l 105271 112 stat 2386 signed law october 19 1998 statements made herein shall construed within confines act extent reader year 2000 readiness disclosure investor potential investor companys affiliates equity debt securities disclosure made sole purpose communicating disclosing information aimed correcting helping correct andor avoid year 2000 failures employee separation asset impairment charge first quarter 1996 company adopted program reduce operating costs work force reductions improved work processes adopted sfas 121 accounting impairment longlived assets longlived assets disposed result workforce reduction program adoption sfas 121 company recorded special charge 99 million 47 million employee separation costs 52 million asset impairments first quarter 1996 discussion see item 8 financial statements supplementary data note 11 management aware commitments contingent liabilities would materially adverse effect companys financial condition results operations cash flows new accounting pronouncements yet adopted accounting costs computer software developed obtained internal use march 1998 american institute certified public accountants issued statement position 981 accounting costs computer software developed obtained internal use statement provides guidance accounting costs also defines internaluse computer software statement effective fiscal years beginning december 15 1998 application pronouncement material impact companys financial position results operations cash flows reporting costs startup activities april 1998 american institute certified public accountants issued statement position 985 reporting costs startup activities statement defines startup activities requires startup organization costs expensed incurred addition requires cost exists balance sheet expensed upon adoption pronouncement statement effective fiscal years beginning december 15 1998 company adopt pronouncement effective january 1 1999 expects report charge range 7 million 12 million net income taxes first quarter 1999 cumulative effect change accounting principle accounting derivative instruments hedging activities june 1998 sfas 133 accounting derivative instruments hedging activities issued financial accounting standards board establish accounting reporting standards derivative instruments including certain derivative instruments embedded contracts hedging activities sfas 133 requires entity classify derivatives either assets liabilities statement financial position measure instruments fair value certain conditions met derivative may specifically designated hedge exposure changes fair value recognized asset liability unrecognized firm commitment ii hedge exposure variable cash flows forecasted transaction iii hedge foreign currency exposure net investment foreign operation unrecognized firm commitment availableforsale security foreigncurrencydenominated forecasted transaction accounting changes fair value derivative depends intended use derivative resulting designation standard effective quarters fiscal years beginning june 15 1999 company currently evaluating effects pronouncement disclosure relating euro conversion july 1998 securities exchange commission issued staff legal bulletin 6 provide guidance disclosure related euro conversion guidance primarily focuses disclosure managements discussion analysis financial condition results operations well description business company currently investments countries affected euro conversion accounting contracts involved energy trading risk management activities november 1998 emerging issues task force reached consensus eitf 9810 accounting contracts involved energy trading risk management activities eitf 9810 requires energy trading contracts recorded fair value balance sheet changes fair value included earnings eitf 9810 effective fiscal years beginning december 15 1998 company adopted provisions eitf 9810 january 1999 application pronouncement material impact companys financial position results operations cash flows risk factors cautionary statement purposes safe harbor provisions private securities litigation reform act 1995 report contains incorporates reference forwardlooking statements within meaning private securities litigation reform act 1995 forwardlooking statement includes statement assumptions bases underlying forwardlooking statement caution assumptions bases believed reasonable made good faith assumed facts bases almost always vary actual results differences assumed facts bases actual results material depending upon circumstances forwardlooking statement management express expectation belief future results expectation belief expressed good faith believed reasonable basis assurance statement expectation belief result achieved accomplished words believe expect estimate anticipate similar expressions may identify forwardlooking statements mind consider following important factors could cause actual results differ materially expressed forwardlooking statement made us behalf industry highly competitive hydrocarbons transport gather process store owned third parties result volume hydrocarbons involved activities dependent upon actions third parties beyond control ability maintain increase current transmission gathering processing sales volumes remarket unsubscribed capacity subject impact following future weather conditions including favor hydroelectric generation alternative energy sources price competition drilling activity supply availability expiration dynegy contracts end 1999 service competition especially due current excess pipeline capacity california future profitability may affected ability compete services offered energy enterprises may larger offer services possess greater resources seventy percent tgps contracts expiring next two years principally november 2000 ability negotiate new contracts renegotiate existing contracts could adversely affected factors cannot control including proposed construction companies additional pipeline capacity markets served tgp reduced demand due higher gas prices availability alternative energy sources viability expansion projects discussion see item 1 business natural gas transmission markets competition fluctuations natural gas natural gas liquids prices could adversely affect business ability compete transporters impacted natural gas prices supply basins connected pipeline systems compared prices gas producing regions especially canada revenues generated gathering processing contracts dependent upon volumes rates affected prices natural gas natural gas liquids success expanding gathering processing operations offshore gulf mexico subject continued development additional oil gas reserves vicinity facilities ability access additional reserves offset natural decline existing wells connected systems decline energy prices could precipitate decrease development activities could cause decrease volume reserves available gathering processing offshore facilities fluctuations energy prices may impact gathering rates investments third parties development new oil gas reserves connected gathering processing facilities caused number factors including regional domestic international supply demand availability adequacy transportation facilities energy legislation federal state taxes sale transportation natural gas natural gas liquids price abundance supplies alternative energy sources reductions average volume natural gas transport gather process prolonged period results operations financial position could materially adversely affected use derivative financial instruments could result financial losses nonregulated subsidiaries engaged gathering processing marketing natural gas energy commodities utilize futures option contracts traded new york mercantile exchange overthecounter options price basis swaps gas merchants financial institutions instruments intended reduce exposure shortterm volatility changes commodities prices could however incur financial losses future result volatility market values underlying commodities one counterparties fails perform contract additional information concerning derivative financial instruments see item 7a quantitative qualitative disclosures market risks item 8 financial statements supplementary data note 5 attractive acquisition investment opportunities may available ability grow depend part upon ability identify complete attractive acquisition investment opportunities growth acquisitions investments joint ventures future operating results success acquisitions joint ventures within outside us may subject effects changes following us foreign trade monetary policies laws regulations political economic developments inflation rates taxes operating conditions foreign investments involve special risks activities areas outside us subject risks inherent foreign operations including loss revenue property equipment result hazards expropriation nationalization wars insurrection political risks effects currency fluctuations exchange controls recent devaluation indonesian brazilian currencies economic problems legal regulatory events unforeseeable obstacles may beyond control ability manage could incur substantial environmental liabilities may incur significant costs liabilities order comply existing environmental laws regulations also possible developments increasingly strict environmental laws regulations enforcement policies thereunder claims damages property employees persons environment resulting current discontinued operations could result substantial costs liabilities future additional information concerning companys environmental matters see section item entitled environmental activities involve operating hazards uninsured risks maintain insurance certain risks normally associated transportation gathering processing natural gas including explosions pollution fires occurrence significant event fully insured could material adverse effect business remain potential liabilities related acquisition eptpc amount actual contingent liabilities eptpc remained liabilities epng acquired eptpc could vary materially amount estimated based upon assumptions could prove inaccurate new tenneco newport news shipbuilding inc unable unwilling pay respective liabilities court could require us certain legal theories may applicable situation assume responsibility obligations required assume obligations could material adverse effect financial condition results operations cash flows remain potential federal income tax liabilities related acquisition eptpc connection acquisition eptpc distributions made eptpc prior acquisition irs issued private letter ruling old tenneco ruled us federal income tax purposes distributions would taxfree old tenneco except extent cash received lieu fractional shares existing stockholders merger would constitute taxfree reorganization certain transactions effected connection merger distribution would taxfree distributions qualify taxfree distributions corporate level federal income tax would assessed consolidated group old tenneco common parent corporate level federal income tax would payable eptpc certain limited circumstances however new tenneco newport news shipbuilding inc agreed indemnify eptpc defined portion tax liabilities subject financing interest rate exposure risks business operating results adversely affected factors availability cost capital changes interest rates changes tax rates due new tax laws market perceptions natural gas industry epec credit ratings subject risks associated year 2000 issues taking steps mitigate adverse effects year 2000 date change customers business operations including assessment remediation testing applications hardware software implementation necessary change nevertheless failure thirdparties deal achieve year 2000 compliance may adversely affect business additional information year 2000 strategy specific factors may affect ability achieve year 2000 compliance see section item entitled year 2000 item 7aitem 7 managements discussion analysis financial condition results operations general past five years companys business activities operations changed dramatically result significant acquisitions transactions designed enhance companys ability compete effectively global energy industry changes significantly expanded companys operating scope ability generate operating cash flows needs cash investment opportunities consequently company substantially expanded credit facilities created financing structures facilities meet needs period companys business activities segregated five segments natural gas transmission merchant energy international field services production structure reflects companys operating segments following merger sonat historical periods presented basis current segment presentation companys segments strategic business units offer variety different energy products services company manages segments separately requires different technology marketing strategies certain business segments earnings largely derived earnings equity investments accordingly company evaluates segment performance based ebit merger coastal corporation january 2000 company announced entered definitive agreement merge coastal merger share coastal common stock class common stock converted taxfree basis 123 shares company common stock coastals outstanding convertible preferred stock exchanged company common stock basis preferred stock converted coastal common stock immediately prior merger total value transaction approximately 16 billion including 6 billion assumed debt preferred equity accounted pooling interests expected close fourth quarter 2000 company coastal complete merger number conditions satisfied waived including coastal stockholders approve adopt merger agreement company stockholders approve issuance shares el paso common stock connection merger law court order prohibits transaction relevant waiting periods federal antitrust laws applicable merger expire terminate regulatory approvals including approval ferc received without conditions would material adverse effect financial condition results operations cash flow companys coastals combined businesses companys coastals independent public accountants concur merger qualify pooling interest accounting treatment attorneys company coastal issue opinions merger expected taxfree however cannot assurance company coastal complete merger even conditions satisfied coastal diversified energy holding company engaged subsidiaries joint ventures natural gas transmission storage gathering processing marketing natural gas oil exploration production petroleum refining marketing distribution chemicals power production coal coastal owns interests approximately 18000 miles natural gas pipelines extending across midwestern rocky mountain areas united states proved reserves 36 tcfe coastal also international domestic interests natural gas oil producing properties power production plants crude oil refining facilities purchase texas midstream operations january 2000 company entered agreement purchase natural gas natural gas liquids businesses pge gas transmission texas corporation pge gas transmission teco inc total value transaction 840 million including face amount assumed debt approximately 561 million acquisition expected close midyear 2000 subject receipt certain required governmental approvals third party consents transaction accounted purchase included field services assets acquired consist 8500 miles intrastate natural gas transmission pipelines transport approximately 28 bcfd south texas area nine natural gas processing plants currently process 15 bcfd 72 bcf natural gas storage field transaction also includes significant natural gas liquids pipelines fractionation facilities merger sonat inc october 25 1999 company completed merger sonat merger company issued one share el paso common stock share sonat common stock total shares issued approximately 110 million shares company also assumed approximately 23 billion sonat debt result merger company incurred total approximately 515 million merger related costs merger related asset impairment charges first quarter 2000 company complete sales east tennessee natural gas company sea robin pipeline company well onethird interest destin pipeline company comply federal trade commission order related merger sonat proceeds sales expected approximately 618 million company treat expected gain arising sales extraordinary item reflecting expected gain company believes future impact dispositions individually aggregate material effect companys overall financial position results operations cash flows company accounted merger pooling interests accordingly information herein restated though transaction occurred beginning earliest period presented holding company reorganization taxfree internal reorganization effective august 1 1998 company reorganized holding company organizational structure whereby el paso became parent holding company see item 8 financial statements supplementary data note 1 discussion holding company reorganization december 31 1998 1999 following merger sonat company completed taxfree internal reorganization assets operations certain subsidiaries reorganizations number subsidiaries transferred el paso andor entities owned el paso neither creation holding company structure taxfree internal reorganizations impact overall segment presentations herein results operations extent possible results operations reclassified conform current business segment presentation although results necessarily indicative results would achieved revised business segment structure effect periods operating revenues expenses segment include intersegment sales expenses eliminated consolidation company believes gross margin revenue less cost sales rather operating revenue provides accurate indicator merchant energy field services segments discussion individual segments see item 8 financial statements supplementary data note 16 three year period ended december 31 1999 company incurred significant charges related companys 1999 merger sonat along certain asset impairment charges costs associated 1998 acquisition zilkha energy writedowns capitalized costs natural gas oil properties full cost method accounting charges impacted companys operating units period similar costs anticipated future company makes integrates future acquisitions andor enters significant transactions shape impact business strategy operations table provides summary charges three years ended december 31 1999 business segment total following table presents ebit segment total three years ended december 31 1999 including charges discussed ebit year variances discussed segment results natural gas transmission year ended december 31 1999 compared year ended december 31 1998 operating revenues year ended december 31 1999 7 million higher 1998 increase due favorable resolution certain regulatory issues 1999 tgp system related new england rates coupled downward revision 1998 amount recoverable interest tgps gsr costs also contributing increase higher revenues epng system increased longterm transportation sale capacity dynegy increase firm transportation revenues sng system associated expansion projects increases partially offset lower system throughput tgp system 1999 favorable resolution 1998 contested rate matter mpc system related rate methodology higher nontransportation revenues 1998 sng system decrease transportation revenues due lower throughput sea robin system 1999 operating expenses year ended december 31 1999 92 million higher 1998 increase primarily due mergerrelated charges resulting el pasosonat merger including severance termination charges impact conforming accounting policies practices within transmission segment impairment charges redundant assets inventory also contributing increase reserves established 1999 lower anticipated recoveries sngs north alabama palmetto pipeline projects higher general administrative costs companys systems higher depreciation expansion projects completed sng effect epngs regulatory settlement edison partially offsetting increases favorable resolution tgps customer imbalance mechanism revised estimates rate recoveries items included epngs cost service lower fuel costs associated lower throughput 1999 tgp epng systems income year ended december 31 1999 7 million lower 1998 decrease primarily due lower equity earnings destin 1999 partially offset increase 1999 interest income destinrelated debt issuance latter part 1998 year ended december 31 1998 compared year ended december 31 1997 operating revenues year ended december 31 1998 77 million lower 1997 primarily due lower revenues epng system expiration pacific gas electric company contract effective december 31 1997 also contributing decrease lower throughput tgp system warmer average temperatures northeastern midwestern markets downward revision 1998 tgps recoverable interest gsr costs decreases significantly offset epngs risk sharing revenue revenues sale capacity dynegy favorable resolution contested rate matter mpc system operating expenses year ended december 31 1998 68 million lower 1997 primarily due lower system fuel usage tgp associated operating efficiencies attained result lower throughput reduced general administrative expenses tgp largely due lower payroll costs well lower compensation employee benefits costs sng decreases partially offset recovery receivable previously deemed uncollectible 1997 income year ended december 31 1998 12 million higher 1997 primarily due interest component favorable sales use tax settlement gains sale assets inclusion sngs share earnings destin destins earnings increase result higher allowance funds used construction capitalized 1998 compared 1997 levels merchant energy year ended december 31 1999 compared year ended december 31 1998 total gross margin year ended december 31 1999 57 million higher 1998 increase natural gas margin primarily due higher income recognition longterm natural gas transactions contracts completed 1999 partially offset decline value marktomarket positions resulting termination certain contracts 1999 increase power margin due management fee income earned 1999 merchant energys electron project revenues consolidated power generation facilities acquired december 1998 increases partially offset decrease power trading margins 1999 operating expenses year ended december 31 1999 112 million higher 1998 due higher operating costs associated increase power activities operating expenses consolidated power facilities acquired december 1998 increases mergerrelated charges including integrating accounting policies practices decline value certain marktomarket positions write certain capitalized project costs abandoned projects also contributing increase higher amortization goodwill resulting change estimated useful life goodwill related companys 1995 acquisitions premier gas company eastex energy inc income year ended december 31 1999 2 million higher 1998 primarily due march 1999 acquisition 50 percent interest ce generation llc partially offset lower earnings equity investments gains 1998 sales several assets also offsetting increases lower losses assumed 1999 agl resources inc agl ownership interest sonats merchant energy operations year ended december 31 1998 compared year ended december 31 1997 total gross margin year ended december 31 1998 5 million higher 1997 higher power margins result increased trading activity power price volatility coupled reduced losses trading activity energy commodities offset lower natural gas margins revised estimate natural gas imbalances reduced revenues channel pipeline company transferred field services 1998 operating expenses year end december 31 1998 7 million lower 1997 due 1997 restructuring merchant energy organization following eptpc acquisition transfer channel pipeline company operations field services decrease partially offset increase sonat energy services operating costs due expansion scope business income year ended december 31 1998 12 million higher 1997 primarily due higher losses assumed agl ownership interest sonats merchant energy operations along sale creole pipeline portion merchant energys equity interest berkshire 1998 international year ended december 31 1999 compared year ended december 31 1998 operating revenues year ended december 31 1999 15 million higher 1998 primarily due increase revenues rio negro project consolidated third quarter 1999 coupled higher revenues manaus power project partially offset decrease ema power revenues operating expenses year ended december 31 1999 20 million higher 1998 primarily due higher operating expenses consolidated projects including increased payroll outside services insurance supplies depreciation amortization increases partially offset lower project development costs 1999 income year ended december 31 1999 25 million higher 1998 due interest income earned notes receivable higher earnings equity investments equity swap gains recognized 1999 internationals capsa project increases partially offset certain 1998 gains projectrelated activities gain sale surplus power equipment year ended december 31 1998 compared year ended december 31 1997 operating revenues year ended december 31 1998 45 million higher 1997 due consolidation financial reporting purposes manaus power project may 1998 acquiring additional ownership interest increase revenue attributable ema power project company began reporting consolidated basis july 1997 operating expenses year ended december 31 1998 48 million higher 1997 primarily due costs related consolidation ema power manaus power projects increased general administrative expenses largely due higher project development costs reflecting increase projectrelated activities 1998 income year ended december 31 1998 26 million higher 1997 primarily due increased equity earnings gain sale surplus power equipment recognition certain gains projectrelated activities internationals projects move development stage operational stage common recognize onetime gains fees may include management fees development fees financing fees gains selldown ownership interests company anticipates additional onetime events may result recognition income expense future field services year ended december 31 1999 compared year ended december 31 1998 total gross margin year ended december 31 1999 11 million higher 1998 increase gathering treating margin primarily due higher volumes average gathering rates san juan basin partially offset elimination margins assets anadarko basin sold september 1998 decrease processing margin resulted lower volumes realized liquids prices 1999 compared 1998 sale several processing plants second quarter 1999 increase margin resulted acquisition encap march 1999 operating expenses year ended december 31 1999 30 million higher 1998 primarily due higher operating expenses related acquisition encap higher shared services allocations write certain gathering assets held sale following companys merger sonat increase amortization depreciation expense attributable acquisitions income year ended december 31 1999 35 million higher 1998 due increase earnings equity investments primarily increase earnings el paso energy partners partially offset decrease equity earnings viosca knoll sold second quarter 1999 increase also attributable net gain sale several assets primarily viosca knoll second quarter 1999 year ended december 31 1998 compared year ended december 31 1997 total gross margin year ended december 31 1998 23 million higher 1997 increase gathering treating margin primarily resulted higher gathering rates compared 1997 increase gathering treating volumes largely attributable acquisition texas gulf coast subsidiaries pacificorp tpc december 1997 inclusion results operations channel pipeline company field services beginning january 1998 versus merchant energy 1997 decrease processing margin largely attributable lower liquids prices 1998 compared period 1997 operating expenses year ended december 31 1998 28 million higher 1997 primarily result additional expenses associated addition channel pipeline company tpc well higher general administrative expenses income year ended december 31 1998 6 million higher 1997 primarily due higher earnings equity investments production year ended december 31 1999 compared year ended december 31 1998 total operating revenues year ended december 31 1999 62 million lower 1998 decrease natural gas oil condensates liquids revenues primarily due property dispositions 1998 partially offset increase realized prices 1999 increase revenues resulted favorable contractual settlement 1999 operating expenses year ended december 31 1999 743 million lower 1998 primarily due lower full cost ceiling test charges 1999 versus charges incurred 1998 along lower production levels 1999 also contributing decrease lower operating maintenance expenses due property dispositions 1998 efficiencies created 1998 reorganization production decreases partially offset el pasosonat mergerrelated costs including costs retain seismic data licenses consolidate offices writedown inventory income year ended december 31 1999 2 million lower 1998 due primarily net gain sale nonoperating assets third quarter 1998 year ended december 31 1998 compared year ended december 31 1997 total operating revenues year ended december 31 1998 221 million lower 1997 decrease natural gas revenues primarily resulted overall decline production volumes realized prices 1998 compared period 1997 decrease oil condensate liquids revenues largely attributable lower realized oil condensate prices operating expenses year ended december 31 1998 896 million higher 1997 result ceiling test charges incurred 1998 along restructuring charges connection productions 1998 reorganization operations partially offsetting increases 1997 charges related acquisition zilkha energy company lower 1998 depletion resulting decreased natural gas production reduced operating administrative costs following productions 1998 restructuring future quarterly full cost ceiling tests based thencurrent prices natural gas oil net carrying value companys natural gas oil properties reduced due full cost ceiling limitation present value companys proved natural gas oil reserves discounted 10 percent exceed companys net natural gas oil properties recorded balance sheet risk future property writedowns due factors negatively affect estimated present value proved natural gas oil reserves including volatile natural gas oil prices downward revisions estimated proved natural gas oil quantities unsuccessful exploratory operations see item 8 financial statements supplementary data note 4 corporate expenses net year ended december 31 1999 compared year ended december 31 1998 net corporate expenses year ended december 31 1999 327 million higher 1998 primarily due charges 1999 related merger sonat including accelerated amortization certain employee benefits legal accounting financial advisory costs termination retention severance costs incremental costs incurred combining office facilities following merger increase partially offset start costs assumed 1998 companys power services activities higher recurring equity compensation charges 1998 year ended december 31 1998 compared year ended december 31 1997 net corporate expenses year ended december 31 1998 7 million lower 1997 decrease resulted lower benefits costs nonrecurring gains partially offset administrative costs associated formation startup companys power services activities established first quarter 1998 increased costs associated companys year 2000 project interest debt expense year ended december 31 1999 compared year ended december 31 1998 interest debt expense year ended december 31 1999 66 million higher 1998 primarily due increased borrowings el paso 18 billion fund capital expenditures acquisitions investing activities offset higher capitalized interest 1999 higher project investments development primarily production merchant energy year ended december 31 1998 compared year ended december 31 1997 interest debt expense year ended december 31 1998 43 million higher 1997 primarily due increased borrowings fund capital expenditures acquisitions investing activities higher average effective interest rate 1998 generally resulting higher rates associated march 1997 issuance tgp longterm debt approximately 883 million increases partially offset higher interest expense 1997 rate refunds due epngs customers income tax expense year ended december 31 1999 compared year ended december 31 1998 income tax benefits 81 million 1999 170 million 1998 resulted effective tax rates 27 percent 38 percent respectively lower rate 1999 primarily due mergerrelated costs incurred 1999 offset exclusions portion earnings certain unconsolidated equity investees dividend received deduction anticipated earnings distributed year ended december 31 1998 compared year ended december 31 1997 income tax benefit 170 million 1998 income tax expense 234 million 1997 resulted effective tax rates 38 percent 35 percent respectively higher rate 1998 primarily due reduction pretax income 1998 compared 1997 higher rate partially offset lower state income taxes reduced 1998 benefit minority interest year ended december 31 1999 compared year ended december 31 1998 minority interest year ended december 31 1999 24 million higher 1998 result costs associated preferred interest trinity river associates llc 1999 coupled full year dividends preferred securities el paso energy capital trust issued march 1998 year ended december 31 1998 compared year ended december 31 1997 minority interest year ended december 31 1998 12 million higher 1997 result dividends paid preferred securities el paso energy capital trust wholly owned subsidiary el paso issued march 1998 liquidity capital resources cash operating activities net cash provided operating activities 501 million year ended december 31 1999 compared 1033 million period 1998 decrease primarily attributable cash payments charges related sonat merger net income tax refunds received 1998 reduction gsr collections 1999 early payout certain employee benefits result epec change control defined certain benefit plans 1999 decrease partially offset takeorpay refund paid epng customers 1998 working capital changes cash investing activities net cash used investing activities 23 billion year ended december 31 1999 amounts paid joint ventures equity investment activities primarily acquisition interest chaparral 50 percent ownership interest ce generation llc ownership interest eaprc third quarter 1999 company repurchased 35 percent interest sonat marketing company lp sonat power marketing lp agl investment activities included expenditures acquisitions rio negro power plant encap well expenditures expansion construction projects internally generated funds supplemented financing activities used fund companys investing activities companys planned capital investment expenditures 2000 approximately 2 billion primarily intended expansion international operations domestic unregulated operations pipeline systems production activities facilities computer communication system enhancements funding capital expenditures acquisitions investing expenditures expected provided internally generated funds commercial paper issuances available capacity existing credit facilities andor issuance longterm debt trust securities equity cash financing activities net cash provided financing activities 22 billion year ended december 31 1999 longterm debt borrowings proceeds issuance preferred interest trinity river associates llc proceeds issuance longterm notes payable supplemented internally generated funds used fund capital equity investments reduce shortterm longterm borrowings pay dividends corporate purposes future funding longterm debt retirements dividends financing expenditures expected provided internally generated funds commercial paper issuances available capacity existing credit facilities andor issuance longterm debt trust securities equity addition electron company plans raise approximately 1 billion balance sheet debt first half 2000 finance nug activities liquidity company relies cash generated internal operations primary source liquidity supplemented available credit facilities commercial paper programs availability borrowings companys credit agreements subject specified conditions management believes company currently meets conditions include compliance financial covenants ratios required agreements absence default agreements continued accuracy representations warranties contained agreements including absence material adverse changes since specified dates discussion companys financing arrangements see item 8 financial statements supplementary data note 9 commitments contingencies see item 8 financial statements supplementary data note 10 discussion companys commitments contingencies december 31 1999 company capital investment commitments 497 million expected funded internally generated funds andor incremental borrowings companys planned capital investment projects discretionary nature substantial capital commitments made advance actual expenditures february 2000 epng entered agreement purchase portion american pipeline crude oil transportation system 129 million epng purchase 1088 mile portion pipeline runs mccamey texas emidio station near bakersfield california acquisition subject federal trade commission approval epng plans convert oil pipeline natural gas pipeline estimated cost 75 million pending ferc approval february 2000 company agreed purchase two 67 megawatt natural gasfired electric generation plants located dartmouth massachusetts pawtucket rhode island acquisition pawtucket plant closed february 2000 dartmouth plant acquisition expected close march 2000 part purchase agreement company assumed responsibility operations maintenance activities plants february 2000 merchant energy purchased partnership interests portfolio eleven gasfired combined cycle power generation facilities california dynegy portfolio represents net combined electric generating capacity approximately 370 megawatts also included acquisition operating company turbine maintenance organization eight eleven acquired facilities entered fuel management agreements purchase natural gas fuel oil used operate facilities market rates plus management fee merchant energy currently ten eleven facilities sell power three large public utilities pursuant longterm power contracts january 2000 company acquired bonneville approximately 63 million net cash acquired bonneville owns 50 percent interest 85 megawatt natural gasfired cogeneration facility located las vegas area sells power large utility longterm contract bonneville also provides operations maintenance services longterm contracts two cogeneration facilities las vegas area january 2000 company completed acquisition crystal gas storage inc approximately 220 million transaction accounted purchase crystal gas storage owns operates two natural gas storage facilities near hattiesburg mississippi holds interests natural gas producing properties northern louisiana southern arkansas january 2000 company signed power purchase agreement engineering procurement contract 40 percent interest 60 million power plant located city porto velho western brazil 64 megawatt dieselengine power plant fully commercial july 2000 plant sell power ten year power purchase agreement eletronorte local electric company december 1999 company filed application ferc stagecoach expansion project connect stagecoach storage field tioga county new york tgps mainline new lateral consist 24 miles pipe capacity 500000 dthd addition project expand tgps 300 line provide 90000 dthd firm transportation service bradford county pennsylvania interconnect new jersey natural gas total cost project estimated 87 million service lateral scheduled begin august 2001 service tgps 300 line november 2001 company pursuing telecommunications strategy leverage extensive north american natural gas pipeline system core competency rightofway development extent bandwidth associated fiber optic capacity becomes actively traded marketing trading skills newly developed commodity products company partners currently planning install fiber optic network along certain key segments pipeline system may expand network beyond pipeline system fiber capacity swaps leases third party fiber optic companies year 2000 coordinate phases companys year 2000 project company established executive steering committee project team phases project awareness ii assessment iii remediation iv testing v implementation necessary modifications vi contingency planning goal year 2000 project ensure critical systems processes companys direct control remained functional december 31 1999 company substantially completed phases critical domestic international systems year 2000 rollover date passed apparent disruptions experienced companys systems processes remains possible third parties may experienced disruptions yet manifested impact company could future accordingly company prepared implement contingency plans disruption occur total cost companys year 2000 project continues accumulated company expect incur remaining material costs 2000 december 31 1999 company incurred expenses approximately 21 million capitalized costs approximately 11 million including costs accumulated sonat prior merger company sonats year 2000 costs include direct cost salaried employees including costs benefits company traced incremental expenses related year 2000 project means costs year 2000 project related salaried employees company including direct salaries benefits included estimated costs project disclosure year 2000 readiness disclosure extent reader year 2000 readiness disclosure investor potential investor companys affiliates equity debt securities disclosure made sole purpose communicating disclosing information aimed correcting helping correct andor avoiding year 2000 failures items discussed management aware commitments contingent liabilities would materially adverse effect companys financial condition results operations cash flows new accounting pronouncements yet adopted see item 8 financial statements supplementary data note 1 discussion relating new accounting pronouncements yet adopted risk factors cautionary statement purposes safe harbor provisions private securities litigation reform act 1995 report contains incorporates reference forwardlooking statements within meaning private securities litigation reform act 1995 forwardlooking statement includes statement assumptions bases underlying forwardlooking statement caution believe assumptions bases reasonable made good faith assumed facts bases almost always vary actual results differences assumed facts bases actual results material depending upon circumstances forwardlooking statement management express expectation belief future results expectation belief expressed good faith believed reasonable basis cannot assure however statement expectation belief result achieved accomplished words believe expect estimate anticipate similar expressions generally identify forwardlooking statements mind consider following important factors could cause actual results differ materially expressed forwardlooking statement made us behalf industry highly competitive hydrocarbons transport gather process store many cases owned third parties result volume hydrocarbons involved activities depends actions third parties beyond control following factors beyond control impact ability maintain increase current transmission storage gathering processing sales volumes rates renegotiate existing contracts expire remarket unsubscribed capacity levels rates currently place future weather conditions including favor hydroelectric generation alternative energy sources price competition drilling activity supply availability expiration significant contracts service area competition especially due current excess pipeline capacity california future profitability may affected ability compete services offered energy enterprises may larger offer services possess greater resources ongoing profitability interstate pipeline systems depends upon place longterm firm transportation contracts major portion capacity contracts representing 20 percent tgps firm transportation expire november 2000 contracts representing 43 percent sngs firm transportation expire primarily 2003 epng continues remarket portion capacity shorterterm contractual basis ability negotiate new contracts renegotiate existing contracts could harmed factors cannot control including proposed construction companies additional pipeline capacity markets served companys interstate pipelines reduced demand due higher gas prices actions regulators may impact competitiveness shortterm longterm capacity markets availability alternative energy sources viability expansion projects discussion see item 1 business natural gas transmission markets competition fluctuations energy commodity prices could adversely affect business natural gas prices supply basins connected pipeline systems compared prices gas producing regions especially canada impact ability compete transporters revenues generated gathering processing contracts depend volumes rates affected prices natural gas natural gas liquids success expanding gathering processing operations offshore gulf mexico subject continued development additional oil gas reserves vicinity facilities ability access additional reserves offset natural decline existing wells connected systems decline energy prices could precipitate decrease development activities could cause decrease volume reserves available gathering processing offshore facilities fluctuations energy prices may impact gathering rates investments third parties development new oil gas reserves connected gathering processing facilities caused number factors including regional domestic international supply demand availability adequacy transportation facilities energy legislation federal state taxes sale transportation natural gas natural gas liquids abundance supplies alternative energy sources reductions average volume natural gas transport gather process prolonged period results operations financial position could significantly negatively affected fluctuations exploration production activities could harm business success exploration production activities could adversely affected factors control including fluctuations price crude oil natural gas timing success exploration development drilling programs would affect production levels reserves risks incident drilling operation oil gas wells future drilling production development costs including drilling rig rates success power generation marketing activities depends many factors may beyond control success international domestic power projects power marketing activities could adversely affected factors beyond control including alternative sources supplies energy becoming available due new technologies interest self generation cogeneration uncertain regulatory conditions resulting ongoing deregulation electric industry united states foreign jurisdictions ability negotiate successfully enter restructure recontract advantageous longterm power purchase agreements possibility reduction projected rate growth electricity usage result factors regional economic conditions implementation conservation programs telecommunications business strategy may successful experience telecommunications industry limited cannot assure strategic communications objectives marketing telecommunications capacity proposed fiberoptic network successful success depends part ability integrate adapt facilities services keep pace advances communications technologies new improved devices services result changes addition market fiberoptic capacity telecommunications services rapidly evolving although expect demand services grow cannot assure growth occur additionally price fiber optic capacity expected continue decline sharply increase newlyinstalled fiber optic capacity coming market rapid fiber optic equipment technology improvements certain critical issues including security reliability ease cost access uncertain governmental regulation quality service remain unresolved may adversely affect business cannot assure therefore telecommunications strategy successful may difficulty integrating operations sonat merger risks inherent integration process relating merger sonat including risk sonats business may successfully integrated el paso energys businesses risk may fully realize benefits expected result merger sonat impact loss key employees unsuccessful integrating operations business financial position could adversely affected use derivative financial instruments could result financial losses nonregulated subsidiaries use futures option contracts traded new york mercantile exchange overthecounter options price basis swaps gas merchants financial institutions instruments intended reduce exposure shortterm volatility changes energy commodity prices could however incur financial losses future result volatility market values underlying commodities one counterparties fails perform contract furthermore valuation financial instruments involve estimates changes assumptions underlying estimates occur changing valuation potentially resulting financial losses additional information concerning derivative financial instruments see item 7a quantitative qualitative disclosures market risks item 8 financial statements supplementary data note 7 attractive acquisition investment opportunities may available ability grow depend part upon ability identify complete attractive acquisition investment opportunities growth acquisitions investments joint ventures future operating results success acquisitions joint ventures within outside united states may subject effects changes following united states foreign trade monetary policies laws regulations political economic developments inflation rates taxes operating conditions foreign investments involve special risks activities areas outside us subject risks inherent foreign operations including loss revenue property equipment result hazards expropriation nationalization wars insurrection political risk effects currency fluctuations exchange controls devaluations indonesian brazilian currencies economic problems legal regulatory events unforeseeable obstacles may beyond control ability manage could incur substantial environmental liabilities may incur significant costs liabilities order comply existing future environmental laws regulations also possible developments increasingly strict environmental laws regulations enforcement policies thereunder claims damages property employees persons environment resulting current discontinued operations could result substantial costs liabilities future additional information concerning environmental matters see item 8 financial statements supplementary data note 10 activities involve operating hazards uninsured risks maintain insurance certain risks normally associated transportation exploration production storage gathering processing natural gas including limited explosions pollution fires occurrence significant event fully insured could significant negative effect business remain potential liabilities related acquisition eptpc amount actual contingent liabilities assumed company merger eptpc could vary substantially amount estimated based upon assumptions could prove inaccurate new tenneco inc newport news shipbuilding inc organizations created distributed tenneco inc shareholders prior acquisition tenneco inc company december 1996 unable unwilling pay respective liabilities court could require us certain legal theories may applicable situation assume responsibility obligations required assume obligations could material adverse effect financial condition results operations cash flows remain potential federal income tax liabilities related acquisition eptpc connection acquisition eptpc distributions made eptpc prior acquisition irs issued private letter ruling old tenneco inc tenneco inc prior acquisition company ruled united states federal income tax purposes distributions would taxfree old tenneco inc except extent cash received lieu fractional shares existing stockholders merger would constitute taxfree reorganization certain transactions effected connection merger distribution would taxfree distributions qualify taxfree corporate level federal income tax would assessed consolidated group old tenneco inc common parent corporate level federal income tax would payable eptpc certain limited circumstances however new tenneco inc newport news shipbuilding inc agreed indemnify eptpc defined portion tax liabilities subject financing interest rate exposure risks business operating results harmed factors availability cost capital changes interest rates changes tax rates due new tax laws changes structured finance market perceptions natural gas energy industry el paso credit ratings item 7aitem 7 managements discussion analysis financial condition results operations general past several years business activities operations changed dramatically result significant acquisitions transactions internal growth initiatives designed enhance ability compete effectively global energy industry changes significantly expanded operating scope ability generate operating cash flows needs cash investment opportunities consequently substantially expanded credit facilities created financing structures facilities meet needs period significant changes discussed merger coastal corporation january 2001 merged coastal corporation accounted merger pooling interests converted share coastal common stock class common stock taxfree basis 123 shares common stock also exchanged coastals outstanding convertible preferred stock common stock basis preferred stock converted coastal common stock immediately prior merger issued total 271 million shares including 4 million shares issued holders coastal stock options total value transaction approximately 24 billion including 7 billion assumed debt preferred equity coastal diversified energy holding company engaged subsidiaries joint ventures natural gas transmission storage gathering processing marketing natural gas oil exploration production petroleum refining marketing distribution chemicals production power production coal mining coastal owns interests approximately 18000 miles natural gas pipelines extending across midwestern rocky mountain areas us proved reserves 36 tcfe coastal also international domestic interests natural gas oil producing properties power generation plants crude oil refining facilities purchase texas midstream operations late december 2000 completed purchase pges texas midstream operations 887 million including assumption 527 million debt accounted acquisition purchase assets acquired consist 7500 miles natural gas transmission natural gas liquids pipelines transport approximately 28 bcfd nine natural gas processing plants process 15 bcfd rights 72 bcf natural gas storage capacity assets serve majority metropolitan areas largest industrial load centers texas well numerous natural gas trading hubs assets also create physical link epng tgp systems march 2001 field services sold acquired natural gas liquids transportation fractionation assets energy partners assets sold include 600 miles natural gas liquids gathering transportation pipelines three fractionation plants located south texas december 2000 comply federal trade commission order sold interest oasis pipeline company proceeds sale 22 million recognized extraordinary loss 19 million net income taxes 9 million merger sonat inc october 1999 completed merger sonat merger issued one share common stock share sonat common stock total shares issued approximately 110 million shares connection federal trade commission order related merger sold east tennessee natural gas company sea robin pipeline company well onethird interest destin pipeline company proceeds sales approximately 616 million recognized extraordinary gain 89 million net income taxes 60 million accounted merger pooling interests mergerrelated costs asset impairment charges integrated activities operations mergers acquisitions incurred continue incur charges significant impact results operations financial position cash flows costs nonrecurring nature include employee severance retention transition charges writeoffs writedowns duplicate assets charges relocate assets employees contract termination charges align accounting policies practices three year period ended december 31 2000 incurred charges related mergers coastal sonat zilkha energy september 2000 announced plan geographically consolidate pipeline operations coastals following completion coastal merger consolidation plan el paso natural gas companys operations relocated el paso texas colorado springs colorado anr pipeline company subsidiary coastal relocated detroit michigan houston texas along consolidation also conduct numerous relocations among various operating sites relocations plans expected completed midyear 2001 upon merger coastal issued approximately 4 million shares common stock exchange coastal employee former employee outside director stock options total charge connection exchange approximately 278 million included combined operations first quarter 2001 result merger coastal also required sell midwestern pipeline system proceeds sale expected approximately 90 million result tax gain approximately 50 million expect complete sale second quarter 2001 additionally first quarter 2001 energy partners sold interest several offshore assets sales consisted interests seven natural gas pipeline systems dehydration facility two offshore platforms proceeds sales approximately 135 million resulted loss partnership approximately 23 million additional consideration sales committed pay energy partners series payments totaling 29 million amount well proportional share losses sale partnerships assets recorded charge income statement first quarter 2001 anticipate impact sale midwestern system transactions energy partners material effect ongoing financial position operating results cash flows january 30 2001 completed employee restructuring resulted reduction 3285 fulltime positions combination early retirements terminations reductions occurred across locations business segments actions resulted severance termination charges retention payments employees retained combined organization acceleration employee benefits existing benefit plans total charges connection actions estimated approximately 890 million majority recorded first quarter 2001 total cost mergerrelated activities well additional charges incur complete evaluations contracts operating assets accounting policies combined organization could range 16 billion 2 billion estimate based costs expect record first quarter 2001 preliminary estimates additional costs incur expect charges recorded 2001 also three year period ended december 31 2000 incurred variety asset impairment charges ranging result rate filings within regulated pipelines writedowns operating plants contracts determined impaired also recorded writedowns capitalized costs natural gas oil properties full cost method accounting 1998 1999 mergerrelated costs asset impairment charges reflected results operations discussed segments table provides summary mergerrelated costs asset impairment charges business segments total three years ended december 31 segment results operations business activities segregated four segments pipelines merchant energy field services production segments strategic business units offer variety different energy products services fourth quarter 2000 combined international segment merchant energy segment reflect ongoing globalization merchant energy strategy operating activities addition results include impact merger coastal reflected results operations 2001 results pges texas midstream operations reflected results purchase date manage segments separately requires different technology marketing strategies since earnings equity investments significant component earnings several segments evaluate segment performance based earnings interest expense taxes ebit instead operating income extent possible results operations reclassified conform current business segment presentation although results necessarily indicative results would achieved revised business segment structure effect periods operating revenues expenses segment include intersegment revenues expenses eliminated consolidation changes energy commodity prices similar impact operating revenues cost products sold period believe gross margin revenue less cost sales provides accurate meaningful basis analyzing operating results merchant energy field services segments discussion individual segments see item 8 financial statements supplementary data note 15 following table presents ebit segment total including mergerrelated costs asset impairment charges discussed three years ended december 31 pipelines pipeline segment operates interstate pipeline businesses segments pipeline systems operates separate tariff governs operations rates operating results pipeline systems generally stable majority revenues based fixed demand charges result expect changes aspect business primarily driven regulatory actions contractual events commodity throughputbased revenues account smaller portion operating results revenues vary period system impacted factors weather operating efficiencies competition pipelines lesser degree fluctuations natural gas prices results operations pipeline segment follows three years ending december 31 year ended december 31 2000 compared year ended december 31 1999 operating revenues year ended december 31 2000 74 million lower period 1999 decrease due impact sales east tennessee pipeline sea robin systems first quarter 2000 required sell ftc order condition completing sonat merger also contributing decrease favorable resolution regulatory issues first quarter 1999 tgp lower rates following sngs may 2000 rate case settlement lower revenues contracts relinquished capacity epng elimination minimum bill provision elba island facility following fercs approval elba islands reactivation first quarter 2000 additionally impact customer settlements contract terminations 2000 resolutions customer imbalance issues 1999 tgp contributed decrease partially offsetting decreases higher revenues transportation services provided transmission systems due improved average throughput 2000 higher realized prices pipeline gas sales revenues january 2000 acquisition crystal gas storage inc prior sale energy partners september 2000 operating expenses year ended december 31 2000 160 million lower period 1999 decrease due cost efficiencies following merger sonat lower operating costs east tennessee pipeline sea robin systems result sale march 2000 favorable impact fercs authorization reactivate sngs elba island facility first quarter 2000 also contributing decrease 1999 resolution contested rate matter customer epng severance termination charges incurred result sonat merger impairment several sng expansion projects occurring 1999 additionally estimated future environmental costs writeoffs duplicate information technology assets 1999 sng following merger sonat contributed decrease partially offset impact unfavorable producer shipper settlements epng well revised estimates regulatory recoveries epng higher utility costs 2000 income year ended december 31 2000 17 million higher period 1999 increase due higher earnings citrus corp result onetime benefit recorded 2000 well gains sale nonpipeline assets third quarter 2000 increase partially offset favorable settlement regulatory issue 1999 elimination asset future recovery costs elba island facility lower allowance funds used construction result less expansion construction activity 2000 year ended december 31 1999 compared year ended december 31 1998 operating revenues year ended december 31 1999 75 million higher 1998 increase due favorable resolution regulatory issues 1999 tgp coupled downward revision 1998 amount recoverable interest tgps gsr costs also contributing increase higher revenues transportation services increase firm transportation revenues sng system associated expansion projects resolutions tgps customer imbalance issues higher operational gas sales increases partially offset lower system throughput tgp system 1999 favorable resolution 1998 contested rate matter mpc system related rate methodology higher nontransportation revenues 1998 sng system operating expenses year ended december 31 1999 159 million higher 1998 increase due severance termination charges incurred result merger sonat impairment several sng expansion projects increase estimated environmental costs writeoffs duplicate information technology assets occurring 1999 also contributing increase higher general administrative costs systems higher depreciation expansion projects sng unfavorable 1999 resolution contested rate matter customer epng partially offsetting increases revised estimates regulatory recoveries epng income year ended december 31 1999 8 million lower 1998 decrease primarily due lower equity earnings destin pipeline company 1999 partially offset increase 1999 interest income destinrelated debt issuance latter part 1998 required sell destin result merger sonat merchant energy merchant energy market maker involved wide range activities wholesale energy market place including trading risk management asset ownership financial services markets served merchant energy highly competitive influenced directly indirectly energy market economics merchant energys trading risk management activities provide sophisticated energy trading energy management solutions customers affiliates involving primarily natural gas power within trading risk management operations merchant energy originates transactions customers assist energy supply aggregation storage transportation management well valuation risk management merchant energy maintains substantial trading portfolio balances position risk across multiple commodities seasonally fluctuating energy demands 2000 us energy supply demand resulted substantial volatility energy markets significantly impacted merchant energys earnings opportunities volatility expected continue 2001 although necessarily levels experienced 2000 merchant energy provider power natural gas state california latter half 2000 continuing 2001 california experienced sharp increases natural gas prices wholesale power prices due energy shortages resulting concurrence variety circumstances including unusually warm summer weather followed high winter demand low gas storage levels poor hydroelectric power conditions maintenance downtime significant generation facilities price caps discouraged power movement nearby states california increase power prices caused imbalance natural gas power supply demand coupled electricity price caps imposed rates allowed charged california electricity customers resulted large cash deficits two major california utilities southern california edison pacific gas electric result utilities defaulted payments creditors accumulated substantial collections customers resulted credit ratings downgraded 2001 investment grade investment grade utilities filed emergency rate increases california public utilities commission working state authorities restore companies financial viability historically one largest suppliers energy california actively participating parties california part longterm stable solution californias energy needs march 2001 merchant energy believes exposure sales power gas state california including receivables related interest california power plant investments approximately 50 million net credit reserves reflect market uncertainties merchant energys asset ownership activities include global power plants power facilities owned managed behalf chaparral assetbased businesses include power plants 16 countries merchant energy also actively involved developing global lng operation 2000 merchant energy earned 80 million fee based revenue chaparral reimbursed 20 million operating expenses expect 2001 fee based revenue increase approximately 147 million based growth chaparral asset portfolio financial services area merchant energy owns encap enerplus conducts energy financing activities encap manages three separate oil natural gas investment funds us serves investment advisor one fund europe encap also facilitates investment emerging energy companies earns return investments 2000 merchant energy acquired enerplus canadian investment management company conducts fund management activities similar encap canada merchant energys operating results analysis results three years ended december 31 volumes year ended december 31 2000 compared year ended december 31 1999 trading gross margin represents revenue physical energy commodity sales less costs sales well results financial trading activities year ended december 31 2000 trading gross margin 315 million higher period 1999 commodity marketing trading margins increased due significant price volatility natural gas power markets increased value trading portfolio 2000 also contributing increase higher income power transactions originated 2000 versus 1999 increases partially offset natural gas transactions originated 1999 operating revenues represent operating revenues excluding revenue energy commodity sales year ended december 31 2000 revenues 172 million higher period 1999 increase due higher asset management fees earned chaparral began operations fourth quarter 1999 consolidation brazilian power project latter part 1999 higher income west georgia power project seasonal peaking facility began operating june 2000 encaps financial services activities 2000 acquisition enerplus march 2000 also contributed increase operating expenses year ended december 31 2000 37 million lower period 1999 decrease due higher reimbursements 2000 general administrative costs relating chaparral 1999 charge eliminate minority investor sonats marketing joint venture following sonat merger 1999 asset writedowns charges conform consolidate accounting practices policies sonat following merger decrease partially offset higher general administrative expenses project development costs relating international projects 2000 income year ended december 31 2000 36 million higher period 1999 increase due higher earnings power projects investments primarily ce generation acquired march 1999 well benefit realized formation east asia power joint venture march 2000 also contributing increase settlement received indonesian project may 2000 higher interest income increases partially offset lower equity earnings investments various international projects primarily investment east asia power philippines year ended december 31 1999 compared year ended december 31 1998 trading gross margin year ended december 31 1999 20 million higher period 1998 commodity marketing trading margins increased due transactions originated 1999 partially offset decrease trading margins 1999 operating revenues year ended december 31 1999 61 million higher period 1998 increase primarily due management fees earned chaparral revenues brazilian power project consolidated latter part 1999 revenues consolidated power generation facilities acquired december 1998 operating expenses year ended december 31 1999 135 million higher period 1998 increase due higher operating costs associated increase power activities operating expenses consolidated power generation facilities acquired december 1998 1999 charge eliminate majority interest sonats marketing joint venture following sonat merger 1999 asset writedowns charges conform consolidate accounting practices policies sonat following merger also contributing increase higher general administrative costs higher operating costs brazilian power project increases partially offset lower project development costs international projects 1999 income year ended december 31 1999 29 million higher period 1998 increase due higher earnings power projects investments primarily ce generation higher interest income 1999 equity swap gains recognized capsa project increases partially offset 1998 gains sale projectrelated activities surplus power equipment field services field services provides variety services midstream component operations including gathering treating natural gas processing fractionation natural gas natural gas liquids natural gas derivative products butane ethane propane subsidiary field services also serves general partner energy partners publicly traded master limited partnership general partner field services earns combination management fees partner distributions services rendered energy partners field services attempts balance earnings activities combination contractually based market based services gathering treating operations earn margins substantially feebased services means revenues product market price usually related monthly natural gas price index volume gathered 2000 field services hedged substantial amount risk associated changes natural gas prices entering forward natural gas derivatives processing fractionation operations earn margin based feebased contracts makewhole contracts makewhole contracts allow us retain extracted liquid products return producer btu equivalent amount natural gas periods natural gas liquid prices volatile field services may greater price risk makewhole contracts makewhole contracts constitute greater portion operating contracts acquired late december connection acquisition pges texas midstream operations field services operating results analysis results follows three years ended december 31 year ended december 31 2000 compared year ended december 31 1999 total gross margin year ended december 31 2000 42 million higher period 1999 gathering treating margins increased due higher average gathering rates predominantly san juan basin substantially indexed natural gas prices higher average condensate prices higher margin 2000 partially offset lower gathering treating volumes due sale el paso intrastate alabama gathering system coalbed methane producing regions alabama energy partners march 2000 processing margins increased due higher liquids prices 2000 acquisition april 2000 interest indian basin processing assets operating expenses year ended december 31 2000 4 million higher period 1999 due higher depreciation amortization assets transferred epng field services following ferc order well december 2000 impairment charge related needle mountain processing facility due unrecoverability costs increase partially offset impairment gathering assets 1999 lower costs labor benefits cost recoveries managed facilities income year ended december 31 2000 21 million lower period 1999 decrease primarily due net gains 1999 sale interest viosca knoll gathering system energy partners june 1999 well lower equity earnings 2000 following sale interest viosca knoll year ended december 31 1999 compared year ended december 31 1998 total gross margin year ended december 31 1999 1 million lower period 1998 gathering treating margins increased due higher volumes average gathering rates substantially indexed natural gas prices partially offset elimination margins assets anadarko basin sold september 1998 processing margins decreased due lower liquids prices sale two processing facilities 1999 operating expenses year ended december 31 1999 23 million higher period 1998 increase due higher shared services allocations 1999 impairment gathering assets fourth quarter 1999 increase depreciation amortization resulting acquisitions income year ended december 31 1999 33 million higher period 1998 increase due higher earnings investments primarily energy partners well gain recorded 1999 sale interest viosca knoll production productions operating results driven variety factors including ability locate develop economic reserves extract reserves minimal production costs sell products attractive commodity prices operate lowest cost level possible past years production successful replacing production new relatively low cost reserves addition production also successful efficiently extracting reserves maintaining low overall cost structure 1998 production restructured business response depressed market conditions 1999 following sonat merger efforts successful reducing overhead administrative costs production engages hedging activities natural gas oil production order stabilize cash flows reduce risk downward commodity price movements sales production achieved natural gas oil swaps typically higher percentage production hedged current year decreases year thereafter productions hedged position closely monitored evaluated effort achieve earnings objectives reduce risks associated spotmarket price volatility 2000 realized prices natural gas oil sales lower could realized production sold spotmarket prices however hedging strategy produced relatively stable revenue stream resulted expected rates return 2001 anticipate hedging approximately 75 percent production includes estimates coastals 2001 production factors ones influencing results usually impact performance period operating results analysis results three years ending december 31 year ended december 31 2000 compared year ended december 31 1999 operating revenues year ended december 31 2000 49 million higher 1999 increase due higher realized prices natural gas oil condensate liquids operating expenses year ended december 31 2000 405 million lower 1999 decrease due full cost ceiling test charges incurred first quarter 1999 decreased 2000 labor costs result organizational restructuring following sonat merger 1999 charges retain sonats seismic data production operations result merger decrease partially offset higher depletion rates 2000 result increased future development costs 2000 versus 1999 year ended december 31 1999 compared year ended december 31 1998 total operating revenues year ended december 31 1999 62 million lower 1998 decrease natural gas oil condensate liquids revenues primarily due sales properties 1998 partially offset increase realized prices 1999 increase revenues resulted favorable contractual settlement 1999 operating expenses year ended december 31 1999 743 million lower 1998 primarily due lower full cost ceiling test charges 1999 versus charges incurred 1998 along lower production levels 1999 also contributing decrease lower operating maintenance expenses due property dispositions 1998 efficiencies created productions 1998 reorganization operations decreases partially offset charges retain sonats seismic data production operations result sonat merger income year ended december 31 1999 2 million lower 1998 due primarily net gain sale nonoperating assets third quarter 1998 corporate expenses net year ended december 31 2000 compared year ended december 31 1999 corporate expenses year ended december 31 2000 226 million lower 1999 decrease primarily due higher costs related merger sonat 1999 partially offset costs incurred 2000 related merger coastal also offsetting decrease increased funding commitments el paso energy foundation 2000 incur additional mergerrelated costs 2001 result merger coastal year ended december 31 1999 compared year ended december 31 1998 net corporate expenses year ended december 31 1999 328 million higher 1998 primarily due charges 1999 related merger sonat including accelerated amortization certain employee benefits legal accounting financial advisory costs employee severance retention costs incremental costs incurred combining office facilities following merger increase partially offset costs incurred 1998 introduction power services activities higher recurring equity compensation charges 1998 interest debt expense year ended december 31 2000 compared year ended december 31 1999 interest debt expense year ended december 31 2000 85 million higher 1999 primarily due 900 million increased borrowings combination shortterm longterm programs el paso fund capital expenditures acquisitions investing activities 46 million increased interest expense borrowings chaparral 2000 year ended december 31 1999 compared year ended december 31 1998 interest debt expense year ended december 31 1999 66 million higher 1998 primarily due increased borrowings el paso 18 billion fund capital expenditures acquisitions investing activities offset higher capitalized interest 1999 higher project investment development primarily production merchant energy income tax expense benefit income tax expense benefit years ended december 31 2000 1999 1998 286 million 81 million 170 million amounts resulted effective tax rates 33 percent 25 percent 36 percent differences effective tax rates statutory tax rate 35 percent primarily result following factors state income taxes earnings unconsolidated equity investees anticipate receiving dividends foreign income taxed us taxed foreign tax rates utilization deferred credits loss carryovers nondeductible portion mergerrelated costs nondeductible dividends preferred stock subsidiary reconciliation statutory rate 35 percent effective rates three years ended december 31 2000 see item 8 financial statements supplementary data note 4 minority interest year ended december 31 2000 compared year ended december 31 1999 minority interest year ended december 31 2000 83 million higher 1999 primarily due full year costs associated preferred interest trinity river associates llc formed june 1999 also contributing increase costs associated preferred interest clydesdale associates lp distributions associated preferred securities el paso energy capital trust iv formed may 2000 year ended december 31 1999 compared year ended december 31 1998 minority interest year ended december 31 1999 24 million higher 1998 result costs associated preferred interest trinity river associates llc 1999 coupled full year dividends preferred securities el paso energy capital trust issued march 1998 liquidity capital resources cash operating activities net cash used operating activities 1040 million year ended december 31 2000 compared net cash provided operating activities 501 million 1999 increase cash used operations primarily result cash expended price risk management activities well higher trading receivables payables related substantial growth trading portfolio higher prices energy commodity markets also higher interest payments 2000 primarily related higher longterm shortterm debt balances higher 2000 income tax payments result higher state foreign income tax payments partially offsetting increases higher payments 1999 mergerrelated costs activities versus mergerrelated payments made 2000 higher cash generated 2000 pipeline field services production operations 2001 expect pay significant amounts related coastal merger expect cash demands expanded merchant energy activities continue offsetting higher cash generated expanded operations following merger coastal cash investing activities net cash used investing activities 1553 million year ended december 31 2000 investing activities principally consisted additions joint ventures equity investments including increase chaparral equity investment purchase additional 185 interest argentine company capsa purchase investment korean power company korea independent energy corporation formerly hanwha energy co ltd note receivable quanta investors llc company formed hold various telecommunications assets investing activities 2000 included acquisitions pges texas midstream operations crystal gas storage inc enerplus global management also purchased allamerican pipeline assets interest indian basin gas processing plant assets expenditures expansion construction projects cash inflows investment related activities included proceeds sales east tennessee pipeline system sea robin pipeline system el paso intrastatealabama pipeline system onethird interest destin pipeline system west georgia generating company also received proceeds formation east asia power joint venture repayment note receivable chaparral cash financing activities net cash provided financing activities 2736 million year ended december 31 2000 cash provided financing activities included revolving credit borrowings issuance longterm debt sale interest clydesdale associates lp issuance preferred securities el paso energy capital trust iv notes payable chaparral 2000 repaid shortterm borrowings paid dividends retired longterm debt liquidity rely cash generated internal operations primary source liquidity supplemented available credit facilities commercial paper programs availability borrowings credit agreements subject specified conditions believe currently meet conditions include compliance financial covenants ratios required agreements absence default agreements continued accuracy representations warranties including absence material adverse changes since specified dates expect future funding working capital needs capital expenditures acquisitions investing activities longterm debt retirements payments dividends financing expenditures provided internally generated funds commercial paper issuances available capacity existing credit facilities issuance new longterm debt trust securities equity discussion financing arrangements see item 8 financial statements supplementary data note 9 commitments contingencies see item 8 financial statements supplementary data note 11 discussion commitments contingencies december 31 2000 capital investment commitments 12 billion primarily relating production pipeline international power activities planned capital investment projects discretionary nature substantial capital commitments made advance actual expenditures new accounting pronouncements yet adopted see item 8 financial statements supplementary data note 1 discussion new accounting pronouncements yet adopted risk factors cautionary statement purposes safe harbor provisions private securities litigation reform act 1995 report contains incorporates reference forwardlooking statements within meaning private securities litigation reform act 1995 forwardlooking statement includes statement assumptions bases underlying forwardlooking statement caution believe assumptions bases reasonable made good faith assumed facts bases almost always vary actual results differences assumed facts bases actual results material depending upon circumstances forwardlooking statement management express expectation belief future results expectation belief expressed good faith believed reasonable basis cannot assure however statement expectation belief result achieved accomplished words believe expect estimate anticipate similar expressions generally identify forwardlooking statements mind consider following important factors could cause actual results differ materially expressed forwardlooking statement made us behalf operate highly competitive industries natural gas natural gas liquids transport gather process store owned third parties result volume natural gas natural gas liquids involved activities depends actions third parties beyond control following factors beyond control may unfavorably impact ability maintain increase current transmission storage gathering processing sales volumes rates renegotiate existing contracts expire remarket unsubscribed capacity future weather conditions including favor hydroelectric generation alternative energy sources price competition drilling activity supply availability expiration significant contracts service area competition especially due current excess pipeline capacity california midwest unable compete services offered energy enterprises may larger offer services possess greater resources future profitability may negatively impacted revenues pipeline businesses generated contracts must renegotiated periodically substantially pipeline subsidiaries revenues generated natural gas transportation contracts expire periodically must renegotiated extended replaced although actively pursue renegotiation extension andor replacement contracts cannot assure able extend replace contracts expire terms renegotiated contracts favorable existing contracts particular ability extend andor replace transportation contracts could harmed factors cannot control including proposed construction companies additional pipeline capacity markets served interstate pipelines changes state regulation local distribution companies may cause negotiate shortterm contracts reduced demand due higher natural gas prices availability alternative energy sources supply points viability expansion projects unable renew extend replace contracts renew less favorable terms may suffer material reduction revenues earnings fluctuations energy commodity prices could adversely affect business natural gas prices supply basins connected pipeline systems higher prices natural gas producing regions especially canada ability compete transporters may negatively impacted revenues generated gathering processing contracts depend volumes rates affected prices natural gas natural gas liquids success gathering processing operations offshore gulf mexico subject continued development additional oil natural gas reserves vicinity facilities ability access additional reserves offset natural decline existing wells connected systems decline energy prices could precipitate decrease development activities could cause decrease volume reserves available gathering processing offshore facilities fluctuations energy prices may impact gathering rates investments third parties development new oil natural gas reserves connected gathering processing facilities caused number factors including regional domestic international supply demand availability adequacy transportation facilities energy legislation federal state taxes sale transportation natural gas natural gas liquids abundance supplies alternative energy sources reductions average volume natural gas natural gas liquids transport gather process prolonged period results operations financial position could significantly negatively affected rates able charge customers may reduced governmental authorities pipeline businesses regulated ferc various state local regulatory agencies particular ferc generally limits rates permitted charge customers interstate natural gas transportation cases sales natural gas rates permitted charge customers use regulated pipelines lowered profitability pipeline businesses may reduced success oil natural gas exploration production businesses dependent factors cannot predicted certainty performance exploration production businesses dependent upon number factors cannot control factors include fluctuations crude oil natural gas prices results future drilling activity ability identify precisely locate prospective geologic structures drill successfully complete wells structures timely manner ability expand leased land positions desirable areas often subject intensely competitive leasing conditions risks incident operations natural gas oil wells future drilling production development costs including drilling rig rates estimates oil natural gas reserves may change actual production revenues taxes development expenditures operating expenses respect reserves likely vary estimates proved reserves oil natural gas variances may material process estimating oil natural gas reserves complex requiring significant decisions assumptions evaluation available geological geophysical engineering economic data reservoir deposit result estimates inherently imprecise actual future production oil natural gas prices revenues taxes development expenditures operating expenses quantities recoverable oil natural gas reserves may vary substantially estimates addition may required revise reserve information downward upward based upon production history results future exploration development prevailing oil natural gas prices factors many beyond control success power generation marketing activities depends many factors may beyond control success international domestic power projects power marketing activities amount related performancebased management fee paid us connection electron financing structure could adversely affected factors beyond control including alternative sources supplies energy becoming available due new technologies interest self generation cogeneration uncertain regulatory conditions resulting ongoing deregulation electric industry united states foreign jurisdictions ability negotiate successfully enter restructure recontract advantageous longterm power purchase agreements possibility reduction projected rate growth electricity usage result factors regional economic conditions implementation conservation programs inability customers pay amounts owed power purchase agreements increasing price volatility due deregulation changes commodity trading practices telecommunications business strategy may successful experience telecommunications industry limited cannot assure telecommunications strategy successful success depends part evolution telecommunications commodity ability integrate adapt facilities services keep pace advances communications technologies new improved devices services result changes addition market fiber optic capacity telecommunications services rapidly evolving although expect demand services grow cannot assure growth occur additionally price fiber optic capacity expected continue decline sharply increase newly installed fiber optic capacity coming market rapid fiber optic equipment technology improvements variety critical issues including security reliability ease cost access creation liquid trading market uncertain governmental regulation quality service remain unresolved may adversely affect business cannot assure therefore telecommunications strategy successful cannot assure coastal successfully combined single entity cannot successfully combine operations coastal may experience material adverse effect business financial condition results operations merger coastal involves combining two companies previously operated separately combining companies involves number risks including diversion managements attention combining operations difficulties combining operations systems difficulties assimilating retaining employees challenges keeping customers potential adverse shortterm effects operating results financial position among factors considered board directors company approving merger agreement opportunities economies scale scope opportunities growth operating efficiencies could result merger although expect combined company achieve significant annual savings operating costs result merger may able maintain levels operating efficiency previously achieved might achieve remain separate difficulties combining operations may able achieve cost savings sizerelated benefits hope achieve merger use derivative financial instruments could result financial losses nonregulated subsidiaries use futures option contracts traded new york mercantile exchange overthecounter options price basis swaps natural gas merchants financial institutions instruments intended reduce exposure shortterm volatility changes energy commodity prices could however incur financial losses future result volatility market values underlying commodities one counterparties fails perform contract furthermore valuation financial instruments involve estimates changes assumptions underlying estimates occur changing valuation instruments potentially resulting financial losses additional information concerning derivative financial instruments see item 7a quantitative qualitative disclosures market risks item 8 financial statements supplementary data note 6 attractive acquisition investment opportunities may available ability grow depend part upon ability identify complete attractive acquisition investment opportunities growth acquisitions investments joint ventures future operating results success acquisitions joint ventures within outside united states may subject effects changes united states foreign trade monetary policies laws regulations political economic developments inflation rates taxes operating conditions foreign investments involve special risks activities areas outside us subject risks inherent foreign operations including loss revenue property equipment result hazards expropriation nationalization wars insurrection political risk effects currency fluctuations exchange controls devaluations foreign currencies economic problems changes laws regulations policies foreign governments including associated changes governing parties costs environmental liabilities regulations litigation could exceed estimates current former operations involve management regulated materials subject various environmental laws regulations laws regulations obligate us clean various sites petroleum chemicals lowlevel radioactive substances regulated materials may disposed released sites designated superfund sites epa comprehensive environmental response compensation liability act also party legal proceedings involving environmental matters pending various courts agencies possible us estimate reliably amount timing future expenditures related environmental matters difficulty estimating clean costs uncertainty quantifying liability environmental laws impose joint several liability potentially responsible parties nature environmental laws regulations possible introduction future environmental laws regulations although believe established appropriate reserves liabilities including clean costs could required set aside additional reserves future due uncertainties additional information concerning environmental matters see item 8 financial statements supplementary data note 11 operations subject operational hazards uninsured risks exploration production transportation gathering processing operations subject inherent risks normally associated operations including explosions pollution release toxic substances fires hazards could result damage destruction facilities damages persons property events occur could suffer substantial losses maintain insurance types risks extent amounts believe reasonable financial condition operations could adversely affected significant event occurs fully covered insurance remain potential liabilities related acquisition el paso tennessee pipeline co amount actual contingent liabilities assumed merger el paso tennessee 1996 could vary substantially amounts estimated based upon assumptions could prove inaccurate new tenneco inc newport news shipbuilding inc organizations created distributed tenneco inc shareholders prior acquisition tenneco incs energy businesses december 1996 unable unwilling pay respective liabilities court could require us legal theories may applicable situation assume responsibility obligations required assume obligations could material adverse effect financial condition results operations cash flows remain potential federal income tax liabilities related acquisition el paso tennessee pipeline co connection acquisition el paso tennessee distributions made el paso tennessee prior acquisition irs issued private letter ruling old tenneco inc known el paso tennessee ruled united states federal income tax purposes distributions would taxfree old tenneco inc except extent cash received lieu fractional shares existing stockholders merger would constitute taxfree reorganization transactions effected connection merger distribution would taxfree distributions qualify taxfree corporate level federal income tax would assessed consolidated group old tenneco inc common parent corporate level federal income tax would payable el paso tennessee limited circumstances however new tenneco inc newport news shipbuilding inc agreed indemnify el paso tennessee defined portion tax liabilities subject financing interest rate exposure risks business operating results harmed factors availability cost capital changes interest rates changes tax rates due new tax laws changes structured finance market perceptions us natural gas energy industry credit ratings subject foreign currency exchange risk fluctuations value dollar rises falls daily foreign currency exchanges negative effect businesses operating results item 7aitem 7 managements discussion analysis financial condition results operations general past several years business activities operations grown dramatically result significant acquisitions transactions internal growth initiatives enhanced ability compete global energy industry growth significantly expanded operating scope ability generate operating cash flows needs cash investment opportunities consequently substantially expanded credit facilities entered financing arrangements facilities meet needs period significant events discussed merger coastal corporation january 2001 merged coastal corporation accounted merger pooling interests converted share coastal common stock class common stock taxfree basis 123 shares common stock also exchanged coastals outstanding convertible preferred stock common stock basis preferred stock converted coastal common stock immediately prior merger issued total 271 million shares including 4 million shares issued holders coastal stock options discussion analysis financial condition results operations reflects combined information two companies periods presented connection federal trade commission ftc order related merger 2001 sold gulfstream pipeline project midwestern gas transmission system investments empire state stingray ut offshore iroquois pipeline systems proceeds sales approximately 279 million recognized extraordinary gain 26 million net income taxes 27 million transactions purchase texas midstream operations december 2000 completed purchase pacific gas electrics pgestexas midstream operations 887 million including 527 million assumed debt accounted acquisition purchase assets acquired consist 7500 miles intrastate natural gas transmission natural gas liquids pipelines transport approximately 28 bcfd nine natural gas processing plants process 15 bcfd rights 72 bcf natural gas storage capacity assets serve majority metropolitan areas largest industrial load centers texas well numerous natural gas trading hubs assets also create physical link epng tgp systems results acquisition reflected results operations date purchase december 2000 comply ftc order sold interest oasis pipeline company proceeds sale 22 million recognized extraordinary loss 19 million net income taxes 9 million march 2001 sold acquired natural gas liquids transportation fractionation assets el paso energy partners approximately 133 million assets sold included 600 miles natural gas liquids gathering transportation pipelines three fractionation plants located south texas february 2002 announced sale remaining natural gas transmission assets el paso energy partners see discussion sale discussion segment operating results field services segment merger sonat inc october 1999 completed merger sonat inc accounted merger pooling interests converted share sonat common stock one share common stock issued approximately 110 million shares connection ftc order related merger sold east tennessee natural gas company sea robin pipeline company pipeline systems well onethird interest destin pipeline company system proceeds sales approximately 616 million recognized extraordinary gain 89 million net income taxes 59 million balance sheet enhancement plan december 2001 announced plan strengthen capital structure enhance liquidity response changes market conditions industry plan involves sale assets reduction capital spending issuance equity elimination renegotiation rating triggers several financing arrangements goal plan reduce debt total capital ratio 50 percent end 2002 information plan see discussion future liquidity mergerrelated costs asset impairments charges incurred significant impact results operations financial position cash flows three years ended december 31 mergerrelated costs mergerrelated costs relate mergers coastal sonat consisted following three years ended december 31 employee severance retention transition costs include direct payments benefit costs severed employees early retirees occurred result mergerrelated workforce reduction consolidation following coastal merger completed employee restructuring across operating segments resulting reduction 3285 fulltime positions combination early retirements terminations following sonat merger total approximately 870 fulltime positions eliminated similar restructuring employee severance costs include actual severance payments costs pension postretirement benefits settled curtailed existing benefit plans result restructurings retention charges include payments employees retained following mergers payments employees satisfy contractual obligations transition costs relate costs relocate employees costs severed retired employees arising severance date transition jobs ongoing workforce pension postretirement benefits accrued merger date paid applicable benefit periods terminated retired employees costs expensed incurred paid also included 2001 employee severance retention transition costs charge 278 million resulting issuance approximately 4 million shares common stock date coastal merger exchange fair value coastal employees directors stock options transaction costs include investment banking legal accounting consulting advisory fees incurred obtain federal state regulatory approvals take actions necessary complete mergers items expensed periods incurred business operational integration costs include charges consolidate facilities operations business segments lease termination abandonment charges recognition marktomarket value energy trading contracts resulting changes contracts managed combined operating strategy incremental fees software seismic license agreements also included 2001 charges approximately 222 million estimated lease related costs relocate pipeline operations detroit michigan houston texas el paso texas colorado springs colorado charges accrued time completed relocations closed offices amounts accrued paid term applicable noncancelable lease agreements costs expensed incurred mergerrelated asset impairments relate writeoffs writedowns capitalized costs duplicate systems redundant facilities assets whose value impaired result decisions strategic direction combined operations following merger coastal charges occurred merchant energy production pipelines segments assets either operations suspended continue held use charges taken based comparison cost assets estimated fair value ongoing operations based change operating strategy costs include payments made satisfaction obligations arising ftc approval merger coastal miscellaneous charges items expensed period incurred asset impairments 2001 asset impairment charges resulted writedowns investments several international power projects merchant energy segment several telecommunications investments corporate operations 2000 charges consisted impairment coal mining refining assets merchant energy segment gas processing facility field services segment 1999 charge occurred pipeline segment derived impairments regulatory assets recoverable based settlement rate case impairments periods primarily result weak changing economic conditions causing permanent declines value assets charges taken assets based comparison assets carrying value estimated fair value based future estimated cash flows assets continue held use operations suspended changes accounting estimates 2001 changes accounting estimates consist 232 million additional environmental remediation liabilities 47 million additional accrued legal obligations 38 million charge reduce value spare parts inventories reflect changes usability parts worldwide operations changes primarily result several events occurred part following merger coastal including consolidation numerous operating locations sale majority retail gas stations shutdown midwest refining operations lease corpus christi refinery changes also direct result fire aruba refinery also impacting amounts evaluation operating standards strategies plans combined company following merger charges included operating expenses income statement reduced net income extraordinary items net income year ended december 31 2001 approximately 215 million ceiling test charges full cost method accounting natural gas oil properties perform quarterly ceiling tests evaluate whether carrying value natural gas oil properties exceeds present value future net revenues discounted 10 percent plus lower cost fair market value unproved properties third quarter 2001 capitalized costs exceeded ceiling limit 135 million including 87 million canadian full cost pool 28 million brazilian full cost pool 20 million international production operations primarily turkey charges based november 1 2001 daily posted oil natural gas sales prices 1999 incurred charges related us full cost pool 352 million based end period natural gas oil prices natural gas oil prices used periods adjusted oilfield gas gathering hub wellhead price differences appropriate noncash writedowns included income statement ceiling test charges use financial instruments hedge volatility natural gas oil prices impact hedges considered determination ceiling test charge 2001 factored future ceiling test calculations impact hedges included calculating 2001 ceiling test charge would materially changed since significantly hedge international production activities also mentioned 2001 charge computed based daily posted prices november 1 2001 computed charge based daily oil natural gas prices september 30 2001 charge would approximately 275 million including approximately 227 million canadian full cost pool 48 million brazilian international production operations including impact future cash flows hedging program impact hedging program excluded charges would approximately international full costs pools production operations would incurred additional charge approximately 576 million related us full cost pool results operations results operations along impact segment mergerrelated asset impairment charges discussed extraordinary items accounting changes three years ended december 31 follows 1 proforma amounts used substitute amounts reported generally accepted accounting principles presented solely improve understanding impact charges reported periods presented 2 2001 gains result ftc ordered sales connection coastal merger including sales gulfstream pipeline project midwestern gas transmission system investments empire state stingray ut offshore iroquois pipeline systems 2000 gains result ftc ordered sales connection sonat merger including sales east tennessee sea robin pipeline systems segment results four segments pipelines merchant energy production field services strategic business units offer variety different energy products services requiring different technology marketing strategies evaluate segment performance based earnings interest expense income taxes ebit operating revenues expenses segment include intersegment revenues expenses eliminated consolidation changes energy commodity prices similar impact operating revenues cost products sold period believe gross margin revenue less cost sales provides accurate meaningful basis analyzing operating results trading refining portions merchant energy field services segment discussion individual segments see discussion businesses beginning page 1 well item 8 financial statements supplementary data note 18 discussion analysis operating results business segments results include impact mergerrelated costs asset impairments charges discussed years presented pipelines segment operates interstate pipeline businesses pipeline system operates separate tariff governs operations terms conditions service rates operating results pipeline systems generally stable majority revenues based fixed reservation charges result expect changes aspect business primarily driven regulatory actions system expansions contractual events commodity throughputbased revenues account smaller portion operating results revenues vary period system impacted factors weather operating efficiencies competition pipelines fluctuations natural gas prices results operations pipelines segment follows three years ended december 31 1 throughput volumes exclude related pipeline systems sold connection ftc orders related coastal sonat mergers including midwestern gas transmission east tennessee natural gas sea robin systems destin empire state iroquois pipeline investments throughput volumes exclude intrasegment activities year ended december 31 2001 compared year ended december 31 2000 operating revenues year ended december 31 2001 7 million higher period 2000 increase due higher reservation revenues epng system result larger portion capacity sold maximum tariff rates versus period 2000 impact completed system expansions new storage transportation contracts anr cig 2001 also contributing increase impact higher natural gas prices first second quarters sales segmentowned production sales excess natural gas sales regulated natural gas sales contracts well higher throughput increased deliveries california western states increases partially offset lower 2001 revenues resulting contract remarketing tgp system late 2000 impact sales midwestern gas transmission system april 2001 crystal gas storage september 2000 east tennessee natural gas sea robin systems first quarter 2000 also partially offsetting increase lower 2001 sales base gas abandoned storage fields favorable resolution natural gas pricerelated contingencies cig 2000 lower transportation revenues 2001 tgp result higher proportion short versus long hauls compared 2000 lower remarketed rates seasonal turnedback capacity 2001 result sngs 2000 rate case settlement allowing customers partially reduce firm transportation capacity operating expenses year ended december 31 2001 267 million higher period 2000 primarily result mergerrelated charges 2001 discussed previously also contributing increase impact higher natural gas prices first half 2001 natural gas purchase contracts higher purchase gas costs due net impact natural gas imbalance revaluation 2001 result falling gas prices second half year increases reserve bad debts result exposure connection bankruptcy enron corp onetime favorable adjustment depreciation expense first quarter 2000 result approval ferc reactivate elba island lng facility partially offsetting increase lower operating maintenance expenses due cost efficiencies following merger coastal reduced operating depreciation expenses due sales midwestern gas transmission system april 2001 crystal gas storage september 2000 east tennessee sea robin first quarter 2000 income year ended december 31 2001 25 million lower period 2000 due lower 2001 equity earnings australian pipelines citrus corp owns florida gas transmission system gains sales nonpipeline assets 2000 also contributing decrease impact equity earnings due sales investments empire state iroquois pipeline systems 2001 sale onethird interest destin pipeline company 2000 partially offsetting decrease increased earnings investment alliance pipeline project commenced operations fourth quarter 2000 year ended december 31 2000 compared year ended december 31 1999 operating revenues year ended december 31 2000 15 million lower period 1999 decrease due impact sales east tennessee natural gas sea robin systems first quarter 2000 comply ftc order related merger sonat favorable resolution regulatory issues first quarter 1999 tgp lower rates following sngs may 2000 rate case settlement also contributing decrease impact customer settlements contract terminations 2000 resolutions customer imbalance issues 1999 tgp partially offsetting decrease higher revenues transportation services provided transmission systems due improved average throughput 2000 versus 1999 higher realized prices pipeline gas sales 2000 favorable resolution natural gas pricerelated contingencies 2000 cig revenues january 2000 acquisition crystal gas storage sold september 2000 el paso energy partners operating expenses year ended december 31 2000 104 million lower period 1999 decrease due cost efficiencies following merger sonat lower operating costs due sales east tennessee sea robin first quarter 2000 onetime favorable adjustment depreciation expense first quarter 2000 result approval ferc reactivate elba island facility also contributing decrease expense associated resolution contested rate matter customer epng severance termination charges incurred result sonat merger impairment several sng expansion projects occurring 1999 additionally increase estimated future environmental costs writeoffs duplicate information technology assets 1999 sng following merger sonat contributed decrease partially offset higher gas costs related dakota gasification facility higher system balancing requirements impact unfavorable producer shipper settlements epng income year ended december 31 2000 34 million higher period 1999 increase due higher earnings citrus corp result onetime benefit recorded 2000 higher earnings equity investments 2000 well gains sale nonpipeline assets third quarter 2000 increase partially offset favorable settlement regulatory issue 1999 elimination asset future recovery costs elba island facility lower allowance funds used construction result less expansion construction activity 2000 merchant energy merchant energy segment involved wide range activities wholesale energy markets including asset ownership customer origination marketing trading financial services markets served merchant energy highly competitive influenced directly indirectly energy market economics prior october 2000 coastal conducted marketing trading activities engage energy us lp engage canada lp joint venture coastal westcoast energy inc major canadian natural gas company fourth quarter 2000 coastal terminated engage joint venture commenced marketing trading activities asset ownership merchant energys asset ownership activities include domestic international power plants refining chemical coal mining operations emerging lng business power asset business merchant energy owns interests 95 plants 20 countries segments domestic power activities principally conducted chaparral investors llc unconsolidated affiliate merchant energy 20 percent ownership interest chaparral 1999 formed chaparral subsidiaries chaparral also referred electron owns domestic power assets funded third party capital 80 el paso capital 20 manage daily activities chaparrals assets investments paid annual management fee basic strategy chaparral acquire power facilities attractive power contracts develop facilities operate longterm tolling agreements restructure power sales fuel supply credit agreements purpa facilities monetize restructured arrangements fund operations grow venture operate facilities fully deregulated environment manner enhances value chaparral formed order obtain low cost financing grow new business activities generate stable feebased income stream merchant energys annual management fee equal 20 net present value assets chaparral must approved third party investor net present value npv represents present value anticipated future cash flows chaparrals assets net liabilities less estimated cost liquidate third party capital december 31 2001 chaparral held assets npv totaling approximately 925 million december 31 2001 chaparrals total assets 25 billion liabilities 16 billion total third party capital chaparral approximately 115 billion debt component 10 billion order lower cost debt provided contingent equity support arrangement debt arrangement issued mandatorily convertible preferred stock aggregate liquidation value 10 billion trust control could required sell stock repay third party debt among things credit ratings fall investment grade stock price falls 2707 ten consecutive trading days plan amend arrangement eliminating stock pricecredit downgrade events replace el paso financial guarantee connection balance sheet enhancement plan see discussion balance sheet enhancement plan future liquidity future success chaparral dependent upon ability successfully restructure existing assets chaparral well acquire additional power facilities chaparral may face increased competition future properties facilities increasingly complicated acquire restructure addition renegotiated renewed debt financing supports chaparral matures first quarter 2003 intent renew agreements guarantees financial investors continue participate third party capital available investment merchant energy conducts variety transactions chaparral generates earnings several ways includes performancebased management fee equity earnings chaparrals activities margins risk management activities merchant energy serves commodity provider many chaparrals fuel power purchase contracts chaparral also reimburses merchant energy general administrative expenses incurred behalf 2001 merchant energy earned 147 million management fees chaparral reimbursed 20 million general administrative expenses also recognized 75 million equity earnings 2002 management fee increase approximately 185 million approved chaparrals third party investor fourth quarter 2001 management fee increase reflects growth occurred chaparral asset portfolio assumptions used establishing annual management fee include estimates future energy prices future demand power timing terms contract restructurings future interest rates assumptions based combination quoted market prices rates models project future market changes anticipated demand variables changes assumptions impact annual management fee year changes material time enter transactions chaparral affiliates sell power assets merchant energys fiduciary responsibilities management agreement chaparral require transactions entered fair reasonable values ensure fairness significant transactions evaluated approved third party investor chaparral well board directors 2001 chaparral acquired power assets us fair value 276 million recognize gains losses transactions international power assets gemstone internationally merchant energys power assets consist primarily investments joint ventures construct operate power facilities infrastructure assets around world brazil activities conducted gemstone unconsolidated affiliate merchant energy plans expand power investments country gemstone formed 2001 third party investor primarily generate lowcost funds financing power plants brazil reduce risk introduction third party equity total third party capital gemstone december 31 2001 1 billion debt component 950 million lower cost debt provided contingent equity support arrangement issued mandatorily convertible preferred stock aggregate liquidation value 950 million trust control could required sell stock repay debt among things credit ratings fall investment grade stock price falls 3616 ten consecutive trading days addition renegotiated renewed debt financing supports gemstone matures 2004 plan amend arrangement eliminating stock pricecredit downgrade events replace el paso financial guarantee connection balance sheet enhancement plan see discussion balance sheet enhancement plan future liquidity brazils power infrastructure primarily based use hydroelectric power generation success gemstone future based demand natural gas fired generation brazil may significantly impacted availability competing generation hydroelectric power generation less expensive operate abundant furthermore numerous risks operating internationally could impact gemstones ultimate success earnings merchant energys international power activities including gemstone derived primarily equity earnings investments dependent ultimate success privately owned power generation infrastructure development countries merchant energy business 2001 merchant energy recorded net equity earnings gemstone 2 million refining chemical coal mining lng addition power business merchant energy refining chemical coal mining operations emerging global lng operation results merchant energys refining chemical operations highly dependent margin differentials feedstocks primarily crude oil petroleum products market prices products produced highly volatile coal business results driven productivity mining operations along market prices coal produced 2001 merchant energy increased scope activities lng full operations expected 2003 2004 success business based substantially worldwide supply natural gas demand lng depend strong natural gas prices lng shipping terminalling infrastructure customer origination marketing trading merchant energys customer origination marketing trading activities provide energy supply risk management solutions customers affiliates involving natural gas power crude oil refined products chemicals coal merchant energy assists customers energy supply aggregation storage transportation management provides array risk management products merchant energy also conducts substantial energy trading business executes proprietary trading strategies manages segments risk across multiple commodities seasonally fluctuating energy demands using consistent methodologies 2001 2000 us energy supply demand resulted substantial volatility energy markets significantly impacted merchant energys earnings merchant energys customer origination marketing trading groups account activities using marktomarket accounting method financial instruments physical commodity positions contractual energyrelated transactions recorded balance sheet income statement fair value time entered subsequent inception transactions continue adjusted balance sheet income statement changes fair value settled determining fair value positions inception settlement principally involves use actively quoted prices lesser degree valuation methods including models rely actively quoted prices approximately 9 value marktomarket portfolio based model valuations ie active market quotes models optionsbased valuations involve contracts related physical assets examples contracts generally valued using models include natural gas pipeline capacity natural gas storage contracts lesser extent power plant tolling agreements modeling allows us value contracts well manage effectively providing lower cost service customers effectively measure manage risk associated daily basis almost modelbased valuations employ spread option valuations location spread options pipeline capacity time spread options natural gas storage capacity spark spread options natural gasfired power plant tolling price data underlying models based part market data estimates future prices periods market data limited important variable models volatility prices underlying contracts correlation prices underlying contracts limited market price data related correlations volatilities although significant implicit data exist use implicit market data historical data determine volatilities correlation calculation models believe calculations reliable predictors value time addition merchant energy maintains risk controls group verifies market price data accuracy independently marketing trading groups group conducts activities actively quoted modelderived information extent uncertainty amounts ultimately realize transactions adjust amounts recognize income uncertainties resolved estimates adjusted assumptions change transactions move closer settlement better estimates become available december 31 2001 fair value tradingrelated price risk management activities 1295 million total margins generated activities 2001 690 million following table details fair value merchant energys price risk management activities year maturity valuation methodology amounts reflected prices actively quoted based values determined market quotes actively traded data primarily nymex exchangebased information including broker quotes amounts reflected prices based models valuation methods represent fair value contracts calculated based internal models using methods discussed fair value trading price risk management contracts december 31 2001 reconciliation 2001 trading activities follows millions 1 december 31 2001 net assets nontrading price risk management activities 426 million total net assets price risk management activities 1721 million fair value contracts settled period represents amounts traded contracts settled cash physical delivery commodity claim cash accounts receivable payable initial recorded value new contracts includes fair value origination transactions time transaction initiated change fair value contracts year represents change value contracts beginning period date origination settlement settled end period included change fair value contracts year net loss 109 million related changes market values contracts transferred trading portfolio result change manner contracts managed following coastal merger included effect natural gas storage purchases premiums paid option contracts financial services financial services area merchant energy conducts energy financing activities ownership encap enerplus encap manages four separate oil natural gas investment funds us serves investment advisor one fund europe encap also facilitates investment emerging energy companies earns return investments enerplus acquired 2000 canadian investment management company conducts fund management activities similar encap canada results merchant energys financial services activities based combination management fees market based earnings investments held companies merchant energys operating results traded volumes excluding intrasegment transactions analysis results three years ended december 31 year ended december 31 2001 compared year ended december 31 2000 trading refining gross margin consists revenues commodity trading origination activities less costs commodities sold well revenues refineries chemical plants less cost feedstocks used refining production processes year ended december 31 2001 gross margins 199 million higher period 2000 increase primarily due higher trading margins natural gas power crude oil refined products result increased trading volumes price volatility well increased income transactions originated 2001 increase trading margins partially offset negative margins refining resulting fire aruba facility april 2001 lease corpus christi refinery related assets valero june 2001 lower margins heavy crude based refined products lower margins throughput eagle point refinery result decreased demand jet fuel following events september 11 2001 also offsetting increase reserves established result bankruptcy enron corp december 2001 merchant energy conducted trading activities held derivative positions enron corp subsidiaries december 2001 enron certain subsidiaries sought protection creditors chapter 11 us bankruptcy code following filing merchant energy terminated contracts enron subsidiaries filed bankruptcy resulted transfer merchant energys net derivative positions enron price risk management activities accounts receivable addition merchant energy established reserves receivables believes adequate based amounts expects collect bankruptcy first quarter 2002 merchant energy asserted claim enron cancelled contracts merchant energy provider power natural gas state california latter half 2000 continuing first half 2001 california experienced sharp increases wholesale power prices natural gas prices due energy shortages resulting part combination unusually warm summer weather followed high winter demand low gas storage levels lower hydroelectric power generation maintenance downtime significant generation facilities result two major california utilities southern california edison pacific gas electric defaulted payments creditors accumulated substantial undercollections customers resulted credit ratings downgraded 2001 investment grade investment grade april 2001 pacific gas electric filed bankruptcy 2001 recognized revenues pacific gas electric southern california edison believe appropriate based improving financial condition resulted recognition income portion transactions fourth quarter based improved credit exposure customers state operating revenues consist revenues domestic international power generation facilities investments including management fee chaparral coal operations revenues encap financial services business merchant energy year ended december 31 2001 operating revenues 77 million higher period 2000 increase resulted higher management fees chaparral higher revenues encap financial services due growth businesses revenues cebu power project philippine project acquired additional interest began consolidating first quarter 2001 offsetting increase revenues recorded 2000 west georgia power generation facility sold fourth quarter 2000 operating expenses year ended december 31 2001 450 million higher period 2000 increase primarily result mergerrelated costs asset impairments associated combining operations coastal changes estimates environmental remediation costs legal obligations spare parts inventory usability also contributing increase higher operating expenses resulting expansion operations europe mexico brazil singapore liquefied natural gas business consolidation cebu power project increase also resulted higher fuel costs refineries due higher natural gas prices increases partially offset lower operating expenses resulting lease corpus christi refinery related assets valero june 2001 2000 costs related west georgia plant sold fourth quarter 2000 income year ended december 31 2001 142 million higher period 2000 increase result marketing agency technical services fees related development macae power project brazil higher equity earnings chaparral investment capital district energy power facility resulting primarily completion power contract restructurings increases partially offset lower earnings argentine investment gains sale portion east asia power project sale interest guatemala power project occurring 2000 also offsetting increase lower earnings javelina project due reduced margins year ended december 31 2000 compared year ended december 31 1999 trading refining gross margin year ended december 31 2000 512 million higher period 1999 trading margins increased due significant price volatility natural gas power crude oil refined products markets increased value trading portfolio 2000 versus 1999 refining margins increased resulting increase sales volumes primarily due expansion aruba refinery increased prices refined products 2000 improved brokerage margins also contributing increase higher income transactions originated 2000 operating revenues year ended december 31 2000 222 million higher period 1999 increase due asset management fees earned chaparral began operations fourth quarter 1999 revenues west georgia power project seasonal peaking facility began operating june 2000 consolidation brazilian power project latter part 1999 revenues manchief power project began operating july 2000 encaps financial services activities 2000 also contributed increase operating expenses year ended december 31 2000 184 million higher period 1999 increase due higher general administrative expenses project development costs relating international projects 2000 well higher repair maintenance expense fuel costs relating increased volumes refining operations also contributing increase fuel costs relating west georgia power project higher depreciation expense relating rensselaer generating facility acquired 1999 operating costs manchief generation facility increases partially offset higher reimbursement 2000 general administrative costs relating chaparral 1999 charge eliminate minority investor sonats marketing joint venture following sonat merger 1999 asset writedowns charges consolidate accounting policies sonat following merger income year ended december 31 2000 118 million higher period 1999 increase due higher earnings ce generation power project acquired march 1999 benefit realized formation east asia power joint venture march 2000 gain sale interest guatemala power generation facility also contributing increase increased earnings engage prior termination joint venture gain recorded 2000 sale 49 percent montreal paraxylene facility increases partially offset lower equity earnings investments various international projects primarily investment east asia power philippines production productions operating results driven variety factors including ability locate develop economic natural gas oil reserves extract reserves minimal production costs sell products attractive prices operate lowest cost level possible 2002 production expects continue active onshore offshore development drilling program capitalize land seismic holdings estimated capital expenditures production 2002 17 billion production continue pursue strategic acquisitions production properties development coal seam projects subject acceptable return hurdles production engages hedging activities natural gas oil production order stabilize cash flows reduce risk downward commodity price movements sales production achieved primarily natural gas oil swaps 2001 approximately 80 percent segments overall production hedged fixed prices hedging program intended hedge approximately 75 percent anticipated current year production approximately 50 percent anticipated succeeding year production lesser percentage thereafter productions hedge positions monitored evaluated effort achieve earnings objectives reduce risks associated spotmarket price volatility december 2001 announced sale natural gas oil properties connection balance sheet enhancement plan see discussion plan future liquidity operating results analysis results three years ended december 31 year ended december 31 2001 compared year ended december 31 2000 operating revenues year ended december 31 2001 661 million higher period 2000 increase attributable higher volumes higher realized prices natural gas higher volumes oil condensate liquids 2000 transportation net product costs year ended december 31 2001 19 million higher period 2000 primarily due higher transported volumes costs incurred meet minimum payments pipeline agreements operating expenses year ended december 31 2001 336 million higher period 2000 increase due full cost ceiling test charges 135 million international properties incurred third quarter 2001 higher depletion expense 2001 result increased production volumes combined higher capitalized costs full cost pool mergerrelated costs increased oilfield service costs 2001 also contributing increase higher severance production taxes 2001 resulting higher production volumes higher gas prices year ended december 31 2000 compared year ended december 31 1999 operating revenues year ended december 31 2000 578 million higher period 1999 increase due increased volumes higher realized prices natural gas oil condensate liquids transportation net product costs year ended december 31 2000 31 million higher period 1999 primarily due higher transported volumes costs incurred meet minimum production quantities pipeline agreements operating expenses year ended december 31 2000 152 million lower period 1999 decrease due full cost ceiling test charges 352 million incurred first quarter 1999 decreased 2000 labor costs result organizational restructuring following sonat merger 1999 charges retain sonats seismic data production operations result merger decreases partially offset higher 2000 depletion rates higher production taxes higher production costs field services field services segment provides variety services midstream component operations including gathering treating natural gas processing fractionation natural gas natural gas liquids natural gas derivative products butane ethane propane field services also serves general partner el paso energy partners lp field services attempts balance earnings operating activities combination fixedfee based marketbased services majority field services gathering treating operations earn margins fixedfeebased services however operations earn margins marketbased rates revenues marketbased rate services product market price usually related monthly natural gas price index volume gathered processing fractionation operations earn margin based fixedfee contracts percentageofproceeds contracts makewhole contracts percentageofproceeds contracts allow us retain percentage product fee processing fractionation service makewhole contracts allow us retain extracted liquid products return producer btu equivalent amount natural gas percentageofproceeds contracts makewhole contracts field services may sensitivity price changes periods natural gas natural gas liquids prices volatile general partner el paso energy partners perform partnerships daily operations provide strategic direction performs administrative operational activities reimbursed 34 million services 2001 addition recognized 47 million equity earnings 2001 el paso energy partners related general partner common preferred units ownership interests often enter transactions el paso energy partners affiliates acquire sell assets specific procedures instituted evaluating transactions ensure best interests us partnership based fair values procedures require board directors evaluate approve appropriate transactions partnership addition special committee comprised general partners independent directors evaluates transactions partnerships behalf typically involves engaging independent financial advisor independent legal counsel assist evaluation opine fairness 2001 sold several assets partnership including transportation fractionation assets acquired pge investment deepwater holdings entity owned several pipeline gathering systems gulf mexico 2001 partnership also acquired rights chaco processing facility previous owners currently lease facility agreement expires october 2002 2000 sold intrastate pipeline system alabama storage facilities mississippi partnership transactions evaluated approved appropriate board directors general partners committee independent directors proceeds sales assets partnership 344 million 2001 197 million 2000 proceeds include 170 million series b preference units issued us exchange storage facilities recognized aftertax gain sales 13 million 2001 gain loss recognized sales 2000 february 2002 part balance sheet enhancement plan announced sale additional midstream assets el paso energy partners total consideration 750 million primary assets sold include 9400 miles intrastate transmission pipelines 1300 miles gathering systems permian basin 423 percent nonoperating interest indian basin gas processing treating plant associated gathering lines proceeds approximately 554 million cash approximately 6 million el paso energy partners common units along partnerships interest prince tension leg platform nine percent overriding royalty interest partnership holds prince field combined fair value estimated 190 million expect complete transaction march 2002 sale assets contingent upon receiving customary regulatory approvals execution definitive agreements anticipate material gain loss transactions addition field services several segments also enter transactions el paso energy partners normal course business sale natural gas services transportation fractionation storage processing types operational services transactions based similar terms transactions nonaffiliates field services operating results analysis results follows three years ended december 31 2001 year ended december 31 2001 compared year ended december 31 2000 total gross margin year ended december 31 2001 124 million higher period 2000 increase primarily due higher volumes result acquisition pges texas midstream operations december 2000 volumes also increased result acquisition indian basin processing plant second quarter 2000 combined increase indian basins processing capacity 2001 increase margin partially offset higher processing costs associated new processing arrangement el paso energy partners chaco processing facility fourth quarter 2001 year ended december 31 2001 average gathering treating processing rates lower compared 2000 due primarily different mix assets contract terms resulting acquisition pges texas midstream operations operating expenses year ended december 31 2001 162 million higher period 2000 increase due higher operating depreciation expenses primarily resulting addition pges texas midstream operations well mergerrelated costs related ftc ordered sales assets owned el paso energy partners mergerrelated employee severance relocation expenses merger charges changes estimated environmental remediation liabilities 2001 income year ended december 31 2001 19 million higher period 2000 increase primarily due increased earnings el paso energy partners gain sale interest deepwater holdings october 2001 partially offset lower 2001 equity earnings deepwater holdings result sale increase also partially offset equity investment losses mobile bay aux sable liquids processing facilities due low natural gas liquids prices 2000 gain sale colorado dry gathering system year ended december 31 2000 compared year ended december 31 1999 total gross margin year ended december 31 2000 148 million higher period 1999 increase result higher gathering treating margins due higher average gathering rates predominantly san juan basin substantially indexed natural gas prices higher average condensate prices higher 2000 margin partially offset sale el paso intrastate alabama gathering system coalbed methane producing regions alabama el paso energy partners march 2000 processing margins also higher due higher natural gas natural gas liquids prices 2000 acquisition indian basin processing plant second quarter 2000 higher processing volumes due acquisition gas processing fractionation facilities located louisiana end 1999 operating expenses year ended december 31 2000 56 million higher period 1999 due higher depreciation amortization assets transferred el paso natural gas field services following ferc order impairment needle mountain lng processing facility 2000 higher expenses coastals gas processing plants result acquisition processing fractionation assets located louisiana 1999 increase partially offset impairment gathering assets 1999 lower costs labor benefits cost recoveries managed facilities income year ended december 31 2000 8 million lower period 1999 decrease primarily due net gains 1999 sale interest viosca knoll gathering system el paso energy partners june 1999 well lower equity earnings 2000 following sale interest viosca knoll corporate expenses net corporate operations includes general administrative activities well operations telecommunications miscellaneous businesses 2001 significant downturn telecommunications market result refocused telecommunications strategy reduced capital investment startup business current business strategy involves primarily development wholesale metropolitan transport services primarily texas december 31 2001 investment telecommunications business 555 million year ended december 31 2001 compared year ended december 31 2000 corporate expenses year ended december 31 2001 1372 million higher period 2000 increase primarily result mergerrelated charges connection january 2001 merger coastal costs associated increased estimates environmental remediation costs legal obligations usability spare parts inventories lower margins due sale substantially retail gas stations 2001 also contributing higher costs operating losses associated telecommunications business 2001 approximately 72 million year ended december 31 2000 compared year ended december 31 1999 corporate expenses year ended december 31 2000 230 million lower period 1999 decrease primarily due costs related merger sonat 1999 partially offset costs incurred 2000 related merger coastal also offsetting decrease increased funding commitments el paso energy foundation 2000 interest debt expense year ended december 31 2001 compared year ended december 31 2000 interest debt expense year ended december 31 2001 115 million higher period 2000 increase result higher longterm shortterm borrowings lower capitalized interest 2001 ongoing capital projects investment programs operating requirements year ended december 31 2000 compared year ended december 31 1999 interest debt expense year ended december 31 2000 264 million higher period 1999 primarily due increased borrowings combination shortterm longterm programs fund capital expenditures acquisitions investing activities higher average interest rates 2000 increased interest expense borrowings chaparral 2000 increase partially offset increase interest capitalized minority interest year ended december 31 2001 compared year ended december 31 2000 minority interest year ended december 31 2001 13 million higher period 2000 higher balances minority interests result issuance additional preferred interests clydesdale associates lp topaz investors llc part gemstone transaction full year costs clydesdale el paso energy capital trust iv significantly offset lower interest rates clydesdale capital trust iv formed may 2000 year ended december 31 2000 compared year ended december 31 1999 minority interest year ended december 31 2000 111 million higher period 1999 primarily due full year costs associated preferred interest trinity river associates llc formed june 1999 also contributing increase costs associated preferred interest clydesdale associates lp distributions associated preferred securities el paso energy capital trust iv formed may 2000 discussion borrowing financing activities period see securities subsidiaries minority interests income tax expense income tax expense year ended december 31 2001 182 million resulting effective tax rate 73 percent amount 115 million related nondeductible merger charges changes estimate additional tax liabilities majority estimated additional liabilities paid 2001 contested us effective tax rate excluding charges 27 percent years ended december 31 2000 1999 income tax expense 538 million 93 million resulting effective tax rates 30 percent 27 percent differences effective tax rates statutory tax rate 35 percent years primarily result following factors state income taxes earnings unconsolidated affiliates anticipate receiving dividends nondeductible portion mergerrelated costs tax adjustments provide revised estimated liabilities foreign income taxed different rates utilization deferred credits loss carryovers nondeductible dividends preferred stock subsidiary nonconventional fuel tax credits depreciation depletion amortization reconciliation statutory rate 35 percent effective rates see item 8 financial statements supplementary data note 6 liquidity capital resources general year ended december 31 2001 generated 9 billion cash combination cash operations issuance longterm debt financing obligations issuance equity cash used capital expenditures acquisitions investing activities longterm debt repayments dividends financing activities following discussion operating investing financing cash flows year ended december 31 2001 cash operating activities net cash provided operating activities 41 billion year ended december 31 2001 compared 99 million 2000 increase primarily due growth cashbased earnings 2001 resulting higher realized prices volumes production segment along physical liquidations net derivative trading positions related price risk management activities partially offsetting increases cash payments 2001 charges related merger coastal higher interest payments cash investing activities net cash used investing activities 50 billion year ended december 31 2001 investing activities principally consisted additions property plant equipment including expenditures developmental drilling expansion construction projects additions joint ventures investments unconsolidated affiliates primarily related investment gemstone along investments five coalfired power plants international power companies located brazil china additions investments also consisted shortterm notes unconsolidated affiliates notes primarily related subsidiary chaparral significant portion notes repaid 2001 august 2001 completed acquisition velvet exploration ltd canadian exploration development company properties located foothills deep basin areas western alberta province canada cost approximately 230 million cash inflows investmentrelated activities included proceeds sale manchief power facility chaparral midwestern gas transmission system gulfstream pipeline project property plant equipment assets along proceeds sale substantially retail gas stations 2001 additional cash inflows included sale interests empire state iroquois pipeline systems liquidation health management investment portfolio cash financing activities net cash provided financing activities 13 billion year ended december 31 2001 cash provided financing activities included issuance longterm debt financing obligations notes unconsolidated affiliates primarily related gemstone also issuances common stock result equity offering december 2001 exercise employee stock options well issuance preferred securities related one consolidated subsidiaries associated gemstone 2001 repaid shortterm borrowings financing obligations retired longterm debt paid dividends also repaid notes unconsolidated affiliates primarily related chaparral gemstone significant borrowing repayment activities 2001 presented amounts include borrowings repayments shortterm financing instruments original maturity three months less including commercial paper programs shortterm credit facilities 1 net proceeds primarily used repay shortterm longterm borrowings general corporate purposes 2 debentures convertible 8456589 shares common stock based conversion rate 47872 shares per 1000 principal amount maturity rate equivalent initial conversion price 94604 per share common stock 3 march 2001 issued e550 million approximately 510 million euro notes 575 due 2006 reduce exposure foreign currency risk entered swap transaction exchanging euro note 510 million us dollar denominated obligation fixed interest rate 661 fiveyear term note 4 loan collateralized lease payments valero corpus christi refinery related assets interest rate loan london interbank offered rate libor plus 1425 reduce exposure interest rate risk entered swap transaction notional amount 240 million exchanging libor fixed rate 307 transaction results payment fixed rate 4495 swap terminates june 2003 december 2001 issued 203 million shares common stock price 4250 per share net proceeds approximately 863 million used retire shortterm debt general corporate purposes credit facilities available capacity use commercial paper programs manage shortterm cash requirements programs borrow 3 billion combination individual corporate tgp epng commercial paper programs 1 billion maintain 3year 1 billion revolving credit competitive advance facility conduct shortterm borrowings commercial credit transactions facility expires 2003 el paso cgp formerly coastal epng tgp designated borrowers facility june 2001 replaced existing 364day revolving credit facility renewable 3 billion 364day revolving credit competitive advance facility epng tgp also designated borrowers new facility interest rate facilities varies based libor plus 50 basis points december 31 2001 amounts outstanding facilities december 31 2001 connection acquisition pges texas midstream operations december 2000 established 700 million shortterm credit facility 455 million outstanding december 31 2000 february 2001 borrowed additional 245 million facility two separate payments march june 2001 repaid outstanding balance credit facility terminated also supplement commercial paper program smaller shortterm credit facilities used coastal prior merger terminated year april 2001 filed shelf registration statement securities exchange commission sell time total 3 billion debt securities preferred common stock medium term notes trust securities december 31 2001 approximately 920 million remaining shelf registration statement issued additional securities january 2002 december 31 2001 tgp 200 million sng 100 million shelf registration statements file securities exchange commission availability borrowings credit borrowing agreements subject specified conditions believe currently meet conditions include compliance financial covenants ratios required agreements absence default agreements continued accuracy representations warranties contained agreements senior unsecured debt issues given investment grade ratings standard poors moodys 2002 activities january 2002 increased shelf registration statement 920 million 110 billion issued 110 billion aggregate principal amount 775 medium term notes due 2032 net proceeds approximately 108 billion net issuance costs used repay shortterm borrowings general corporate purposes issuance used remaining capacity previous shelf registration statement february 2002 filed new shelf registration statement securities exchange commission allows us issue 3 billion registration statement issue combination debt equity instruments including trust preferred securities el paso capital trust ii el paso capital trust iii trusts wholly owned us issue securities trusts required issue full unconditional guarantees securities also january 2002 retired 100 million aggregate principal amount 785 notes 215 million aggregate principal amount 775 notes march 2002 retired 400 million floating rate notes january 2002 sng filed shelf registration statement increasing amount debt issue 100 million 300 million february 2002 sng issued 300 million aggregate principal amount 80 notes due 2032 net proceeds approximately 297 million net issuance costs used general corporate purposes issuance used remaining capacity sngs shelf registration statement future liquidity rely cash generated internal operations primary source liquidity supplement internally generated cash commercial paper programs available credit facilities bank financings issuance longterm debt trust securities equity securities time also use structured financial products expect future funding working capital needs capital expenditures acquisitions investing activities longterm debt repayments dividends financing activities continue provided sources cash internal operations may change future due number factors cannot control including price receive products sell services provide demand products services margin requirements resulting significant increases decreases commodity prices operational risks factors ability draw upon available credit facilities dependent upon ability comply conditions requirements credit facilities believe currently meet funding capital markets commercial paper longterm debt equity structured financial products may impacted lack liquidity industry segment change credit rating changes market conditions discussion business risks see risk factors december 2001 announced plan strengthen capital structure enhance liquidity response changes market conditions january 2002 board directors approved plan key elements plan raise approximately 225 billion cash sales assets reduce net capital spending approximately 31 billion 2002 increase common equity combination earnings equity financings eliminate renegotiate rating triggers chaparral gemstone investments trinity river clydesdale minority interest financing transactions goal plan reduce debt total capital ratio 549 percent december 31 2001 approximately 50 percent end 2002 december 2001 issued 203 million shares common stock generating 863 million also expect firm sales agreements completed half asset sales end first quarter 2002 first step accomplished february 2002 announcement sale midstream assets el paso energy partners total consideration approximately 750 million additional assets evaluated may possibly included asset sale program include approximately 1 billion exploration production properties various refining chemical assets coal mining assets power facilities actual assets sold depend number factors including shortterm market developments availability qualified buyers acceptability offers received addition potential losses writedowns value assets could occur proposed offer evaluated approved committee board directors prior completion intend commence exchange offers existing note holders chaparral gemstone eliminate rating triggers replace securities direct financial guarantees us expect complete exchange offers second quarter 2002 also expect commence amendment process trinity river clydesdale transactions early 2002 discussion risks may affect balance sheet enhancement plan see risk factors contractual obligations commercial commitments course business activities enter variety contractual obligations commercial commitments result direct obligations reflected balance sheet others commitments firm based uncertainties reflected underlying financial statements contractual cash obligations following table summarizes contractual cash obligations payment due date obligations discussed detail millions 1 longterm cash obligations exclude 75 million unamortized debt discounts december 31 2001 2 maturity schedule instruments based expiration period underlying agreements shortterm cash obligations shortterm contractual cash obligations december 31 2001 follows millions borrow 3 billion combination corporate tgp epng commercial paper programs 1 billion december 31 2001 weighted average rate commercial paper outstanding 32 also shortterm notes payable banks 139 million short term credit facilities 111 million longterm cash obligations longterm cash obligations december 31 2001 follows millions unsecured notes debentures consists thirdparty debt issued normal course business activities notes secured general credit subsidiaries interest rates instruments range 575 1075 maturity dates range 2002 2037 zero coupon convertible debentures maturity value 18 billion due 2021 yield maturity 4 debentures convertible 8456589 shares common stock based conversion rate 47872 shares per 1000 principal amount maturity rate equal conversion price 94604 per share common stock october 2001 borrowed 240 million due 2004 loan agreement loan collateralized lease payments valero lease corpus christi refinery 1999 issued total 18400000 feline pridessm consisting 17000000 income prides stated value 25 1400000 growth prides stated value 25 income prides consist unit comprised senior debenture purchase contract holder obligated purchase us later august 16 2002 25 stated price number shares common stock growth prides consist unit comprised purchase contract holder obligated purchase us later august 16 2002 25 stated price number shares common stock 25 undivided beneficial interest threeyear treasury security principal amount maturity equal 1000 terms purchase contract effect prior merger coastal number shares common stock holder pride received varied 05384 06568 shares depending price coastals common stock result merger coastal terms purchase contract number shares holder pride entitled required receive upon settlement became fixed 06622 shares el paso common stock result issuance approximately 122 million shares el paso common stock financing obligations consist crude oil prepayments received third parties exchange agreement deliver fixed quantity crude oil specified delivery point future production payment received exchange delivery fixed quantity natural gas future production agreements terms settled delivery commodity entered commodity swaps effectively lockin value commitments third party upon delivery commodity intention negotiate cash settlement crude oil prepayments prior delivery dates agreements continue deliver natural gas production payment agreement according terms consider agreements financing arrangements carrying cost prepayments production payment recognized interest expense income statement obligations affiliates obligations unconsolidated affiliates december 31 2001 follows millions gemstone obligation gemstone consists 346 million debt securities payable demand carry fixed interest rate 525 chaparral obligation chaparral consists 169 million debt securities 289 million contingent interest promissory notes debt securities payable demand carry fixed interest rate 7443 contingent interest promissory notes carry variable interest rate exceed 1275 mature 2019 2021 obligations affiliates include line credit unconsolidated affiliate 57 million interest rate 527 miscellaneous notes several unconsolidated affiliates 11 million average interest rate 245 december 31 2001 securities subsidiaries minority interests past three years entered number transactions finance consolidated subsidiaries cases accomplished sale preferred interests entities structured financial transactions collateralized assets subsidiaries total amounts outstanding programs december 31 2001 follows millions 1 consolidated trusts composed capital trust coastal finance capital trust iv capital trust march 1998 formed el paso energy capital trust issued 65 million 4 34 trust convertible preferred securities 325 million common securities trust exists sole purpose issuing preferred securities investing proceeds 4 34 convertible subordinated debentures due 2028 sole asset provide full unconditional guarantee trust preferred securities trust preferred securities reflected companyobligated preferred securities consolidated trusts balance sheet distributions paid preferred securities included minority interest income statement trust preferred securities nonvoting except limited circumstances pay quarterly distributions annual rate 4 34 carry liquidation value 50 per security plus accrued unpaid distributions convertible common shares time prior close business march 31 2028 option holder rate 12022 common shares trust preferred security equivalent conversion price 4159 per common share december 31 2001 approximately 65 million trust preferred securities outstanding coastal finance may 1998 coastal completed public offering 12 million mandatory redemption preferred securities coastal finance business trust 300 million coastal finance holds debt securities purchased proceeds preferred securities offering cumulative quarterly distributions paid preferred securities annual rate 8375 liquidation amount 25 per preferred security preferred securities mandatorily redeemable maturity date may 13 2038 may redeemed option may 13 2003 earlier various events occur redemption price paid 25 per preferred security plus accrued unpaid distributions date redemption capital trust iv may 2000 formed el paso energy capital trust iv issued 300 million preferred securities third party investor preferred securities pay cash distributions floating rate equal threemonth libor plus 75 basis points december 31 2001 floating rate 283 preferred securities must redeemed trust iv later november 30 2003 proceeds sale securities used trust iv purchase series floating rate senior debentures whose yield maturity terms mirror trust ivs preferred securities sole assets trust iv floating rate senior debentures provide full unconditional guarantee obligations trust iv related preferred securities time trust iv issued preferred securities also agreed issue 300 million equity securities including limited common stock one public offerings prior may 31 2003 trinity river also known red river 1999 formed series companies refer trinity river trinity river formed provide financing invest various capital projects assets thirdparty investor contributed cash 980 million trinity river 1999 exchange preferred securities one consolidated subsidiaries third party entitled adjustable preferred return derived trinity rivers net income preferred interest collateralized combination notes payable us various fixed assets including mojave pipeline bear creek storage various natural gas oil production properties el paso energy partners common units option acquire thirdpartys interest trinity river time prior june 2004 exercise option agreement extended could required liquidate assets supporting transaction account investors preferred interest consolidated subsidiary minority interest balance sheet preferred return minority interest expense income statement assets liabilities operations trinity river included financial statements credit ratings downgraded investment grade sp moodys could required liquidate assets supporting transaction clydesdale also known mustang 2000 formed series companies refer clydesdale formed provide financing invest various capital projects assets thirdparty investor contributed cash 1 billion clydesdale exchange preferred securities one consolidated subsidiaries third party entitled adjustable preferred return derived clydesdales net income preferred interest collateralized combination notes payable us various fixed assets including colorado interstate gas transmission system natural gas oil properties option acquire thirdpartys interest clydesdale time prior may 2005 exercise option agreement extended could required liquidate assets supporting transaction account investors preferred interest consolidated subsidiary minority interest balance sheet preferred return minority interest expense income statement assets liabilities operations clydesdale included financial statements credit ratings downgraded investment grade sp moodys could required liquidate assets supporting transaction el paso tennessee preferred stock 1996 el paso tennessee pipeline co subsidiary issued 6 million shares publicly registered 825 cumulative preferred stock par value 50 per share 300 million preferred stock redeemable option el paso tennessee redemption price equal 50 per share plus accrued unpaid dividends time january 2002 three years ended december 31 2001 dividends approximately 25 million paid year preferred stock coastal securities company preferred stock 1996 coastal securities company limited wholly owned subsidiary issued 4 million shares preferred stock 100 million quarterly cash dividends paid preferred stock rate based libor preferred shareholders also entitled participating dividends based various refining margins coastal securities may redeem preferred stock cash liquidation price plus accrued unpaid dividends coastal oil gas resources preferred stock 1999 coastal oil gas resources inc wholly owned subsidiary issued 50000 shares preferred stock 50 million preferred shareholders entitled quarterly cash dividends rate based libor dividend rate subject renegotiation 2004 fifth anniversary thereafter event coastal oil gas resources preferred shareholders unable agree new rate coastal oil gas resources must redeem shares 1000 per share plus accrued unpaid dividends cause preferred stock registered securities exchange commission remarketed coastal oil gas resources also option redeem shares dividend rate reset date 1000 per share plus accrued unpaid preferred dividends coastal limited ventures preferred stock 1999 coastal limited ventures inc wholly owned subsidiary issued 150000 shares preferred stock 15 million preferred shareholders entitled quarterly cash dividends annual rate 6 dividend rate subject renegotiation 2004 fifth anniversary thereafter event coastal limited preferred shareholders unable agree new rate preferred shareholders may call redemption preferred shares redemption price 100 per share plus accrued unpaid preferred dividends thereon coastal limited also option redeem shares rate reset date 100 per share plus accrued unpaid preferred dividends gemstone part gemstone transaction wholly owned subsidiary topaz investors llc issued minority member interest third party investor gemstone 300 million third party investor entitled cumulative preferred return 803 interest agreements underlying transaction expire 2004 earlier sell international power assets owned indirectly topaz minority member interest redeemable liquidation value plus accrued unpaid dividends consolidated partnership december 1999 coastal limited contributed assets limited partnership exchange controlling general partnership interest limited interests partnership issued unaffiliated investors 285 million limited partners entitled cumulative priority return based libor return subject renegotiation 2004 fifth anniversary thereafter partnership maximum life 20 years may terminated sooner subject certain conditions including failure agree new rate coastal limited may terminate partnership time repayment limited partners outstanding capital plus unpaid priority returns operating leases maintain operating leases ordinary course business activities leases include office space operating facilities office operating equipment terms agreements vary 2002 2053 december 31 2001 total commitments operating leases approximately 677 million several leases provided residual value guarantees lessor guarantees either choose purchase asset end lease term specified amount typically equal outstanding loan amounts owed lessor choose assist sale leased asset third party asset sold price equals exceeds amount guarantee would obligated shortfall levels residual value guarantees range 860 percent 899 percent original cost leased assets total outstanding residual value guarantees operating leases december 31 2001 see residual value guarantees capital commitments purchase obligations december 31 2001 capital investment commitments 24 billion primarily relating production pipeline international power activities planned capital investment projects discretionary nature substantial capital commitments made advance actual expenditures entered unconditional purchase obligations products services totaling 346 million december 31 2001 annual obligations agreements 34 million 2002 32 million 2003 34 million years 2004 2005 2006 178 million total thereafter commercial commitments following table summarizes commercial commitments date expiration commitments discussed detail lines credit commitment loan mesquite subsidiary chaparral affiliate 725 million december 31 2001 mesquite borrowed 552 million facility resulting undrawn commitment 173 million interest rate facility based libor plus margin 264 december 31 2001 letters credit enter letters credit ordinary course operating activities december 31 2001 outstanding letters credit 465 million related marketing trading activities domestic power development operating activities guarantees involvement joint ventures project level construction finance results issuance financial nonfinancial guarantees business activities also guarantee performance contractual commitments companies within consolidated group various events circumstances may require us perform guarantees including nonpayment guaranteed party noncompliance covenants transactions guaranteed party noncompliance us provision guarantees crossacceleration transactions december 31 2001 approximately 15 billion guarantees connection international development operating activities consolidated balance sheet approximately 19 billion guarantees connection domestic development operating activities consolidated balance sheet amounts approximately 950 million relates gemstone investment 10 billion relates chaparral investment residual value guarantees december 31 2001 738 million residual value guarantees supporting operating leases expire 2002 2006 commercial commitments may october 2001 entered agreements timecharter four separate ships secure transportation developing liquefied natural gas business agreements provide deliveries vessels 2003 2005 timecharter 20year term commencing vessels delivered possibility two 5year extensions total commitment four time charter agreements 18 billion contingencies discussion contingencies see item 8 financial statements supplementary data note 14 incorporated herein reference critical accounting policies selection application accounting policies important process developed business activities evolved accounting rules developed accounting rules generally involve selection among alternatives involve implementation interpretation existing rules use judgment specific set circumstances existing business make every effort properly comply applicable rules adoption believe proper implementation consistent application accounting rules critical however situations specifically addressed accounting literature cases must use best judgment adopt policy accounting situations accomplish analogizing similar situations accounting guidance governing often consult independent accountants appropriate interpretation application policies critical accounting policies include policies related specific business units price risk management activities accounting oil gas activities well broad policies include accounting impairments contingencies consolidations business combinations areas involves complex situations high degree judgment either application interpretation existing literature development estimates impact financial statements critical accounting policies price risk management activities account price risk management activities based upon fair value accounting methods prescribed emerging issues task force eitf issue 9810 sfas 133 eitf issue 9810 governs accounting energy trading activities sfas 133 prescribes accounting hedging activities derivatives sets accounting rules require determine fair value instruments use business activities reflect balance sheet fair values however changes fair value period energy trading derivatives fair value hedges recorded income statement period changes fair value cash flow hedges generally recognized income statement hedge settled time methods derive similar results however period income methods differ significantly one primary factors impact results period price assumptions used value energy trading derivatives fair value hedges many instruments quoted market prices however required use internal valuation techniques models particularly energy trading activities estimate fair value instruments traded active exchange terms extend beyond time period exchangebased quotes available modeling techniques require us estimate future prices price correlation interest rates market volatility liquidity estimates also reflect potential impact liquidating position orderly manner reasonable period time present market conditions modeling risk credit risk counterparties operational risk amounts report financial statements change estimates revised reflect actual results changes market conditions factors many beyond control another factor impact results period ability estimate level correlation future changes fair value hedge instrument transaction hedged inception ongoing basis complicated since energy commodity prices primary risk hedge quality locational differences difficult hedge effectively factors underlying estimates fair value assessment correlation hedging derivatives impacted actual results changes conditions affect factors many beyond control asset impairments asset impairment accounting rules require us determine event occurred indicating longlived asset may impaired cases events clear however many cases clearly identifiable triggering event occur rather series individually insignificant events occur period time leading indication asset may impaired complicated investments foreign countries projects operator events occur may known later date occurrence continually monitor businesses market business environments make judgments assessments whether triggering event occurred event occurs make estimate future cash flows assets determine asset impaired investments evaluate whether events possible outcomes indicate decline value investment temporary occurred also generally involves assessment project level cash flows cash flow estimates require us make projections assumptions many years future pricing demand competition operating costs legal regulatory issues factors variables often differ estimates changes either positive negative impact estimates impairment result additional charges addition changes economic business environment impact original ongoing assessments potential impairment accounting reserves accounting reserves policies cover wide variety business activities including reserves potentially uncollectible receivables rate matters legal environmental exposures accrue reserves assessments indicate probable liability incurred asset recovered amount reasonably estimated estimates liabilities based currently available facts estimates ultimate outcome resolution liability future actual results may differ estimates often revised future either negatively positively depending upon outcome expectations based facts surrounding exposure accounting natural gas oil producing activities use fullcost method accounting natural gas oil producing activities accounting method capitalize substantially costs incurred connection exploration acquisition development natural gas oil reserves full cost pools maintained geographic area regardless whether reserves actually located method differs successful efforts method accounting activities primary difference two methods treatment exploratory dry hole costs exploration acquisition development costs wells yield measurable reserves successful efforts method costs generally expensed determination made measurable reserves added result financial statements differ companies apply successful efforts method since generally reflect higher level capitalized costs well higher depletion rate full cost accounting method conduct quarterly impairment tests capitalized costs cost pools based assessment discounted cash flows test referred ceiling test two primary factors impacting test reserve levels current prices addition prices use assessment reflect impact hedging programs risks related test changing estimates natural gas oil reserves decline prices process estimating natural gas oil reserves complex requiring significant decisions evaluation available geological geophysical engineering economic data given field may also change substantially time result numerous factors including additional development activity evolving production history continual reassessment viability production changing economic conditions result material revisions existing reserve estimates occur time although every reasonable effort made ensure reserve estimates reported represent accurate assessments possible subjective decisions variances available data various fields increases likelihood significant changes estimates prices natural gas oil volatile change period attempt realize determinable cash flows use hedges continued decline commodity prices impact results ceiling test accounting business combinations past three years completed several significant business combination transactions future may continue grow business combinations prior issuance sfas 141 business combinations 2001 applied guidance provided accounting principles board opinion apb 16 interpretations well various authoritative literature interpretations address issues encountered accounting business combinations accounted past combinations using purchase pooling interests methods required prior issuance sfas 141 allows use purchase method accounting business combinations whether purchase pooling interests method complicated involves use significant judgment purchase method accounting business combination accounted purchase price based upon fair value consideration given whether form cash assets stock assumption liabilities assets liabilities acquired measured fair values purchase price allocated assets liabilities based upon fair values determining fair values assets liabilities acquired involves use judgment since majority assets liabilities acquired fair values readily determinable different techniques may used determine fair values including market prices available appraisals comparisons transactions similar assets liabilities present value estimated future cash flows among others since estimates involve use significant judgment change new information becomes available pooling interests method accounting business combination accounted using historical cost entities involved combination rules pooling interests method accounting highly complex involve application interpretations evolved years since original issuance apb 16 consequently accounting business combinations method requires us apply existing accounting literature interpretations specific situations encountered transaction result risk judgments interpretations could viewed differently others addition even though coastal sonat mergers occurred prior effective dates sfas 141 continue take measures ensure mergers continue qualify pooling rules unable account coastal sonat mergers poolings interests financial statements would materially different principles consolidation currently interests joint ventures equity investors financing arrangements based existing accounting guidance precludes us consolidating entities december 2001 enron corp one largest companies energy industry declared bankruptcy viewed one largest bankruptcies history wake event accounting standard setters including securities exchange commission evaluating existing accounting disclosure rules requirements one area received high level scrutiny accounting rules related consolidations specifically address specialpurpose entities standard setting bodies regulators currently evaluating consolidation rules determine whether existing accounting framework change future risk existing standards change particularly light events 2001 changes could result consolidation financial statements entities currently consolidate details significant accounting policies estimates assumptions judgments use applying policies see item 8 financial statements supplementary data note 1 new accounting pronouncements issued yet adopted business combinations july 2001 financial accounting standards board fasb issued sfas 141 business combinations statement requires transactions fit definition business combination accounted using purchase method prohibits use pooling interests method business combinations initiated june 30 2001 statement also establishes specific criteria recognition intangible assets separately goodwill requires unallocated negative goodwill written acquisition date extraordinary item accounting business combinations undertake future impacted standard statement also requires upon adoption write income negative goodwill recognized business combinations acquisition date july 1 2001 effect change accounting principle expect negative goodwill provisions pronouncement material effect financial statements goodwill intangible assets july 2001 fasb issued sfas 142 goodwill intangible assets statement requires goodwill longer amortized periodically tested impairment least annual basis intangible asset indefinite useful life longer amortized useful life becomes determinable statement various effective dates significant january 1 2002 upon adoption statement january 1 2002 longer recognize annual amortization expense approximately 50 million goodwill indefinitelived intangible assets expect impairment provisions pronouncement material effect financial statements accounting asset retirement obligations august 2001 fasb issued sfas 143 accounting asset retirement obligations statement requires companies record liability relating retirement removal assets used business liability discounted present value related asset value increased amount resulting liability life asset liability accreted future value eventually extinguished asset taken service provisions statement effective fiscal years beginning june 15 2002 currently evaluating effects pronouncement accounting impairment disposal longlived assets october 2001 fasb issued sfas 144 accounting impairment disposal longlived assets statement requires longlived assets disposed sale measured lower book value fair value less cost sell standard also expanded scope discontinued operations include components entity operations distinguished rest entity eliminated ongoing operations entity disposal transaction provisions statement effective fiscal years beginning december 15 2001 provisions statement impact asset dispositions make january 1 2002 balance sheet enhancement plan anticipate sell variety assets including previously announced sale midstream assets el paso energy partners potential sales natural gas oil properties refining chemical coal mining power assets sales occur based current assessment sfas 144s provisions coal mining chemical refining assets likely qualify discontinued operations standard assets including announced sale midstream assets would believe qualify assets held sale addition sfas 144 establishes new rules company begins take action either dispose otherwise alter manner operation asset new rules becomes likely company alter current operating plans evaluation possible impairment made based announced actions date currently evaluating whether assets may sell impaired standard based preliminary indications market value coupled nearterm outlook refining coal mining industries anticipate may required writedown carrying values refining coal mining assets may sell amount could range 145 million 240 million aftertax standard continue evaluate assets may sold part plan see discussion balance sheet enhancement plan future liquidity derivatives implementation group issue c16 september 2001 derivatives implementation group fasb cleared guidance issue c16 scope exceptions applying normal purchases normal sales exception contracts combine forward contract purchased option contract guidance impacts accounting fuel supply contracts require delivery contractual minimum quantity fuel electricity fixed price option permits holder take specified additional amounts fuel fixed price various times use fuel supply contracts power producing operations currently reflect balance sheet since considered normal purchases classified derivative instruments sfas 133 guidance becomes effective second quarter 2002 required account contracts derivative instruments sfas 133 currently evaluating impact guidance financial statements risk factors cautionary statement purposes safe harbor provisions private securities litigation reform act 1995 report contains incorporates reference forwardlooking statements within meaning private securities litigation reform act 1995 forwardlooking statement includes statement assumptions bases underlying forwardlooking statement caution believe assumptions bases reasonable good faith assumed facts bases almost always vary actual results differences assumed facts bases actual results material depending upon circumstances forwardlooking statement management express expectation belief future results expectation belief expressed good faith believed reasonable basis cannot assure however statement expectation belief result achieved accomplished words believe expect estimate anticipate similar expressions generally identify forwardlooking statements forwardlooking statements whether written oral expressly qualified cautionary statements cautionary statements may accompany forwardlooking statements addition disclaim obligation update forwardlooking statements reflect events circumstances date report mind consider risks discussed elsewhere report documents file commission time following important factors could cause actual results differ materially expressed forwardlooking statement made us behalf success pipeline field services business depends factors beyond control natural gas natural gas liquids transport gather process store owned third parties result volume natural gas natural gas liquids involved activities depends actions third parties beyond control following factors beyond control may unfavorably impact ability maintain increase current transmission storage gathering processing sales volumes rates renegotiate existing contracts expire remarket unsubscribed capacity future weather conditions including favor hydroelectric generation alternative energy sources price competition drilling activity supply availability expiration significant contracts service area competition revenues pipeline businesses generated contracts must renegotiated periodically substantially pipeline subsidiaries revenues generated natural gas transportation contracts expire periodically must renegotiated extended replaced although actively pursue renegotiation extension andor replacement contracts cannot assure able extend replace contracts expire terms renegotiated contracts favorable existing contracts particular ability extend andor replace transportation contracts could harmed factors cannot control including proposed construction companies additional pipeline capacity markets served interstate pipelines changes state regulation local distribution companies may cause negotiate shortterm contracts reduced demand due higher natural gas prices availability alternative energy sources supply points viability expansion projects unable renew extend replace contracts renew less favorable terms may suffer material reduction revenues earnings fluctuations energy commodity prices could adversely affect business natural gas prices supply basins connected pipeline systems higher prices natural gas producing regions especially canada ability compete transporters may negatively impacted revenues generated transmission gathering processing contracts depend volumes rates affected prices natural gas natural gas liquids success transmission gathering processing operations gulf mexico subject continued development additional oil natural gas reserves vicinity facilities ability access additional reserves offset natural decline existing wells connected systems decline energy prices could precipitate decrease development activities could cause decrease volume reserves available transmission gathering processing offshore facilities fluctuations energy prices may impact gathering rates investments third parties development new natural gas oil reserves connected gathering processing facilities caused number factors including regional domestic international supply demand availability adequacy transportation facilities energy legislation federal state taxes sale transportation natural gas natural gas liquids abundance supplies alternative energy sources reductions average volume natural gas natural gas liquids transport gather process prolonged period results operations financial position could significantly negatively affected rates able charge customers may reduced governmental authorities pipeline businesses regulated ferc department transportation texas railroad commission various state local regulatory agencies particular ferc generally limits rates permitted charge customers interstate natural gas transportation cases sales natural gas rates permitted charge customers use regulated pipelines lowered recover current cost levels terms conditions tariffs contracts modified profitability pipeline businesses may reduced success natural gas oil exploration production businesses dependent factors beyond control performance natural gas oil exploration production businesses dependent upon number factors cannot control factors include fluctuations natural gas crude oil prices including basis differentials results future drilling activity ability identify precisely locate prospective geologic structures drill successfully complete wells structures timely manner ability expand leased land positions desirable areas often subject intensely competitive leasing conditions risks incident operations natural gas oil wells future drilling production development costs including drilling rig rates increased competition search acquisition reserves estimates natural gas oil reserves may change actual production revenues taxes development expenditures operating expenses respect reserves likely vary estimates proved reserves natural gas oil variances may material process estimating natural gas oil reserves complex requiring significant decisions assumptions evaluation available geological geophysical engineering economic data reservoir deposit result estimates inherently imprecise actual future production natural gas oil prices revenues taxes development expenditures operating expenses quantities recoverable natural gas oil reserves may vary substantially estimates addition may required revise reserve information downward upward based production history results future exploration development prevailing natural gas oil prices factors many beyond control success power generation marketing activities depends many factors beyond control success international domestic power projects power marketing activities amount related performancebased management fee paid us connection chaparral could adversely affected factors beyond control including alternative sources supplies energy becoming available due new technologies interest self generation cogeneration uncertain regulatory conditions resulting ongoing deregulation electric industry united states foreign jurisdictions ability negotiate successfully enter restructure recontract advantageous longterm power purchase agreements possibility reduction projected rate growth electricity usage result factors regional economic conditions implementation conservation programs inability customers pay amounts owed power purchase agreements increasing price volatility due deregulation changes commodity trading practices success refining chemical activities depends many factors beyond control success refining chemical activities depends many factors many beyond control including availability alternative sources supply including new refineries foreign locations ongoing regulations laws governing sale use chemicals produce demand products impact economic recession markets products prices feedstocks primarily crude oil use derivative financial instruments could result financial losses subsidiaries use futures option contracts traded new york mercantile exchange overthecounter options price basis swaps natural gas merchants financial institutions could incur financial losses future result volatility market values energy commodities trade one counterparties fails perform contract valuation financial instruments involve estimates changes assumptions underlying estimates occur changing valuation instruments potentially resulting financial losses extent hedge commodity price exposure interest rate exposure forego benefits would otherwise experience commodity prices increase interest rates change additional information concerning derivative financial instruments see item 7a quantitative qualitative disclosures market risk item 8 financial statements supplementary data note 8 attractive acquisition investment opportunities may available ability grow depend part upon ability identify complete attractive acquisition investment opportunities growth acquisitions investments joint ventures future operating results success acquisitions joint ventures within outside united states may subject effects changes united states foreign trade monetary policies laws regulations political economic developments inflation rates taxes operating conditions addition increased competition acquisition investment opportunities increased competition could result successful bidder making acquisition higher relative price historically paid occurrences would limit ability fully execute growth strategy foreign operations investments involve special risks activities areas outside us subject risks inherent foreign operations including loss revenue property equipment result hazards expropriation nationalization wars insurrection political risks effects currency fluctuations exchange controls devaluation foreign currencies economic problems changes laws regulations policies foreign governments including associated changes governing parties costs environmental liabilities regulations litigation could exceed estimates current former operations involve management regulated materials subject various environmental laws regulations laws regulations obligate us clean various sites petroleum chemicals lowlevel radioactive substances regulated materials may disposed released sites designated superfund sites epa comprehensive environmental response compensation liability act also party legal proceedings involving environmental matters pending various courts agencies possible us estimate reliably amount timing future expenditures related environmental matters difficulty estimating clean costs uncertainty quantifying liability environmental laws impose joint several liability potentially responsible parties nature environmental laws regulations possible introduction future environmental laws regulations although believe established appropriate reserves liabilities including clean costs could required set aside additional reserves future due uncertainties additional information concerning environmental matters see item 8 financial statements supplementary data note 14 operations subject operational hazards uninsured risks operations subject inherent risks normally associated operations including explosions pollution release toxic substances fires hurricanes adverse weather conditions hazards could result damage destruction facilities damages persons property addition operations face possible risks associated acts aggression domestic foreign assets events occur could suffer substantial losses maintain insurance types risks extent amounts believe reasonable financial condition operations could adversely affected significant event occurs fully covered insurance subject financing interest rate exposure risks future success depends ability access capital markets obtain financing cost effective rates addition trading business heavily dependent favorable credit ratings downgrade trigger higher cash requirements operating costs ability access financial markets obtain costeffective rates future dependent number factors many cannot control including changes interest rates tax rates due new tax laws structured commercial financial markets market perceptions us natural gas energy industry stock price credit ratings inability amend rating triggers chaparrals gemstones thirdparty debt otherwise refinance debt could adversely impact credit ratings face competition third parties transport gather process fractionate store otherwise handle oil natural gas natural gas liquids petroleum products oil natural gas business highly competitive search acquisition reserves gathering marketing oil gas production competitors include major oil companies independent oil gas concerns individual producers gas marketers major pipeline companies well participants industries supplying energy fuel industrial commercial individual consumers unable compete services offered energy enterprises may larger offer services possess greater resources future profitability may negatively impacted may achieve objectives set forth balance sheet enhancement program timely manner ability achieve objectives balance sheet enhancement program well timing achievement subject factors beyond control including ability raise 225 billion cash asset sales may impacted ability locate potential buyers timely fashion obtain reasonable price competing asset sales programs competitors addition even receive cash amount announced enhancement program guarantee results program achieved ability amend rating triggers chaparrals gemstones third party debt conditional upon approval existing note holders third party equity investors credit rating perceptions company industry factors impacting timing ability complete enhancement program include ability issue equity securities based stock price credit ratings liquidity capital markets ability retain earnings based operational factors economic conditions commodity prices item 7aitem 7 managements discussion analysis financial condition results operations managements discussion analysis includes forwardlooking statements subject risks uncertainties actual results may differ substantially statements make section due number factors discussed beginning page 76 overview energy company whose operations encompass natural gas oil production gathering processing interstate intrastate transmission natural gas power generation petroleum refining energy trading business divided four distinct business segments pipelines production field services merchant energy last five years experienced substantial growth mergers acquisitions organic growth marketing trading global power businesses growth mergers acquisitions included significant transactions deeptech international acquisition 1998 sonat merger 1999 coastal merger 2001 transactions growth trading power activities capital needs businesses required substantial financial resources fiveyear period frequently accessed capital markets fund growth wide variety financings 2002 experienced dramatic changes industry well financial markets rely continue operate challenging environment response industry events credit rating agencies including moodys standard poors reevaluated ratings companies involved energy trading activities result ratings many largest participants energy trading industry including us downgraded investment grade several experienced significant financial distress also impacting us preliminary decision reached ferc alj one subsidiaries withheld pipeline capacity california market 2000 2001 reacting changes market leverage preliminary decision related california matters moodys standard poors initiated series ratings actions lowering senior unsecured debt rating caa1 b investment grade ratings remain negative outlook several negative outcomes resulted downgrades first cash generated 2002 sales assets originally identified debt reductions instead required posted additional cash collateral connection commercial trading activities paid satisfy financial guarantees used retire arrangements additionally access capital markets commercial paper markets became much restricted lower credit ratings finally credit downgrades resulted net cash generated assets businesses collateralize two minority interest financing arrangements largely unavailable us general corporate purposes instead required use cash redeem preferred securities issued connection arrangements operation assets businesses march 2003 issued 12 billion twoyear term loan proceeds used retire outstanding amounts trinity river preferred interest financing arrangement partially freeing cash usage restrictions discussion redemption see item 8 financial statements supplementary data note 19 since fourth quarter 2001 taken several steps address issues affecting us made significant progress plans meet demands liquidity strengthen capital structure significant accomplishments include sale 25 billion equity equitylinked securities completion execution contracts sale 55 billion noncore assets investments removal rating triggers 4 billion investment financing programs credit rating downgrades would resulted issuance stock liquidation assets proceeds would used repay arrangements issuance 700 million senior unsecured notes southern natural gas company 400 million anr pipeline company 300 million completion march 2003 new 12 billion term loan enabled retirement trinity river preferred interest financing arrangement eliminated cash restrictions accelerated amortization arrangement establishment exit strategy trading business including planned orderly liquidation existing trading portfolio substantial reduction credit exposure lng business repayment 19 billion financial obligations including electron trinity river achievement western energy settlement march 2003 designed resolve principal exposure relating western energy crisis minimizing impact current liquidity february 5 2003 announced 2003 operational financial plan based five key principles preserve enhance value core businesses exit noncore businesses quickly prudently strengthen simplify balance sheet maximizing liquidity aggressively pursue additional cost reductions continue work diligently resolve litigation regulatory matters following sections managements discussion analysis address events outlook greater detail section entitled liquidity capital resources discuss impact changes credit standing current liquidity including ability generate cash operations capital market transactions section entitled offbalance sheet arrangements contractual obligations discuss various financing contractual arrangements involved commit us guarantees commercial contractual obligations results operations analyze operating results business segments identify unusual infrequent events impacted cases may continue impact operations business segments discussions liquidity capital resources offbalance sheet arrangements contractual obligations results operations based consolidated financial statements prepared application accounting principles generally accepted us preparation financial statements reflect selection application accounting policies many require us use assumptions estimates judgments involve complex processes actual results often differ estimates beginning page 70 discussion critical accounting policies discuss policies significant financial position operating results presented financial statements also read significant accounting policies item 8 financial statements supplementary data note 1 understand policies impact financial presentation included discussion analysis presentation financial statements whole liquidity capital resources liquidity overview current liquidity rely cash generated internal operations primary source liquidity well available credit facilities bank financings asset sales issuance longterm debt preferred securities equity securities time also used structured financings sometimes referred offbalance sheet arrangements expect future funding working capital needs capital expenditures longterm debt repayments dividends financing activities continue provided sources impacted factors influence overall amount cash generated us capital available us example cash generated business operations may impacted changes commodity prices demands commodities services due weather patterns competition providers alternative energy sources collateral demands recovery collateral posted impacted natural gas prices hedging levels credit quality counterparties liquidity generated future asset sales may depend overall economic conditions industry served assets condition location assets number interested buyers addition credit ratings general market conditions restrict ability access capital markets significant impact liquidity following tables reflect available liquidity beginning year estimated sources uses liquidity throughout 2003 indicate adequacy liquidity meet immediate needs beginning 2003 available liquidity follows billions 1 364day bank facility matures may 2003 amounts outstanding time becoming due may 2004 multiyear bank facility matures august 2003 2 additional 05 billion drawn february 2003 sources cash expect 2003 include billions 1 issuances 19 billion occurred march 2003 2 march 31 2003 completed executed contracts sale 17 billion noncore assets investments 2003 anticipated cash needs include billions 1 includes redemption trinity river preferred interest 980 million occurred first quarter 2003 2 includes repayment limestone notes 1 billion occurred march 2003 purchase limestones equity 175 million expected occur may 2003 anticipated requirements may change significantly analysis intended provide understanding cash needs required discretionary better understand liquidity outlook factors could impact outlook identified beginning page 76 overview cash flow activities 2002 years ended december 31 2002 2001 cash flows summarized follows year ended december 31 2002 cash equivalents increased approximately 05 billion approximately 16 billion generated substantial amount cash various sources including cash flows principal operations sales assets financing transactions including longterm debt equity securities issuances also used major portion cash fund capital expenditures repay maturing financial obligations meet increased demand cash collateral result credit downgrade summary generated cash principal business operations working capital demands changes 20 billion also raised 54 billion cash issuance debt equity securities borrowings revolving credit facility cash proceeds sale assets investments amounted approximately 29 billion cash received sources invested approximately 40 billion property plant equipment equity investments paid 28 billion maturing longterm debt obligations additionally paid 05 billion dividends 09 billion redeem minority preferred interests also met net working capital demands 16 billion primarily margin payments related energy trading activities hedging activities natural gas production collateral requirements detailed analysis cash flows operating investing financing activities follows cash operating activities generated almost 20 billion cash operations 2002 working capital changes compared 24 billion 2001 net cash provided operating activities 04 billion year ended december 31 2002 compared net cash provided operating activities 41 billion period 2001 margin call requirements trading activities volatile source use working capital us primary reasons significant differences 2002 operating cash flows compared 2001 substantial net cash outflows margins 2002 09 billion net cash inflows 2001 margins almost 03 billion operating cash flows 2002 also reflected significantly lower cash inflows settlements trading positions 03 billion compared 15 billion 2001 margin positions significantly impacted two factors credit commodity prices following downgrade credit extended us counterparties lowered requiring us post additional margins many counterparties also posted letters credit us requiring us return margin deposits addition impact operating cash flows changes commodity prices depends whether hedged prices market prices 2001 hedged prices market resulted margins deposited us hedged prices go market 2002 required make margin deposits however margin deposits recovered sell underlying commodities settle positions natural gas prices decrease december 31 2002 held 01 billion cash 04 billion letters credit collateral third parties related price risk management activities provided 10 billion cash 02 billion letters credit third parties related activities cash investing activities net cash used investing activities 13 billion year ended december 31 2002 investing activities consisted primarily capital expenditures equity investments 40 billion offset net proceeds sale assets investments cash received repayment notes receivable 29 billion capital expenditures equity investments included following billions cash received investing activities includes 29 billion sale assets investments asset sales proceeds primarily attributable sale natural gas oil properties texas colorado utah western canada 13 billion sales texas new mexico midstream assets 05 billion san juan assets 04 billion el paso energy partners sale power petroleum processing assets 07 billion cash financing activities net cash provided financing activities 13 billion year ended december 31 2002 cash provided financing activities included net proceeds issuance longterm debt 43 billion including 08 billion nonrecourse debt issued connection utility contract funding llc ucf power contract restructuring 06 million associated equity security units issuance additionally issued 10 billion common stock also received net proceeds commercial paper shortterm credit facilities 02 billion cash used financing activities included payments made retire third party longterm debt financing obligations 23 billion also redeemed 700 million preferred securities previously issued subsidiaries made minority interest payments 161 million primarily chaparral holds 16 percent minority interest ucf project repaid 513 million notes payable affiliates paid dividends 470 million also year ended december 31 2002 el paso tennessee pipeline co subsidiary paid dividends approximately 25 million series cumulative preferred stock accrues rate 8 14 per year 20625 per quarter summary significant borrowing repayment activities 2002 2003 presented amounts include borrowings repayments shortterm financing instruments original maturity three months less referred cash financing activities issuances 1 net proceeds primarily used repay maturing longterm debt shortterm borrowings repayment intercompany borrowings meet capital requirements borrower redeem preferred interests consolidated subsidiaries general corporate purposes 2 includes 82 million change value e500 million euro notes may 2002 december 2002 due change euro us dollar foreign currency exchange rate 3 notes collateralized solely cash flows contracts consolidated subsidiaries nonrecourse consolidated subsidiaries mohawk river funding iv financing relates capitol district energy center cogeneration associates power restructuring transaction utility contract funding financing relates eagle point cogeneration power restructuring transaction 4 collateralized term loan natural gas oil reserves approximately 23 tcfe minimum libor rate 35 retirements 1 bought back 109 million bonds open market second half year 89 million anticipate continue repurchase debt subject available liquidity ongoing market opportunities 2 includes exchange 435 million senior debentures common stock discussed june 2002 issued 518 million shares common stock public offering price 1995 per share net proceeds offering approximately 1 billion used repay shortterm borrowings financing obligations general corporate purposes june 2002 issued 115 million 9 equity security units equity security units consist two securities purchase contract pay quarterly contract adjustment payments annual rate 286 requires holder buy common stock settled august 16 2005 ii senior note due august 16 2007 principal amount 50 per unit pay quarterly interest payments annual rate 614 beginning august 16 2002 senior notes issued total principal value 575 million pledged secure holders obligation purchase shares common stock purchase contracts purchase contracts settled 2005 issue common stock time proceeds allocated common stock additional paidin capital number common shares issued depend prior consecutive 20trading day average closing price common stock determined third trading day immediately prior stock purchase date issue minimum approximately 24 million shares maximum 288 million shares settlement date depending average stock price recorded approximately 43 million noncurrent liabilities reflect present value quarterly contract adjustment payments required make units annual rate 286 stated amount 50 per purchase contract offsetting reduction additional paidin capital quarterly contract adjustment payments allocated liability recognized date issuance additional paidin capital based constant rate term purchase contracts fees expenses incurred connection equity security units offering allocated senior notes purchase contracts based respective fair values issuance date amount allocated senior notes recognized interest expense term senior notes amount allocated purchase contracts recorded additional paidin capital august 2002 issued 12184444 shares common stock satisfy purchase contract obligations feline pridessm program return issuance stock received approximately 25 million cash maturity zero coupon bond return 435 million existing 6625 senior debentures due august 2004 issued 1999 zero coupon bond senior debentures held collateral purchase contract obligations 25 million received maturity zero coupon bond used retire additional senior debentures total debt reduction issuance common stock approximately 460 million credit facilities historically used commercial paper programs manage shortterm cash requirements programs could borrow 3 billion combination individual corporate tgp epng commercial paper programs 1 billion however result credit downgrade currently issuing commercial paper meet liquidity needs may 2002 renewed existing 3 billion 364day revolving credit competitive advance facility epng tgp also designated borrowers facility jointly severally liable amounts outstanding facility matures may 2003 provides amounts outstanding date due may 2004 also maintain 3year 1 billion revolving credit competitive advance facility conduct shortterm borrowings commercial credit transactions june 2002 amended facility permit us issue 500 million letters credit adjust pricing terms facility matures august 2003 subsidiaries el paso cgp company formerly coastal epng tgp designated borrowers facility jointly severally liable amounts outstanding interest rate facilities varies based senior unsecured debt rating december 31 2002 borrowings facility rate libor plus 100 plus 025 utilization fee december 31 2002 15 billion outstanding 3 billion facility issued approximately 456 million letters credit 1 billion facility february 2003 borrowed 500 million 1 billion facility currently negotiating amendment 3 billion 364day revolving credit facility successful negotiating amendment expect terms conditions amended revolving credit facility include extension maturity date increase unused commitment fee margin collateral support financing new amended financial ratios covenants expected anr tgp epng would also borrowers facility also currently negotiating amendment 1 billion multiyear facility expect conformed amended 3 billion 364day revolver except commitment amount identity lenders maturity availability borrowings credit borrowing agreements subject specified conditions currently meet conditions include compliance financial covenants ratios required agreements absence default agreements continued accuracy representations warranties contained agreements restrictive covenants subsidiaries entered debt instruments guaranty agreements contain covenants restrictions debt levels restrictions liens securing debt guarantees restrictions mergers sales assets capitalization requirements dividend restrictions crosspayment default crossacceleration provisions breach covenants could result acceleration debt financial obligations subsidiaries revolving credit facilities significant debt covenants cross defaults ratio consolidated debt guarantees capitalization excluding certain project financing securitization programs miscellaneous items defined agreement cannot exceed 70 percent b consolidated debt guarantees excluded items subsidiaries cannot exceed greater 600 million 10 percent consolidated net worth c principal subsidiaries cannot permit liens equity interest principal subsidiaries create liens assets material consolidated operations securing debt guarantees excluded items exceeding greater 300 million 10 percent consolidated net worth subject certain permitted exceptions occurrence event default nonpayment principal interest premium respect debt excluded items aggregate principal amount 200 million occurrence event default respect debt results acceleration thereof compliance covenants date filing including ratio debt capitalization defined credit facilities 632 december 31 2002 also issued various guarantees securing financial obligations subsidiaries unconsolidated affiliates similar covenants credit facilities respect guarantees issued subsidiaries significant debt covenant addition covenants discussed el paso cgp must maintain minimum net worth 12 billion breached amounts guaranteed guaranty agreements could accelerated guaranty agreements also maintain 30 million crossacceleration provision el paso cgps net worth december 31 2002 43 billion addition three subsidiaries indentures associated public debt contain 5 million crossacceleration provisions crossacceleration provisions generally state event default occurs exceeds 5 million amounts outstanding securities contain indentures also become due payable available capacity shelf registration statements february 2002 filed new shelf registration statement sec allows us issue 3 billion securities registration statement issue combination debt equity instruments including trust preferred securities two wholly owned trusts el paso capital trust ii el paso capital trust iii issue securities trusts required issue full unconditional guarantees securities december 31 2002 818 million remaining capacity shelf registration statement letters credit enter letters credit ordinary course operating activities december 31 2002 outstanding letters credit approximately 852 million versus 465 million december 31 2001 increase primarily due issuance letters credit connection management trading activities december 31 2002 456 million outstanding letters credit supported revolving credit facility offbalance sheet arrangements contractual obligations course business activities enter variety financing arrangements contractual obligations following discusses first contingent obligations often referred offbalance sheet arrangements part consolidated obligations reflected financial statements second present aggregated information contractual cash obligations reflected financial statements short longterm debt others operating leases capital commitments reflected financial statements offbalance sheet arrangements following table summarizes offbalance sheet arrangements date expiration december 31 2002 commitments discussed detail credit facilities credit facility gemstone allows gemstone borrow 300 million us variable interest rate 68 december 31 2002 gemstone owed us 25 million facility december 31 2002 utilize facility 2001 earned less 1 million interest income facility 2002 2001 guarantees involved various joint ventures ownership arrangements sometimes require additional financial support results issuance financial performance guarantees financial guarantee obligated make payments guaranteed party fails make payments violates terms financial arrangement performance guarantee provide assurance guaranteed party execute terms contract required perform behalf example guaranteed party required deliver natural gas third party fails would required either deliver natural gas make payments third party equal difference contract price market value natural gas december 31 2002 approximately 25 billion financial performance guarantees outstanding amount approximately 10 billion relates chaparral investment 950 million relates gemstone investment discussed remaining 558 million relates global power equity investments including projects chaparral gemstone pipeline petroleum activities chaparral entered chaparral investment also referred electron 1999 expand domestic power generation business time chaparral formed interested participating deregulation power industry occurring across us objective acquire number nonregulated power plants built purpa plants related power contracts opportunities improve existing income cash flows lowering cost power sold regulated utility plants power sales agreement accomplished purchasing power supplied utility wholesale power market rather generating power plant consequently chaparrals investors shareholders would benefit improved economics establishing business number objectives hoped achieve including portfolio management goal establish investment unlike mutual fund investment portfolio held number assets could earn performancebased management fee determined value delivered investors furthermore portfolio approach allowed us reduce volatility earnings enhance cash flows business flexibility efficiency given complexity acquiring managing renegotiating existing power contracts sought investors whose business strategies aligned allow us maximum flexibility efficiency liability segregation separation nonrecourse financing liabilities balance sheet many power projects would hold interests funded partnerships nonrecourse project financings average higher leverage terms debt total equity business developed balance sheet could negatively impacted ratios possibly credit ratings consequently want reflect higher leverage overall capitalization given debt nonrecourse us furthermore separation entities related debt obligations appropriately reflected nature recourse solely projects chaparrals corporate structure limited liability company december 31 2002 owned approximately 20 percent us approximately 80 percent unaffiliated investor limestone capitalized private equity contributions 150 million group unrelated financial investors credit suisse first boston corporation 1 billion senior secured notes issued institutional investors limestone controlled subsidiaries affiliates credit suisse first boston corporation march 2003 notified limestone exercise right partnership agreements purchase outstanding third party equity limestone may 31 2003 175 million march 31 2003 contributed 1 billion limestone exchange noncontrolling interest limestone used proceeds contribution pay 1 billion notes matured date note repayment cancelled 1 billion guarantee related chaparral investment following additional investment 1 billion limestone effective ownership chaparral increased approximately 90 percent neither rights limestone participate operating decisions chaparral changed result continue account investment chaparral equity method consolidate chaparral upon purchase remaining third party equity interest limestone expect occur may 2003 time record acquired assets liabilities fair values fair value assets liabilities acquired impacted changes unregulated power industry whole well changes regional power prices us excess proceeds paid fair value net assets acquired reflected goodwill subject amortization tested impairment cannot currently estimate ultimate amount goodwill recorded believe goodwill 450 million may result goodwill fully impaired would report charge earnings approximately 300 million income taxes hand carrying amount acquired assets liabilities aggregated power assets liabilities fair value reporting unit reporting unit defined entire global power business would impairment goodwill december 31 2002 chaparral 42 billion total assets 18 billion consolidated third party debt chaparrals debt related specific assets owns interests recourse solely assets equity investment chaparral december 31 2002 256 million also additional net receivables chaparral totaled 448 million resulting total net investment chaparral 704 million december 31 2002 discussion chaparral activities see item 8 financial statements supplementary data note 26 gemstone entered gemstone investment 2001 finance five major power plants brazil gemstone established accomplish following objectives portfolio management like chaparral goal establish investment portfolio held number assets participate earnings equity investments unlike chaparrals performancebased management fee however primary objective investment flexibility acquire sell additional assets overall portfolio projects flexibility efficiency given complexity acquiring operationally managing negotiating power contracts foreign governments sought investors whose interests primarily financial return driven allow us maximum flexibility efficiency furthermore allowed us share risk foreign country partially mitigate foreign investment risk gemstone generic term used describe several entities first joint venture equity investment named diamond power ventures llc diamond owned us gemstone investor gemstone investor 100 percent owned subsidiary rabobank international addition 50 million equity investment issued 950 million senior secured notes institutional investors gemstone investor used entire 1 billion invest 700 million diamond b purchase 300 million preferred interest company called topaz power ventures llc topaz consolidated subsidiary topaz indirectly owns operates two brazilian power plants account gemstone investors preferred investment topaz minority interest consolidate diamond owns three power plants brazil gemstone owns interests five power generation facilities brazil total power generation capacity 2184 megawatts december 31 2002 gemstone total assets 17 billion including 304 million investment topaz 122 million receivables us total investment gemstone december 31 2002 663 million excluding payables 304 million minority interest 122 million mentioned consolidated subsidiary gemstone administracao ltda serves managing member diamond provides management services diamond fixedfee administrative services agreement fixed fee reimburses us legal accounting general administrative expenses incurred behalf diamond january 2003 rabobank notified us planned remove us manager gemstone accordance rights partnership agreements turn notified rabobank exercising right partnership agreements purchase rabobanks 50 million equity gemstone consolidate gemstone upon purchase rabobanks equity gemstone april 2003 unless replace new partner discussion gemstone activities see item 8 financial statements supplementary data note 26 residual value guarantees two operating leases provided residual value guarantees lessor leases either choose purchase asset end lease term specified amount typically equal outstanding loan amounts owed lessor choose assist sale leased asset third party asset sold price equals exceeds amount guarantee would obligated shortfall levels residual value guarantees range 862 percent 899 percent original cost leased assets accounting residual value guarantees impacted effective july 1 2003 adoption new accounting rules consolidations discussion accounting impact new rules see new accounting pronouncements issued yet adopted december 31 2002 purchase options residual value guarantees associated operating leases following assets contractual cash obligations following table summarizes contractual cash obligations december 31 2002 years presented 1 see item 8 financial statements supplementary data note 18 2 see item 8 financial statements supplementary data note 19 3 see item 8 financial statements supplementary data notes 2 20 4 maintain operating leases ordinary course business activities leases include office space operating facilities office operating equipment terms agreements vary 2003 2053 5 amounts include payments firm access natural gas transportation storage capacity 6 amounts include purchase commitments electricity part trading activities 7 amounts include obligations 252 million chaparral 122 million gemstone 16 million affiliates obligation chaparral consists 79 million debt securities 173 million contingent interest promissory notes debt securities payable demand carry fixed interest rate 7443 contingent interest promissory notes carry variable interest rate exceed 1275 mature 2019 2021 obligation gemstone consists 122 million debt securities payable demand carry fixed interest rate 525 8 amounts include primarily purchase capital commitments maintenance contracts engineering procurement construction costs 9 commitments exclude 25 billion associated lng ship charter agreement obligations restructured march 2003 resulted issuance letters credit equal 120 million fully collateralized cash results operations use earnings interest income taxes ebit assess operating results effectiveness business segments define ebit operating income adjusted earnings equity investments capitalized returns equity miscellaneous nonoperating items included measure financing costs including interest debt expense income taxes discontinued operations extraordinary items cumulative effect accounting changes following reconciliation operating results ebit income loss continuing operations years ended december 31 believe ebit useful measurement investors provides information used evaluate effectiveness businesses investments operational perspective exclusive costs finance activities exclusive income taxes neither directly relevant efficiency operations measurement may comparable measurements used companies used substitute net income performance measures operating cash flow overview results operations results operations measured ebit segment years ended december 31 results include impacts restructuring mergerrelated costs asset impairments charges including estimated western energy settlement gains sales assets discussed item 8 financial statements supplementary data notes 2 4 5 26 see item 8 financial statements supplementary data note 24 reconciliation operating results ebit segment results four segments pipelines production field services merchant energy strategic business units offer variety different energy products services requires different technology marketing strategies discussion analysis operating results business segments results include impact significant acquisitions dispositions restructuring mergerrelated costs asset impairments charges discussed years presented pipelines segment consists interstate natural gas transmission storage gathering related services us internationally interstate natural gas transportation systems face varying degrees competition pipelines well alternate energy sources used generate electricity hydroelectric power nuclear coal fuel oil addition customers shifted traditional dependence solely longterm contracts portfolio approach balances shortterm opportunities longterm commitments shift due changes market conditions competition driven state utility deregulation local distribution company mergers new supply sources volatility natural gas prices demand shortterm capacity new markets supply power plants regulated ferc regulates rates charge customers rates function costs providing services customers include return invested capital result financial results historically relatively stable however subject volatility due factors weather changes natural gas prices market conditions regulatory actions competition creditworthiness customers addition ability extend existing customer contracts remarket expiring contracted capacity dependent competitive alternatives regulatory environment federal state local levels market supply demand factors relevant dates contracts extended expire duration new renegotiated contracts affected current prices competitive conditions judgments concerning future market trends volatility subject regulatory constraints attempt recontract remarket capacity maximum rates allowed tariffs although times discount rates remain competitive level discount varies pipeline systems discussed item 8 financial statements supplementary data note 20 subheading rates regulatory matters ferc issued order related allocation capacity epng system order required epng give reservation charge credits prospectively firm shippers fails schedule shippers confirmed volumes except case force majeure refrain entering new firm contracts remarketing turned back capacity contracts terminating expiring may 31 2002 add additional compression line 2000 project increasing capacity 320 mmcfd without opportunity recover costs rates next rate case effective january 1 2006 pipelines segments future results operations impacted result capacity allocation proceeding order prohibits epng remarketing approximately 471 mmdthd capacity approximately 200 mmdthd rejected enron corp may 2002 bankruptcy proceeding remaining 271 mmdthd relates capacity epng unable remarket contracts expired within time frame specified fercs order prior rejection expiration 471 mmdthd contracts epng earning approximately 35 million per month net revenue credits related capacity epng requested rehearing september 20 ferc order relating aspects order request rehearing pending ferc december 2001 enron corp number subsidiaries including enron north america corp enron power marketing inc filed chapter 11 bankruptcy protection united states bankruptcy court southern district new york enrons subsidiaries transportation contracts several pipeline systems including epng contract discussed transportation contracts rejected pipeline subsidiaries filed proofs claim totaling approximately 137 million epng filed largest proof claim amount approximately 128 million included 18 million amounts due services provided date contracts rejected 110 million damage claims arising rejection transportation contracts epng prohibited remarketing capacity allocation orders discussed fully reserved amounts due enron date contracts rejected recognized revenues contracts since rejection date november 2002 sold 123 percent 144 percent equity interest alliance pipeline system net proceeds 141 million completed sale remaining equity interest alliance first quarter 2003 income earned investment alliance year ended december 31 2002 2001 approximately 21 million 23 million results operations pipelines segment follows three years ended december 31 1 throughput volumes exclude related pipeline systems sold connection federal trade commission orders related coastal sonat mergers including midwestern gas transmission east tennessee natural gas sea robin systems destin empire state iroquois pipeline investments throughput volumes exclude intrasegment activities year ended december 31 2002 compared year ended december 31 2001 operating revenues year ended december 31 2002 143 million lower 2001 decrease due lower natural gas liquids sales 49 million resulting lower prices 2002 67 million due impact lower natural gas prices 2002 net natural gas recovered used operations also contributing decrease lower revenues 49 million natural gas sales gathering processing activities due sale cigs panhandle field july 2002 lower transportation revenues 49 million due lower revenues capacity sold shortterm contracts lower throughput due lower electric generation demand milder winter weather 2002 addition 11 million decrease operating revenues due favorable resolution regulatory issues related natural gas purchase contracts 2001 4 million decrease due lower rates mojave pipeline system result rate case settlement effective october 2001 6 million decrease due sale midwestern gas transmission system april 2001 decreases partially offset 51 million additional revenues due largely transmission system expansion projects placed service 2001 2002 13 million due larger portion epngs capacity contracted maximum tariff rates 2002 32 million elba island lng facility placed service december 2001 18 million favorable resolution measurement issues processing plant serving tgp system 2002 operating expenses year ended december 31 2002 47 million lower 2001 primarily result 41 million lower fuel system supply purchases costs resulting lower natural gas volumes prices 2002 22 million impact price changes natural gas imbalances 27 million due lower employee benefit costs 2002 due cost efficiencies following merger coastal lower amortization goodwill 18 million due adoption sfas 142 january 2002 22 million decrease related sale cigs panhandle field july 2002 27 million lower electricity legal environmental overhead costs also contributing lower operating expenses 11 million due gain sale pipeline expansion rights february 2002 offsetting lower costs charges 7 million reserve bad debts 2002 related bankruptcy enron corp 10 million contributions charitable foundation associated epngs pipeline rupture 13 million higher amortization additional acquisition costs assigned utility plant 2002 higher operating expenses 16 million due elba island lng facility returning service 2002 also 2002 accrued 412 million western energy settlement 2001 mergerrelated costs 291 million connection coastal merger discussion charges see item 8 financial statements supplementary data notes 2 4 income year ended december 31 2002 124 million lower 2001 primarily due 153 million asset impairment charge associated western australia investment offsetting charge 11 million due resolution uncertainties associated sales interests empire state iroquois pipeline systems gulfstream pipeline project 2001 offset lower equity earnings 6 million empire state iroquois pipeline systems due sale interests 2001 also offsetting lower income higher equity earnings 2002 16 million primarily due higher equity earnings investment great lakes gas transmission year ended december 31 2001 compared year ended december 31 2000 operating revenues year ended december 31 2001 7 million higher 2000 increase due higher reservation revenues 67 million epng system result larger portion capacity sold maximum tariff rates versus period 2000 impact completed system expansions new storage transportation contracts 2001 cig 33 million also contributing increase impact higher natural gas prices first second quarters sales segmentowned production 29 million sales excess natural gas sales regulated natural gas sales contracts 27 million well higher throughput increased deliveries california western states 6 million increases partially offset lower 2001 revenues 44 million contract remarketing tgp system late 2000 42 million impact sales midwestern gas transmission system april 2001 crystal gas storage september 2000 east tennessee natural gas sea robin systems first quarter 2000 also partially offsetting increase lower 2001 sales 22 million related base gas abandoned storage fields favorable resolution 2000 natural gas pricerelated contingencies cig 28 million 11 million lower transportation revenues 2001 tgp result higher proportion throughput earnings short versus long hauls compared 2000 6 million lower remarketed rates seasonal turnedback capacity 2001 result sngs 2000 rate case settlement allowing customers partially reduce firm transportation capacity operating expenses year ended december 31 2001 271 million higher 2000 primarily result mergerrelated charges 334 million 2001 discussed previously also contributing increase impact higher natural gas prices first half 2001 natural gas purchase contracts 12 million higher purchase gas costs 8 million due natural gas imbalance revaluation 2001 result falling gas prices second half year increases reserve bad debts result exposure connection bankruptcy enron corp onetime favorable adjustment depreciation expense first quarter 2000 10 million resulting ferc approval reactivate elba island lng facility also contributing increase impact gains 2000 sales nonpipeline assets 8 million partially offsetting increase lower operating maintenance expenses 83 million due cost efficiencies following merger coastal reduced operating lower depreciation expenses 19 million due sales midwestern gas transmission system april 2001 crystal gas storage september 2000 east tennessee sea robin first quarter 2000 income year ended december 31 2001 21 million lower 2000 due lower equity earnings 13 million australian pipelines citrus corp owns florida gas transmission system also contributing decrease impact equity earnings due sales investments empire state iroquois pipeline systems 2001 8 million sale onethird interest destin pipeline company 2000 2 million partially offsetting decrease increased earnings investment alliance pipeline project 9 million commenced operations fourth quarter 2000 production segment conducts natural gas oil exploration production activities operating results driven variety factors including ability locate develop economic natural gas oil reserves extract reserves minimal production costs sell products attractive prices operate lowest total cost level possible production historically engaged hedging activities natural gas oil production stabilize cash flows reduce risk downward commodity price movements sales achieved primarily natural gas oil swaps past stated goal hedge approximately 75 percent anticipated current year production approximately 50 percent anticipated succeeding year production lesser percentage thereafter component strategic repositioning plan may 2002 modified hedging strategy modified strategy may hedge 50 percent anticipated production rolling 12month forward period modification hedging strategy increase exposure changes commodity prices could result significant volatility reported results operations financial position cash flows period december 31 2002 hedged approximately 215 million mmbtus anticipated natural gas production 2003 nymex henry hub price 343 per mmbtu regional price differentials transportation costs 2002 continued active onshore offshore development drilling program capitalize land seismic holdings development drilling done take advantage large inventory drilling prospects develop proved undeveloped reserve base also completed asset dispositions colorado utah western canada texas part balance sheet enhancement plan primarily due asset dispositions lower reserve base january 1 2003 january 1 2002 see item 8 financial statements supplementary data note 28 discussion natural gas oil reserves since depletion rate determined full cost method accounting lower reserve base coupled additional capital expenditures full cost pool result higher depletion rate future periods first quarter 2003 expect domestic unit production depletion rate approximately 159 per mcfe currently expect reduce total capital expenditures approximately 24 billion 2002 approximately 14 billion 2003 continually evaluate capital expenditure program estimate subject change based market conditions continue pursue strategic acquisitions production properties development projects subject acceptable returns july 2002 acquired natural gas properties raton basin approximately 140 million properties acquired expand interest current coal seam project area operating results analysis results three years ended december 31 1 includes production costs depletion depreciation amortization ceiling test charges mergerrelated costs asset impairments changes accounting estimates corporate overhead general administrative expenses severance taxes 2 prices stated transportation costs year ended december 31 2002 compared year ended december 31 2001 year ended december 31 2002 operating revenues 221 million lower 2001 14 percent decrease natural gas volumes 25 percent decrease natural gas prices hedges transportation costs account 848 million decrease revenues offset 599 million favorable variance natural gas hedging activity 2002 compared 2001 decline natural gas volumes primarily attributable sale properties colorado utah texas decrease operating revenues partially offset 22 percent increase oil condensate liquids volumes net six percent decrease prices hedges transportation costs resulting 46 million increase revenues addition oil hedging activity 7 million favorable variance 2002 compared 2001 decreasing operating revenues loss 13 million 2002 resulting marktomarket adjustment derivative positions longer qualify cash flow hedges longer qualify hedge accounting treatment since designated hedges anticipated future production natural gas oil properties sold march 2002 transportation net product costs year ended december 31 2002 16 million higher 2001 primarily due higher percentage gas volumes subject transportation fees offset lower costs incurred meet minimum payment obligations pipeline agreements operating expenses year ended december 31 2002 153 million higher 2001 contributing increase expenses noncash full cost ceiling test charges totaling 269 million incurred 2002 canadian full cost pool international properties primarily brazil turkey australia offset 2001 noncash full cost ceiling test charges international properties totaling 135 million unit production depletion expense higher 93 million 153 million due higher depletion rates 2002 offset 60 million decrease resulting lower production volumes 2002 higher depletion rate resulted higher capitalized costs full cost pool lower reserve base also contributing increase 2002 expenses increased oilfield service costs 9 million due primarily higher labor workovers production processing fees asset impairments 4 million higher corporate overhead allocations 34 million partially offsetting increase expenses mergerrelated costs 63 million incurred 2001 relating combined production operations 10 million writedowns materials supplies recognized 2001 resulting reduction inventory values due implementation consistent operating standards strategies plans following coastal merger discussion mergerrelated costs changes accounting estimates see item 8 financial statements supplementary data notes 4 6 addition increase expenses offset 49 million lower severance taxes 2002 severance taxes decreased primarily lower natural gas volumes prices tax credits taken 2002 qualified natural gas wells income year ended december 31 2002 4 million higher 2001 primarily due higher earnings 2002 pescada equity investment brazil year ended december 31 2001 compared year ended december 31 2000 operating revenues year ended december 31 2001 661 million higher 2000 nine percent increase natural gas volumes six percent increase natural gas prices hedges transportation costs account 335 million increase revenues addition natural gas hedging activity 261 million favorable impact 2001 compared 2000 19 percent decrease oil condensate liquids prices hedges transportation costs net 24 percent increase oil condensate liquids volumes decreased revenues 1 million decrease offset 66 million favorable impact oil hedging activities 2001 versus 2000 transportation net product costs year ended december 31 2001 19 million higher 2000 primarily due higher percentage gas volumes subject transportation fees costs incurred meet minimum payments pipeline agreements operating expenses year ended december 31 2001 336 million higher 2000 contributing increase full cost ceiling test charges 135 million international properties higher depletion expense 80 million 64 million resulting increased production 16 million higher depletion rates due higher capitalized costs cost pool also contributing higher expenses 2001 mergerrelated costs 63 million related combined production operations 10 million write downs materials supplies resulting reduction inventory values due implementation consistent operating standards strategies plans following coastal merger also increasing expenses 2001 higher oilfield service costs 8 million higher severance production taxes 40 million resulting higher production volumes higher natural gas prices field services assets field services segment primarily consist investment el paso energy partners gathering processing facilities south texas louisiana midcontinent rocky mountain regions general partner el paso energy partners manage partnerships daytoday operations addition various subsidiaries 265 percent partnerships common units series b preference units series c units acquired 350 million november 2002 recognize earnings receive cash partnership several ways including share partnerships cash distributions ownership limited preferred general partner interests also reimbursed costs incur provide various operational administrative services partnership addition reimbursed costs paid directly us partnerships behalf 2002 reimbursed approximately 59 million expenses incurred behalf partnership december 31 2002 common units market value 325 million preference units liquidation value 158 million series c units value 351 million 2002 earnings cash el paso energy partners follows 1 partnership obligated pay distributions units 2010 2 received first cash distributions february 2003 series c units since acquired units november 2002 2000 2002 entered several asset sales transactions el paso energy partners specific procedures instituted evaluating transactions ensure best interests us partnership based fair values procedures require board directors evaluate approve appropriate transactions partnership addition special committee comprised general partners independent directors evaluates transactions partnerships behalf typically involves engaging independent financial advisor assist evaluation opine fairness 2000 sold intrastate pipeline system alabama storage facilities mississippi 197 million included 170 million series b preference units issued us exchange storage facilities 2001 also sold several assets partnership including ngl transportation fractionation assets acquired pge investment deepwater holdings entity owned several pipeline gathering systems gulf mexico 2001 partnership also acquired rights chaco processing facility previous owners leased facility agreement expired december 2002 part plan strengthen capital structure enhance liquidity entered additional transactions sell various midstream assets el paso energy partners april 2002 sold gathering processing assets including intrastate natural gas pipeline system acquired acquisition pges midstream operations december 2000 also sold substantially natural gas gathering processing treating assets san juan basin november 2002 one san juan basin assets included transaction remaining interests chaco cryogenic natural gas processing plant part transaction agreement requires us repurchase chaco processing plant el paso energy partners 77 million october 2021 time el paso energy partners right lease plant us period ten years option renew lease annually thereafter addition 416 million cash received approximately 11 million series c units valued 350 million series c units represent new class partnerships limited partner interests voting rights including series c units limited partner ownership interest el paso energy partners increased approximately 41 percent discussion transactions el paso energy partners see item 8 financial statements supplementary data note 26 2002 also identified midstream assets sold third parties part plan strengthen capital structure enhance liquidity also received interest number parties interested merging andor purchasing portion general partner interest el paso energy partners time cannot predict outcome discussions december 2002 announced sale gathering systems located wyoming western gas resources inc transaction completed january 2003 march 2003 received approval board directors sell assets midcontinent north louisiana regions midcontinent assets primarily include greenwood hugoton keyes mocane natural gas gathering systems sturgis mocane lakin processing plants processing arrangements three additional processing plants north louisiana assets primarily include dubach processing plant gulf states interstate natural gas transmission system expect sale close end 2003 sale completed remaining assets consist primarily processing facilities south texas louisiana rocky mountain regions see part ii item 8 financial statements supplementary data note 3 discussion asset sales third parties 2002 result asset sales resulting decline gathering treating activities expect future ebit decrease considerably however expect increase earnings interests el paso energy partners partially offset anticipated decrease ebit attempt balance earnings operating activities combination fixedfee based marketbased services majority gathering transportation operations earn margins fixedfeebased services however operations earn margins marketbased rates revenues marketbased rate services product market price usually related monthly natural gas price index volume gathered processing fractionation operations earn margin based fixedfee contracts percentageofproceeds contracts makewhole contracts percentageofproceeds contracts allow us retain percentage product fee processing fractionation service makewhole contracts allow us retain extracted liquid products return producer btu equivalent amount natural gas percentageofproceeds contracts makewhole contracts may sensitivity price changes periods natural gas ngl prices volatile provide variety midstream services including gathering transportation natural gas processing fractionation natural gas ngl natural gas derivative products butane ethane propane operating results analysis results follows three years ended december 31 year ended december 31 2002 compared year ended december 31 2001 total gross margins year december 31 2002 212 million lower 2001 margins decreased approximately 134 million due sales midstream assets el paso energy partners april 2002 november 2002 addition processing margins decreased 58 million due lower ngl prices 2002 primarily impacted margins volumes san juan basin south louisiana south texas rocky mountain regions higher processing costs associated new processing arrangement chaco processing facility entered fourth quarter 2001 el paso energy partners sale dragon trail processing plant may 2002 also reduced processing margins 18 million 6 million processing agreement el paso energy partners terminated november 2002 connection el paso energy partners acquisition san juan basin assets lower natural gas prices san juan basin 2002 also resulted 22 million decrease gathering treating margins partially offsetting decreases favorable resolutions fuel rate volume matters 13 million first quarter 2002 8 million unfavorable resolutions fuel matters occurred 2001 14 million due higher realized transportation rates increased system efficiency related pipeline system acquired acquisition pges midstream operation december 2000 pipeline system one assets sold el paso energy partners april 2002 operating expenses year ended december 31 2002 359 million lower 2001 decrease primarily due sales san juan basin assets natural buttes ouray gathering systems dragon trail processing plant resulting net gain 245 million lower operating costs 48 million lower depreciation expense 35 million also contributing decrease 46 million mergerrelated costs 2001 included payments el paso energy partners related federal trade commission ordered sales assets owned partnership 9 million increase estimated environmental remediation liabilities 2001 addition 2002 cost reduction plan contributed 17 million lower operating costs depreciation expense also lower 9 million due assets held sale classification san juan basin assets 2002 9 million associated lower amortization goodwill due adoption sfas 142 january 2002 see item 8 financial statements supplementary data note 1 partially offsetting decreases impairment charge north louisiana facilities fourth quarter 2002 66 million believe facilities likely sold end estimated useful lives discussion asset sales mergerrelated costs see item 8 financial statements supplementary data notes 3 4 income year ended december 31 2002 55 million lower 2001 decrease due losses sale 2002 investment aux sable ngl plant investment blacks fork natural gas processing plant 47 million 3 million also contributing decrease income 2002 13 million gain sale investment deepwater holdings october 2001 gain 8 million recorded may 2001 sale 101 percent nonmanaging interest el paso energy partners 6 million lower equity earnings deepwater holdings result sale interest el paso energy partners october 2001 offsetting decreases higher earnings 22 million 2002 interests el paso energy partners year ended december 31 2001 compared year ended december 31 2000 total gross margins year ended december 31 2001 124 million higher 2000 increase 133 million due higher gathering processing volumes following acquisition pges texas midstream operations december 2000 higher volumes also increased margin 14 million result acquisition indian basin processing plant second quarter 2000 combined increase indian basins treating capacity 23 percent 2001 increase margin partially offset higher processing costs 5 million associated new processing arrangement el paso energy partners chaco processing facility fourth quarter 2001 year ended december 31 2001 lower average gathering treating processing rates resulted reduction total margins 17 million compared 2000 due primarily different mix assets contract terms resulting acquisition pges texas midstream operations operating expenses year ended december 31 2001 166 million higher 2000 increase due higher operating depreciation expenses 117 million primarily resulting acquisition pges texas midstream operations well mergerrelated costs charges 45 million discussion mergerrelated costs see item 8 financial statements supplementary data note 4 income year ended december 31 2001 23 million higher 2000 increase primarily due increased earnings el paso energy partners 27 million 13 million gain sale interest deepwater holdings october 2001 partially offset lower 2001 equity earnings deepwater holdings 3 million result sale increase also partially offset equity investment losses 7 million mobile bay aux sable liquids processing facilities due lower natural gas liquids prices decrease equity earnings projects 8 million merchant energy merchant energy segment consists three primary divisions global power petroleum energy trading may 2002 announced plans limit energy trading mitigate exposure working capital demands credit downgrades third fourth quarter deterioration energy trading environment led decision november 2002 exit energy trading business pursue orderly liquidation trading portfolio anticipate liquidation may occur 2004 liquidation strategy intended maximize cash flow trading portfolio reduce cash liquidity risk uncertain environment early 2003 also announced intent reduce involvement lng business exit substantially petroleum activities excluding aruba refinery merchant energys operating results analysis results three years ended december 31 global power global power division includes ownership operation domestic international power generating facilities cases partially power generating facilities account using equity method conduct domestic power business chaparral internationally invested brazil power market equity investment gemstone discussion chaparral gemstone investments see offbalance sheet arrangements contractual obligations item 8 financial statements supplementary data note 26 also interests number power facilities asia central america europe power contract restructuring activities many domestic power plants power plants owned chaparral longterm power sales contracts regulated utilities entered purpa power sold utility purpa contracts required delivered specified power generation plant power prices usually significantly higher cost power wholesale power market cost generating power purpa power plants typically higher cost would incur obtaining power wholesale power market principally purpa power plants less efficient newer power generation facilities past successful renegotiating restructuring longterm power contracts typically power contract restructuring purpa power sales contract amended power sold utility provided specific power plant able buy lower cost power wholesale power market ability reduce cost paid utility thereby inducing utility enter power contract restructuring transaction following contract restructuring power plant operates merchant basis means longer dedicated one buyer operate power prices high enough make operations economical addition may assume case eagle point cogeneration assume business economic risks supplying power utility satisfy delivery requirements restructured power contract term assume risk manage obligations entering transactions buy power third parties mitigate risk life contract activities reflected part trading activities reduce exposure changes power prices period power contract restructurings generally result higher rate return investment power generation business deliver reliable power lower prices cost generate power purpa power plants addition use restructured contracts collateral obtain financing cost comparable lower existing financing costs last three years successfully completed restructuring number longterm power contracts held unconsolidated affiliates cases held us result credit downgrades decision exit energy trading business disruption capital markets unlikely pursue additional power contract restructurings near term discussion activities see item 8 financial statements supplementary data note 13 year ended december 31 2002 compared year ended december 31 2001 gross margin consists revenues power plants net results power restructuring activities cost fuel used power generation process included operating expenses year ended december 31 2002 gross margin global power division 718 million higher 2001 gross margin power contract restructurings comprised 628 million increase 2002 completed power contract restructurings contract terminations eagle point cogeneration mount carmel nejapa power plants eagle point restructuring transaction completed march 2002 significant power contract restructuring transaction contributed 476 million net 2002 results eagle point restructuring involved several steps revenues expenses fees impairments reported 2002 gross margin first amended existing purpa power sales contract public service electric gas pseg eliminate requirement power delivered specifically eagle point power plant amended contract fixed prices stated increases 14year term range 85 per mwh 126 per mwh entered amended power sales contract consolidated subsidiary ucf created hold execute restructured power sales contract enter supply contract meet requirements restructured agreement monetize net cash flows contracts issuing debt keeping purpose ucf entered power supply agreement energy trading division epme usually participates power restructuring activities taking obligation supply power terms epme power supply contract identical amended power sales contract exception price set 37 per mwh 14year term credit enhancement purposes anticipation financing transaction associated restructuring ucf terminated epme supply contract second quarter 2002 replaced supply contract morgan stanley affiliate ucf entered morgan stanley contract solely purpose reducing cost debt ucf would issue epme continued supply power restructured transaction entering power supply agreement morgan stanley affiliate result steps taken transaction replaced highcost power generated eagle point plant averaged 75 per mwh power purchased open market average cost 31 per mwh also shifted collection credit risks third parties term restructured power sales agreement estimated improvement margins associated restructuring approximately 136 million life contracts actions taken restructure contract required us mark contract fair value result recorded noncash revenue representing estimated fair value derivative contract approximately 978 million also amended terminated ancillary agreements associated cogeneration facility gas supply transportation agreements steam contract existing financing agreements also paid 103 million utility terminate original purpa contract also included operating results 2002 98 million noncash charge adjust eagle point cogeneration plant fair value based new status peaking merchant plant noncash charge 230 million write book value original purpa contract transaction included closing costs 21 million minority interest owners share transaction 50 million total operating cash flows transaction amounted approximately 124 million cash paid utility amend original contract costs total financing cash flows included 829 million proceeds issuance 7944 senior notes collateralized solely contracts cash flows ucf two power restructuring transactions 2002 nejapa mount carmel transactions 2002 arbitration award panel approved termination power purchase agreement comision ejecutiva hydroelectrica del rio lempa nejapa power company one consolidated subsidiaries exchange cash payment 90 million recorded gross margin 90 million gain also recorded 13 million expense minority owners share gain applied proceeds award retire portion nejapas debt mount carmel restructuring involved termination existing purpa power purchase contract fee utility 50 million addition recorded noncash adjustment reflect fair value mount carmel facility 25 million resulting total net benefit restructuring transaction 25 million due increasing market power prices 2002 net increase gross margin power contract restructurings 628 million initial power restructuring transactions partially offset decrease fair value restructured power contracts related power supply contracts 114 million initial gains december 31 2002 addition net increase gross margin relating restructuring activities discussed gross margin increases 147 million realized domestic international power facilities consolidated fourth quarter 2001 first quarter 2002 partially offset decreased revenues sale manchief facility 2001 chaparral also contributing increase higher management fees 2002 42 million primarily chaparral partially offsetting increases increased losses investments 22 million 2002 operating expenses include cost fuel used power generation processes asset impairments costs incur operating maintaining power plants operating expenses year ended december 31 2002 387 million higher 2001 primarily result asset impairments recorded 2002 wrote capitalized turbine costs 162 million reduced capital expenditure plans related future power development result liquidity concerns accordingly ability intent use turbines international domestic power development projects changed reduced capital expenditure plans also impacted ability fund future financial investments resulting 44 million impairment goodwill encap enerplus investment management subsidiaries plant operation maintenance expenses increased 156 million primarily resulting consolidation international domestic powerrelated entities fourth quarter 2001 first quarter 2002 expansion south america central america mexico operations 2002 income year ended december 31 2002 798 million lower 2001 primarily due higher write downs equity investments recorded 2001 due weak economic conditions argentina 2002 recorded 342 million impairment capsacapex equity investment costanera cost investment also 2002 recorded writedown ppn equity investment india 41 million due ppns sole customer failing pay power generated plant significant difficulties encountered operating plant 17 million impairment milford equity investment construction problems disputes contractors lenders delayed completion plant addition recognized 74 million writedown ce generation equity investment december 2002 resulting sale underlying power plants completed first quarter 2003 2002 write downs partially offset impairments 74 million fife east asia equity investments 2001 contributing overall decrease equity earnings chaparral 136 million enfield due unexpected plant shutdowns 22 million projects consolidated fourth quarter 2001 first quarter 2002 52 million income also decreased 51 million due minority owners interest income projects consolidated us 2002 22 million decrease operating lease income result consolidation nejapa 2002 income also decreased due 75 million fees earned engineering construction management services macae power project 2001 recur 2002 power plant became operational contributed gemstone late 2001 decreases partially offset higher equity earnings 107 million gemstone 2002 year ended december 31 2001 compared year ended december 31 2000 gross margin year ended december 31 2001 54 million higher 2000 increase primarily due increase 67 million management fees earned chaparral 2001 also contributing increase higher margins 55 million philippine power project consolidated first quarter 2001 partially offsetting increases decrease 61 million margins associated west georgia facility sold chaparral fourth quarter 2000 operating expenses year ended december 31 2001 58 million higher 2000 increase primarily due increase plant operation maintenance expenses 100 million resulting consolidation philippine power project 2001 expansion operations mexico brazil 2001 addition recorded 12 million mergerrelated costs charges 2001 associated combining operations coastals operations see item 8 financial statements supplementary data notes 4 5 discussion mergerrelated costs asset impairments longlived assets increases partially offset lower costs 33 million west georgia facility sold fourth quarter 2000 income year ended december 31 2001 71 million higher 2000 increase primarily due 75 million fees earned engineering construction management services related development macae power project brazil 2001 also contributing increase equity earnings chaparral 80 million 2001 equity investments 28 million 2001 partially offsetting increases impairment 74 million fife east asia equity investments 2001 gains 36 million sale interests east asia guatemalan power projects 2000 petroleum addition exiting energy trading business announced february 2003 intent reduce involvement lng business exit substantially petroleum businesses except aruba refinery currently interests oil refineries chemical production facilities petroleum terminalling marketing operations blending packaging operations lubricants automotive products refinery operations cyclical nature sensitive movements price crude oil last two years operated environment differences price crude oil input price realize resulting products output narrow experienced losses refinery operations condition improved first quarter 2003 results future may continue volatile also contributing losses 2002 2001 operational difficulties following fire aruba facility 2001 year ended december 31 2002 compared year ended december 31 2001 gross margin consists revenues refineries commodity trading activities less costs feedstocks used refining process costs commodities sold year ended december 31 2002 gross margin 207 million lower 2001 decrease primarily due 67 million decline fair value lng supply contract derivatives 2002 compared 86 million increase fair value contracts 2001 also contributing decrease lower refining margins 84 million resulting lower throughput aruba refinery also recorded 57 million insurance claims recoveries 2001 related refinery losses associated primarily fire aruba facility april 2001 decrease 143 million marine revenues resulting lower marine freight rates number operating vessels decrease 86 million associated lease corpus christi refinery related assets valero june 2001 decreases partially offset increased refining margins 74 million eagle point refinery gain 210 million sale longterm lng supply contract capacity rights regasification terminal snohvit 2002 operating expenses year ended december 31 2002 149 million lower 2001 decrease primarily due 244 million mergerrelated costs asset impairments charges 2001 primarily associated combining operations coastals operations see item 8 financial statements supplementary data notes 4 5 discussion mergerrelated costs asset impairments decrease partially offset 91 million impairment mtbe chemical processing plant 2002 7 million increase operating costs associated expansion lng operations 2002 income year ended december 31 2002 1 million higher 2001 increase primarily due 46 million insurance claims recoveries insurers recorded 2002 compared 40 million net writeoffs damaged properties 2001 primarily associated assets destroyed fire aruba facility april 2001 year ended december 31 2001 compared year ended december 31 2000 year ended december 31 2001 gross margin 1 million lower 2000 decreases year result 105 million decrease margins crude based refined products lower margins throughput eagle point refinery result decreased demand jet fuel following events september 11 2001 also contributing decrease 48 million decrease margins associated lease corpus christi refinery related assets valero june 2001 partially offsetting decreases 86 million increase fair value lng supply contract derivatives 2001 compared 54 million decrease fair value contracts 2000 22 million margins earned coastal liquid partners consolidated early 2001 also offsetting decreases 57 million insurance claims recoveries insurers losses incurred related primarily fire aruba facility april 2001 fire primary reason 25 percent decrease output 2000 2001 resulting 53 million reduction year refining margins operating expenses year ended december 31 2001 259 million higher 2000 increase primarily due 249 million mergerrelated costs asset impairments charges 2001 associated combining operations coastals operations see item 8 financial statements supplementary data notes 4 5 discussion mergerrelated costs asset impairments longlived assets also contributing increase 26 million increase operating expenses associated lng business 2001 higher fuel costs 29 million refineries due higher natural gas prices increases partially offset lower operating expenses 64 million resulting lease corpus christi refinery related assets valero june 2001 income year ended december 31 2001 72 million higher 2000 increase primarily result 77 million insurance claims recoveries net writeoffs damaged properties 37 million insurers associated primarily assets destroyed aruba fire energy trading energy trading activities historically included actively managing inherent risk across merchant energys asset portfolios well providing customers risk management solutions involving natural gas power crude oil refined products chemicals coal division also conducted substantial energy trading business executed proprietary trading strategies managed segments risk across multiple commodities seasonally fluctuating energy demands using consistent methodologies november 2002 announced would exit energy trading business due increasing volatile cash demands inherent business magnified credit downgrade process liquidating trading price risk management portfolio anticipate effort continue 2004 liquidation strategy executed variety ways including negotiating early settlements pursuant contractual terms counterparties actively pursuing sale transactions entire portfolio third parties matching transferring offsetting positions different counterparties transferring transactions el paso segments divisions liquidating scheduled settlements late 2002 began actively liquidating trading portfolio december 31 2002 approximately 40000 transactions settled future included portfolio time approximately 44 bcfd natural gas transportation capacity natural gas storage rights approximately 125 bcf december 31 2002 contracted sell 21 bcfd transportation capacity 70 bcf gas storage rights sale resulted loss approximately 25 million additionally first quarter 2003 sold european natural gas trading portfolio completed liquidations open trading positions europe incurred loss approximately 4 million sale liquidation continuing work numerous counterparties liquidate remainder portfolio 2004 fair value price risk management contracts december 31 2002 following table details net estimated fair value energy contracts trading nontrading year maturity valuation methodology december 31 2002 classify trading activities price risk management activities enter objective generating profits benefiting exposure shifts changes market prices classify derivativerelated activities including related power restructuring activities nontrading price risk management activities 1 exchangetraded positions include positions traded active exchanges new york mercantile exchange international petroleum exchange london clearinghouse 2 nonexchange traded positions include positions based exchange prices third party pricing data valuation techniques incorporate specific contractual terms statistical simulation analysis present value concepts 3 nontrading energy contracts include derivatives power contract restructuring activities 968 million derivatives related natural gas oil producing activities 509 million earnings related natural gas oil producing activities included production segment results energy trading industry experienced dramatic changes 2002 especially fourth quarter changes included credit downgrades many major industry participants actions taken major industry participants reduce trading activities completely exit business actions limit trading activities exit trading business accessibility reliable forward market data purposes estimating fair value significantly limited late 2002 result obtained valuation assistance third party valuation specialist determining fair value trading nontrading price risk management activities december 31 2002 based upon specialists input estimates fair value based upon price curves derived actual prices observed market pricing information supplied specialist independent pricing sources models rely forward pricing information estimates also reflect factors time value volatility underlying contracts potential impact liquidating position orderly manner reasonable time present market conditions modeling risk credit risk counterparties operational risks needed discontinued applying tenyear liquidity valuation allowance instituted first quarter 2002 circumstances uncertainty related forward prices less liquid markets extent forward market data received third party specialist indicates value beyond ten years include value fair value trading nontrading price risk management activities income impacts trading nontrading price risk management activities included divisions merchant energy segment production segment reconciliation trading nontrading activities years ended december 31 2002 2001 follows 1 january 1 2001 adopted sfas 133 recorded cumulative effect accounting change 1921 million related hedging price risk management activities 2 includes net loss 109 million related changes market values contracts transferred trading portfolio result change manner contracts managed following coastal merger 3 includes option premiums storage capacity transactions 4 initial recorded value new contracts trading primarily comes completing snohvit lng supply contract second quarter 2002 nontrading primarily comes eagle point cogeneration restructuring transaction completed first quarter 2002 see discussion transactions results operations global power petroleum divisions 5 result discontinuance tenyear liquidity valuation allowance reversed 29 million represents remaining balance initial valuation allowance 61 million trading price risk management assets liabilities changed significantly fourth quarter 2002 partly adopted eitf issue 023 issues related accounting contracts involved energy trading risk management activities adoption eitf issue 023 following impacts financial statements eliminated marktomarket value contracts meet definition derivative including transportation storage contracts reported cumulative effect change accounting principle 225 million adjusted carrying value natural gas inventory weighted average cost value inventory exchanges expected settlement price assuming accounted basis since acquisition reported cumulative effect change accounting principle 118 million reclassified 254 million natural gas inventory exchanges price risk management assets inventory accounts receivable payable balance sheet overall adoption eitf issue 023 reduced net assets price risk management activities approximately 597 million lowered pretax net income 343 million lowered net income 222 million contracts marktomarket value eliminated accounted accrual method accounting fair value contract settlements period represents amounts traded contracts settled cash physical delivery commodity claim cash accounts receivable payable initial recorded value new contracts includes fair value origination transactions time transaction initiated change fair value contracts year represents change value contracts beginning period date origination settlement settled end period one significant factors affecting declines fair value trading nontrading price risk management activities decrease option value especially longerdated complex transactions despite commodity price volatility seen market recent months finding remaining market participants ascribing little option value types transactions additionally significant reductions creditworthiness many counterparties required adjust valuation allowances market changes particularly experienced fourth quarter recognized loss petroleum energy trading divisions due changes fair value 635 million 2002 accordance generally accepted accounting principles reflected trading portfolio estimated fair value amount contracts portfolio could bought sold current transaction willing buyers sellers however value ultimately receive settlement trading activities may less estimates disclosed previously actively liquidating trading portfolio included approximately 40000 transactions december 31 2002 believe net realizable value trading portfolio may less currently estimated fair value belief based recent transactions completed values estimated fair value bids received transactions also fair value additionally adoption eitf issue 023 portion transactions plan liquidate accounted accrual method recorded balance sheet believe amount may ultimately realize liquidation total portfolio including accrualbased portfolio could result future losses 200 million see item 8 financial statements supplementary data note 1 revenue recognition policy related activities operating results energy trading division presented year ended december 31 2002 compared year ended december 31 2001 gross margin consists revenues commodity trading origination activities less costs commodities sold including changes fair value energy trading portfolio year ended december 31 2002 gross margin 15 billion lower 2001 decrease due combination factors related changes energy trading environment approximately 13 billion decrease relates general market decline energy trading resulting lower price volatility natural gas power markets generally weaker trading credit environment 2002 additionally fourth quarter 2002 many participants trading industry including us publicly announced intent discontinue significantly reduce trading operations believe along factors caused deterioration market valuations trading marketing assets decrease fair value trading nontrading price risk management activities largely related reduced option value remainder decrease resulting volatility forward prices reductions creditworthiness counterparties decline energy trading environment caused us reduce trading origination operations resulted decrease 135 million gains transactions originated 2002 compared 2001 primarily associated transportation storage gas supply contracts operating expenses year ended december 31 2002 541 million higher 2001 significant increase relates primarily charge 487 million related western energy settlement charge 20 million related commodities futures trading commission cftc settlement see item 8 financial statements supplementary data note 2 description western energy settlement item 8 financial statements supplementary data note 20 description cftc settlement adding increase additional costs 5 million expand london operations early 2002 18 million increase staffing infrastructure costs 2002 2003 liquidated european trading assets close offices income year ended december 31 2002 11 million lower 2001 primarily due lower interest rates lower average outstanding balances interestbearing margin deposits notes receivable 2002 year ended december 31 2001 compared year ended december 31 2000 year ended december 31 2001 gross margin 163 million higher 2000 increase due higher trading margins natural gas power result increased trading volumes price volatility net reserves established result bankruptcy enron corp december 2001 operating expenses year ended december 31 2001 73 million higher 2000 increase partially result 27 million mergerrelated asset impairments 2001 remaining increase 46 million related increased personnel costs support increased origination activity expansion european operations 2001 compared 2000 income year ended december 31 2001 5 million higher 2000 increase primarily due 16 million increase income resulting higher interest rates higher average outstanding balances interestbearing margin deposits notes receivable 2001 increases offset 11 million equity earnings 2000 longer recorded upon termination engage joint venture october 2000 corporate expenses net corporate operations includes general administrative activities well operations telecommunications miscellaneous businesses 2001 significant downturn telecommunications market result refocused telecommunications strategy reduced capital investment startup business current business strategy involves primarily development wholesale metropolitan transport services primarily texas december 31 2002 net investment telecommunications business 388 million includes 163 million goodwill telecommunications business consists texasbased metro transport services collocation crossconnect services texasbased metro transport services business provides bandwidth transport services wholesale customers austin san antonio dallas ft worth houston several new initiatives aimed expanding market share within existing markets 2003 expanding business model include commercial customers launch channel partners program utilizes third party entities outside sales representatives order market existing products commercial customers also offer wholesale commercial customers additional products designed specifically leverage existing asset infrastructure including gigabit ethernet provide costeffective service ability use parts telecommunications infrastructure sbc interconnection agreement currently involved proceedings sbc could impact cost using infrastructure possibly ability use infrastructure future additional discussion proceeding see item 8 financial statements supplementary data note 20 subheading southwestern bell proceeding continuing decline telecommunications industry evaluate fair value texasbased assets including goodwill 163 million quarter determine impaired december 31 2002 assets impaired however write 15 million rightofway assets primarily northeast due decisions construct along rightsofway expand business market areas number factors could impact valuation texasbased metro transport business future including negative outcome sbc proceeding judicial legislative changes affecting current regulatory framework decline forecasted demand services areas serve decline telecommunications industry impacting ability expand business december 2002 decided exit longhaul metro dark fiber business minimal contribution activities high cost maintaining circumstances value inventory impaired accordingly fourth quarter reduced carrying value inventory 153 million 5 million addition third quarter reduction 8 million market value determined independent appraiser evaluated dark fiber value based market conditions existing fourth quarter 2002 recent liquidation values dark fiber remaining 4 million value attributable route houston texas los angeles california center arbitration proceeding us broadwing communications services discussion matter see item 8 financial statements supplementary data note 20 collocation crossconnect services available lakeside technology center chicagobased telecommunications facility provides space telecommunications carriers designed unique equipment needs well access multiple network connections various telecommunications carriers operate facility operating lease residual value guarantee 237 million second quarter 2002 reached final settlement lease agreement facility exodus communications inc filed bankruptcy although received consideration settlement resulted termination lease loss significant tenant facility building design beneficial heavy equipment low staffing needs telecommunications provider also limits alternative uses facility putting pressure fair value building significant downturn telecommunications industry consequently analyzed fair value building analysis completed third quarter 2002 estimated fair value building 162 million significantly expected residual value originally anticipated guaranteed lease agreement results contingent loss 113 million consequently amortizing deficiency remaining lease term resulted charge 11 million 2002 result charge 8 million remaining quarter may 2006 upon adoption new accounting pronouncement financial accounting standards board interpretation fin 46 july 2003 anticipate consolidate lessor facility likely require adjustment fair value facility see new accounting pronouncements issued yet adopted year ended december 31 2002 compared year ended december 31 2001 corporate net expenses year ended december 31 2002 1202 million lower 2001 decrease primarily result 1175 million mergerrelated charges asset impairments incurred 2001 connection merger coastal additional costs 144 million incurred 2001 related increased estimates environmental remediation costs legal obligations reductions fair value spare parts inventories reflect changes usability spare parts inventories corporate operations based ongoing evaluation operating standards plans following coastal merger discussion costs see item 8 financial statements supplementary data notes 4 6 also contributing decrease reduction telecommunication expenses 25 million 2002 due 2001 telecommunication organizational restructuring losses 34 million 2001 retail gas stations substantially sold 2001 addition 2002 recorded 21 million gain early extinguishment debt partially offsetting decrease year ended december 31 2002 charges 50 million severance payments related second quarter 2002 employee restructuring costs associated elimination rating stockprice triggers second quarter 2002 gemstone chaparral investments 21 million decrease pretax pension income result reduced expected rate return pension plan assets addition telecommunication operations 2002 recorded 153 million valuation adjustment dark fiber inventory 15 million impairment rightofway assets 11 million contingent loss lakeside technology center facility discussed year ended december 31 2001 compared year ended december 31 2000 corporate expenses year ended december 31 2001 1372 million higher 2000 increase primarily result additional 1082 million incurred 2001 compared 2000 mergerrelated costs asset impairments incurred 2001 connection mergers coastal sonat additional costs 144 million incurred 2001 related increased estimates environmental remediation costs legal obligations usability spare parts inventories 39 million lower margins due sale substantially retail gas stations 2001 also contributing higher costs operating losses associated telecommunications business 2001 approximately 40 million interest debt expense past three years interest debt expense increased result debt issued finance growth business segments period average debt balances increased approximately 108 billion 2000 16 billion december 31 2002 growth period raised funds domestic international capital markets majority fixed rate debt future ability access capital markets issue debt securities function market conditions time credit ratings based rating actions latter part 2002 early 2003 anticipate cost future debt issuances higher us furthermore since debt offerings foreign markets currency fluctuations impact cost debt example 2002 result weaker us dollar incurred incremental interest costs approximately 95 million euro denominated debt year ended december 31 2002 compared year ended december 31 2001 interest debt expense year ended december 31 2002 244 million higher 2001 analysis interest expense year ended december 31 millions interest expense longterm debt year ended december 31 2002 297 million higher 2001 increase due higher average debt balance 2002 issued longterm debt approximately 44 billion average interest rate 79 issuances increased interest longterm debt approximately 233 million year retired approximately 16 billion longterm debt average interest rate 51 resulting decrease interest expense retirements approximately 36 million addition incurred 95 million interest expense 2002 related foreign currency losses eurodenominated debt unhedged 2002 remaining increase primarily due various debt issuances 2001 outstanding entire year 2002 interest expense commercial paper year ended december 31 2002 56 million lower 2001 decrease due lower average shortterm interest rates commercial paper activities lower average shortterm borrowings 2002 average shortterm interest rate based daily ending rates 27 2002 versus 46 2001 average commercial paper shortterm debt balances based daily ending balances approximately 963 million 2002 versus 145 billion 2001 interest year ended december 31 2002 29 million lower 2001 decrease primarily due 23 million decrease interest resulting retirement financing obligations 8 million decrease interest receivable factoring 8 million decrease interest due termination marketing sales contract 2002 decreases partially offset 9 million increase interest debt securities issued gemstone november 2001 capitalized interest year ended december 31 2002 32 million lower 2001 primarily due lower interest rates 2002 2001 expect incur higher interest debt expense debt issuances 2003 due credit downgrades investment grade status year ended december 31 2001 compared year ended december 31 2000 interest debt expense year ended december 31 2001 116 million higher 2000 interest expense longterm debt year ended december 31 2001 61 million higher 2000 increase due higher average debt balance 2001 issued longterm debt approximately 41 billion average interest rate 61 issuances increased interest longterm debt approximately 125 million year retired approximately 16 billion longterm debt average interest rate 68 resulting decrease interest expense retirements approximately 68 million remaining increase primarily due fourth quarter 2000 debt issuances outstanding entire year 2001 interest expense commercial paper year ended december 31 2001 8 million higher 2000 increase due higher average commercial paper balances average commercial paper shortterm debt balances based daily ending balances approximately 145 billion 2001 increase offset lower average rates commercial paper shortterm borrowings year average interest rate based daily ending rates 46 2001 interest year ended december 31 2001 30 million higher 2000 increase primarily due 9 million interest expense associated swap agreement 11 million interest expense associated financing obligations capitalized interest year ended december 31 2001 17 million lower 2000 due completion west georgia facility middle 2000 minority interest consolidated subsidiaries expense associated minority interests consolidated subsidiaries year ended december 31 2002 56 million higher 2001 increase primarily due 2002 income minority owners eagle point cogeneration utility contract funding cdecca mohawk river funding iv result consolidation companies 2002 consolidations contributed 38 million 2002 increase additional 13 million increase related minority owners share gain termination nejapa power purchase agreement returns preferred interests consolidated subsidiaries year ended december 31 2002 compared year ended december 31 2001 returns preferred interests consolidated subsidiaries year ended december 31 2002 58 million lower 2001 primarily due redemptions preferred interests related el paso oil gas resources el paso oil gas associates coastal limited ventures capital trust iv partial redemption clydesdale decrease also due lower interest rates 2002 preferred returns based variable shortterm rates lower average 2002 periods 2001 partially offsetting decreases higher returns preferred interests issued part gemstone investment completed november 2001 year ended december 31 2001 compared year ended december 31 2000 returns preferred interests consolidated subsidiaries year ended december 31 2001 13 million higher 2000 higher balances minority interests result issuance additional preferred interests clydesdale topaz part gemstone transaction 2001 full year costs clydesdale capital trust iv significantly offset lower interest rates clydesdale capital trust iv formed may 2000 discussion borrowings financing activities related consolidated subsidiaries see item 8 financial statements supplementary data note 19 income tax expense income tax benefit year ended december 31 2002 495 million resulting effective tax rate 28 percent year ended december 31 2001 income tax expense 184 million resulting effective tax rate 72 percent amount 115 million related nondeductible merger charges changes estimate additional tax liabilities majority estimated additional liabilities paid 2001 contested us effective tax rate excluding charges 27 percent 2001 year ended december 31 2000 income tax expense 539 million resulting effective tax rate 30 percent differences effective tax rates statutory tax rate 35 percent years primarily result following factors state income taxes earnings unconsolidated affiliates anticipate receiving dividends nondeductible portion mergerrelated costs tax adjustments provide revised estimated liabilities foreign income taxed different rates utilization deferred credits loss carryovers nondeductible dividends preferred stock subsidiary nonconventional fuel tax credits depreciation depletion amortization reconciliation statutory rate 35 percent effective rates see item 8 financial statements supplementary data note 9 contingencies discussion contingencies see item 8 financial statements supplementary data note 20 incorporated herein reference critical accounting policies selection application accounting policies important process developed business activities evolved accounting rules developed accounting rules generally involve selection among alternatives involve implementation interpretation existing rules use judgment specific set circumstances existing business make every effort properly comply applicable rules adoption believe proper implementation consistent application accounting rules critical however situations specifically addressed accounting literature cases must use best judgment adopt policy accounting situations accomplish analogizing similar situations accounting guidance governing often consult independent accountants appropriate interpretation application policies preparation financial statements requires selection application number accounting policies discussion significant accounting policies see item 8 financial statements supplementary data note 1 defined critical accounting policies significant accounting policies involve critical accounting estimates preparation financial statements consider critical accounting estimate accounting estimate recognized financial statements requires us make assumptions matters may highly uncertain time estimate made believe accounting estimate considered critical accounting estimate changes estimates reasonably likely occur reasonably could selected different estimate either differences would resulted material impact financial condition results operations estimates assumptions future events effects cannot determined certainty base estimates historical experience various assumptions believed reasonable circumstances estimates may change new events occur additional information obtained addition management periodically faced uncertainties outcomes within control known prolonged periods time discussed development selection critical accounting policies related disclosures audit committee board directors critical accounting policies include policies related specific business units price risk management activities accounting natural gas oil producing activities well broad policies include accounting environmental reserves pension post retirement benefits areas involves complex situations high degree judgment application interpretation existing literature development estimates impact financial statements critical accounting policies identified current year may additional critical accounting policies new accounting pronouncements adopted new accounting pronouncements discussed section entitled new accounting pronouncements issued yet adopted price risk management activities account price risk management activities accordance requirements sfas 133 requires determine fair value derivative instruments use reflect balance sheet fair values changes fair value period derivative instruments except cash flow hedges recorded income statement changes fair value derivative instruments used hedge cash flows generally recognized income statement hedge settled time methods derive similar results however period income methods differ significantly derivative instruments traded active exchanges new york mercantile exchange others valued using exchange prices third party pricing data valuation techniques incorporate specific contractual terms statistical simulation analysis present value concepts one primary factors impact results period price assumptions used value derivative instruments actions limit trading activities exit trading business accessibility reliable forward market pricing data purposes estimating fair value significantly limited late 2002 result obtained valuation assistance third party valuation specialist determining fair value trading nontrading price risk management activities december 31 2002 based upon specialists input estimates fair value based upon price curves derived actual prices observed market pricing information supplied specialist independent pricing sources models rely forward pricing information estimates also reflect factors time value volatility underlying contracts potential impact liquidating position orderly manner reasonable time present market conditions modeling risk credit risk counterparties operational risks needed discontinued applying tenyear liquidity valuation allowance instituted first quarter 2002 circumstances uncertainty related forward prices less liquid markets extent forward market data received third party specialist indicates value beyond ten years include value fair value trading nontrading price risk management activities amounts report financial statements change estimates revised reflect actual results changes market conditions factors many beyond control another factor impact results period ability estimate level correlation future changes fair value hedge instrument transaction hedged time enter transaction ongoing basis hedging risk derivative instruments value intended offset value changes item hedged however complicated hedging energy commodities energy commodity prices qualitative locational differences difficult hedge effectively estimates fair value assessment correlation hedging derivatives impacted actual results changes market conditions evaluate risk trading nontrading price risk management activities using valueatrisk model determine maximum expected oneday unfavorable impact financial performance due normal market movement discussion methodology calculating valueatrisk please see item 7a quantitative qualitative disclosures market risk believe using valueatrisk methodology captures many uncertainties associated estimates trading nontrading activities reflected trading portfolio estimated fair value amount contracts portfolio could bought sold current transaction willing buyers sellers however value ultimately receive settlement trading activities may less fair value estimates disclosed previously actively liquidating trading portfolio include approximately 40000 transactions december 31 2002 believe net realizable value trading portfolio may less currently estimated fair value belief based recent transactions completed values estimated fair value bids received transactions also fair value additionally adoption eitf issue 023 portion transactions plan liquidate accounted accrual method recorded balance sheet pay counterparties assume transactions future losses result believe amount may ultimately realize liquidation total portfolio including accrualbased portfolio could result future losses 200 million asset impairments asset impairment accounting rules require us determine event occurred indicating longlived asset may impaired cases events clear cases however clearly identifiable triggering event occur rather series individually insignificant events occur time leading indication asset may impaired complicated investments foreign countries projects operator continually monitor businesses market business environments operate make judgments assessments whether triggering event occurred event occurs make estimate future cash flows assets determine asset impaired investments evaluate whether events possible outcomes indicate decline value investment occurred temporary impairment analysis generally involves assessment project level cash flows requires us make projections assumptions many years future pricing demand competition operating costs legal regulatory issues factors variables often differ estimates changes either positive negative impact estimates impairment addition changes economic business environment impact original ongoing assessments potential impairment accounting environmental reserves accrue environmental reserves assessments indicate probable liability incurred asset recovered amount reasonably estimated estimates liabilities based currently available facts existing technology presently enacted laws regulations taking consideration likely effects inflation societal economic factors include estimates associated onsite offsite groundwater technical studies legal costs amounts also consider prior experience remediating contaminated sites companies cleanup experience data released environmental protection agency organizations estimates subject revision future periods based actual costs new changing circumstances included balance sheet current longterm liabilities undiscounted amounts actual results may differ estimates often revised future either negatively positively depending upon actual outcomes changes expectations based facts surrounding exposure december 2002 accrued approximately 482 million environmental matters including approximately 463 million expected remediation costs current former operating sites associated onsite offsite groundwater technical studies approximately 19 million related environmental legal costs anticipate incurring 2027 approximately 15 million accrual related discontinued coal mining operations high end reserve estimates approximately 620 million low end approximately 427 million accrual december 31 2002 based estimated likely reasonable amount liability type site reserves based following estimates reasonably possible outcomes accounting natural gas oil producing activities use full cost method account natural gas oil producing activities accounting method capitalize substantially costs incurred connection exploration acquisition development natural gas oil reserves full cost pools maintained geographic areas regardless whether reserves actually located method differs successful efforts method accounting activities primary differences two methods treatment exploratory dry hole costs geological geophysical costs recognition gains losses properties sold exploratory dry hole costs include exploration acquisition development costs wells yield measurable reserves successful efforts method costs generally expensed determination made measurable reserves exist geological geophysical costs also expensed successful efforts full cost method dry hole costs geological costs capitalized full cost pool result financial statements differ companies apply successful efforts method since could potentially reflect higher level capitalized costs well higher depletion rate full cost accounting method required conduct quarterly impairment tests capitalized costs full cost pools impairment test referred ceiling test total capitalized costs net related income tax effects limited ceiling based present value future net revenues using end period spot prices discounted 10 percent plus lower cost fair market value unproved properties net related income tax effects discounted revenues equal greater total capitalized costs required writedown capitalized costs level primary factors could result ceiling test writedown include lower prices higher capitalized costs full cost pool lower reserve base impact hedging program ceiling test calculation assumes price effect last day quarter held constant life reserves result pricing assumption resulting value indicative true fair value reserves prices natural gas oil volatile change period attempt realize determinable cash flows use hedges decline commodity prices impact results ceiling test ceiling test charges due fluctuating prices opposed reductions underlying reserve quantities considered absolute indicator value related reserves process estimating natural gas oil reserves complex requiring significant decisions evaluation available geological geophysical engineering economic data given field may also change substantially time result numerous factors including additional development activity evolving production history continual reassessment viability production changing economic conditions result material revisions existing reserve estimates occur time although every reasonable effort made ensure reserve estimates reported represent accurate assessments possible subjective decisions variances available data various fields increases likelihood significant changes estimates reserve estimates impact several financial calculations factors held constant increase estimated proved reserves decreases unit production depletion rate higher reserves also reduce likelihood ceiling test impairments estimated reserves used calculate projected future cash flows natural gas oil properties often used collateral secure financing operations discussion reserves see part item 1 business production segment item 8 financial statements supplementary data note 28 accounting pension postretirement benefits accruals related pension postretirement benefits based actuarial calculations performing calculations actuaries must use assumptions including related return expect earn plan assets discount rates used calculating benefit obligations rate expect compensation employees increase plan term cost health care benefits provided plans factors actual results may differ assumptions included actuarial calculations result estimates associated pension postretirement benefits often revised future either negative positive effect costs recognize accruals make following table shows impact one percent change primary assumptions used actuarial calculations associated pension postretirement benefits year ended december 31 2002 millions estimates net benefit expense income partially based expected return pension plan assets use marketrelated value plan assets determine expected return pension plan assets determining marketrelated value plan assets differences expected actual asset returns deferred recognized three years due recent losses pension plan assets fair value plan assets used determine 2002 net benefit expense income less marketrelated value plan assets used fair value plan assets instead marketrelated value plan assets determining expected return pension plan assets net benefit income would 51 million lower year ended december 31 2002 recorded additional pension liability primary pension plan fair value plan assets exceeded accumulated benefit obligation plan september 30 2002 approximately 130 million plan assets exceeded accumulated benefit obligations december 31 2002 similar margin accumulated benefit obligation exceeded plan assets primary pension plan september 30 2002 would recorded pretax additional pension liability approximately 900 million plus amount equal excess accumulated benefit obligation plan assets primary pension plan would also recorded amount equal additional pension liability accumulated comprehensive loss net taxes balance sheet details significant accounting policies estimates assumptions judgments use applying policies see item 8 financial statements supplementary data note 1 new accounting pronouncements issued yet adopted december 31 2002 number accounting standards interpretations issued yet adopted us discussion significant standards could impact us accounting asset retirement obligations june 2001 financial accounting standards board fasb issued sfas 143 accounting asset retirement obligations statement requires companies record liability estimated retirement removal costs longlived assets used business liability recorded fair value corresponding asset depreciated remaining useful life longlived asset liability relates ongoing expense also recognized changes value liability result passage time provisions sfas 143 effective fiscal years beginning june 15 2002 expect record charge cumulative effect accounting change approximately 23 million net income taxes upon adoption sfas 143 january 1 2003 also expect record noncurrent retirement assets 184 million noncurrent retirement liabilities 214 million january 1 2003 liability relates primarily obligations plug abandoned wells production pipelines segments next one 101 years accounting costs associated exit disposal activities july 2002 fasb issued sfas 146 accounting costs associated exit disposal activities statement require us recognize costs associated exit disposal activities incurred rather commit exit disposal plan examples costs covered guidance include lease termination costs employee severance costs associated restructuring discontinued operations plant closings exit disposal activities statement effective fiscal years beginning december 31 2002 impact exit disposal activities initiate january 1 2003 accounting guarantees november 2002 fasb issued fin 45 guarantors accounting disclosure requirements guarantees including indirect guarantees indebtedness others interpretation requires companies record liability guarantees issued january 31 2003 including financial performance fair value guarantees liability recorded fair value upon issuance affect existing guarantees issued january 31 2003 standard also requires expanded disclosures existing guarantees december 31 2002 included required disclosures item 8 financial statements supplementary data note 20 consolidation variable interest entities january 2003 fasb issued fin 46 consolidation variable interest entities interpretation arb 51 interpretation defines variable interest entity legal entity whose equity owners sufficient equity risk andor controlling financial interest entity standard requires companies consolidate variable interest entity allocated majority entitys losses andor returns including fees paid entity provisions fin 46 effective variable interest entities created january 31 2003 effective july 1 2003 variable interest entities created january 31 2003 currently evaluating effects pronouncement reached several tentative conclusions possible impact interpretation us see item 8 financial statements supplementary data note 1 discussion conclusions reached risk factors cautionary statement purposes safe harbor provisions private securities litigation reform act 1995 report contains incorporates reference forwardlooking statements within meaning private securities litigation reform act 1995 forwardlooking statement includes statement assumptions bases underlying forwardlooking statement caution believe assumptions bases reasonable good faith assumed facts bases almost always vary actual results differences assumed facts bases actual results material depending upon circumstances forwardlooking statement management express expectation belief future results expectation belief expressed good faith believed reasonable basis cannot assure however statement expectation belief result achieved accomplished words believe expect estimate anticipate similar expressions generally identify forwardlooking statements forwardlooking statements whether written oral expressly qualified cautionary statements cautionary statements may accompany forwardlooking statements addition disclaim obligation update forwardlooking statements reflect events circumstances date report mind consider risks discussed elsewhere report documents file commission time following important factors could cause actual results differ materially expressed forwardlooking statement made us behalf substantial debt downgrades credit ratings investment grade significantly impacted continue significantly impact liquidity substantial debt december 31 2002 total longterm capital market debt bank debt financing obligations approximately 167 billion including approximately 85 billion subsidiary debt also guarantees approximately 25 billion preferred interests consolidated subsidiaries approximately 33 billion ratings assigned outstanding senior unsecured indebtedness downgraded investment grade currently rated caa1 moodys b standard poors remain negative outlook agencies ratings increased increase cost capital collateral requirements could impede access capital markets result recent downgrades realized substantial demands liquidity demands included application cash required withheld cash management program order redeem preferred membership interests one minority interest financing structures cash collateral margin requirements associated contractual commitments subsidiaries downgrades may subject us additional liquidity demands future downgrades result least part outlook generally consolidated businesses liquidity needs order meet shortterm liquidity needs embarked 2003 operational financial plan contemplates drawing part availability existing bank facilities consummating significant asset sales addition may take additional steps entering financing activities renegotiating credit facilities reducing capital expenditures provide additional liquidity assurance actions consummated favorable terms even consummated actions successful satisfying liquidity needs event liquidity needs satisfied could forced seek protection creditors bankruptcy development could materially adversely affect financial condition ongoing litigation investigations could significantly adversely affect business march 20 2003 entered agreement principle western energy settlement various public private claimants including states california washington oregon nevada resolve principal litigation claims regulatory proceedings us subsidiaries relating sale delivery natural gas electricity september 1996 date western energy settlement information matters see part ii item 8 financial statements supplementary data notes 2 20 unable negotiate definitive settlement agreements settlement approved courts ferc proceedings litigation continue since july 2002 twelve purported shareholder class action suits alleging violations federal securities laws filed us several officers eleven suits consolidated federal court houston single judge suits generally challenge accuracy completeness press releases public statements made 2001 2002 twelfth shareholder class action lawsuit filed federal court new york city october 2002 challenging accuracy completeness february 27 2002 prospectus equity offering completed june 21 2002 since dismissed light similar claims asserted consolidated suits houston four shareholder derivative actions also filed one shareholder derivative lawsuit filed federal court houston august 2002 derivative action generally alleges claims made shareholder class action consolidated shareholder class actions pending houston stayed second shareholder derivative lawsuit filed delaware state court october 2002 generally alleges claims made consolidated shareholder class action lawsuit third shareholder derivative suit filed state court houston march 2002 fourth shareholder derivative suit filed state court houston november 2002 third fourth shareholder derivative suits generally allege manipulation california gas supply gas prices exposed us claims antitrust conspiracy ferc penalties erosion share value december 2002 another action filed federal court houston behalf participants el paso corporation retirement savings plan time legal exposure related lawsuits claims determinable prevail cases litigation administrative regulatory matters may party described item 8 financial statements supplementary data note 20 remedy adopted cases substantially impairs financial position longterm adverse impact credit rating liquidity ability raise capital meet ongoing future investing financing needs could substantial may achieve objectives set forth 2003 operational financial plan timely manner ability achieve stated objectives 2003 operational financial plan well timing achievement subject factors beyond control including ability raise cash asset sales may impacted ability locate potential buyers timely fashion obtain reasonable price competing assets sales programs competitors fail timely achieve plan even achieved fails effects liquidity financial position anticipate liquidity financial position could materially adversely affected objectives exiting energy trading business petroleum business may achieved time period manner expect november 2002 announced intention exit energy trading business pursue orderly liquidation trading portfolio february 2003 announced intention sell remaining petroleum assets excluding aruba refinery unable achieve objectives time period manner expect could substantial negative impact cash flows liquidity financial position ability achieve goals liquidation trading portfolio subject factors beyond control including among others liquidity constraints experienced counterparties energy trading business obtaining maximum cash flow trading portfolio isolating credit liquidity needs energy trading business rest business additionally amounts actually realized liquidation energy trading business could significantly less amounts currently expect liquidations ongoing losses trading business expected incurred positions liquidated ability achieve goals sale petroleum assets subject factors beyond control including among others ability locate potential buyers timely fashion obtain reasonable price competing asset sales programs competitors proxy contest initiated selim zilkha replace board directors could material adverse effect us february 18 2003 selim zilkha one stockholders announced intention initiate proxy solicitation replace entire board directors nominees march 11 2003 mr zilkha filed preliminary proxy statement effect sec proxy contest may disruptive may negatively impact ability achieve stated objectives 2003 operational financial plan addition may difficulty attracting retaining key personnel proxy contest resolved therefore proxy contest whether successful could material adverse effect liquidity financial condition results investigations reporting trading information could adversely affect business response october 2002 data request ferc conducted investigation accuracy information employees el paso merchant energy subsidiary voluntarily reported trade publications part investigation discovered inaccurate information submitted trade publications one el paso merchant energys former employees arrested charged knowingly submitting inaccurate data trade publication continued policy cooperation office us attorney ferc intend take whatever remedial steps necessary ensure operations conducted integrity however investigations continuing assurance penalties sanctions imposed us turn could adversely affect business success pipeline field services businesses depends factors beyond control natural gas natural gas liquids transport gather process store owned third parties result volume natural gas natural gas liquids involved activities depends actions third parties beyond control following factors beyond control may unfavorably impact ability maintain increase current throughput renegotiate existing contracts expire remarket unsubscribed capacity future weather conditions including favor alternative energy sources price competition drilling activity supply availability expiration andor turn back significant capacity service area competition changes regulation action regulatory bodies credit risk customer base increased cost capital natural gas liquids prices revenues pipeline businesses generated contracts must renegotiated periodically substantially pipeline subsidiaries revenues generated contracts expire periodically must renegotiated extended replaced cannot assure able extend replace contracts expire terms renegotiated contracts favorable existing contracts particular ability extend andor replace contracts could adversely affected factors cannot control including proposed construction companies additional pipeline capacity markets served interstate pipelines changes state regulation local distribution companies may cause negotiate shortterm contracts turn back capacity contracts expire reduced demand market conditions availability alternative energy sources gas supply points regulatory actions unable renew extend replace contracts renew less favorable terms may suffer material reduction revenues earnings fluctuations energy commodity prices could adversely affect pipeline field services businesses revenues generated transmission storage gathering processing contracts depend volumes rates affected prices natural gas natural gas liquids increased prices could result loss load customers power companies dispatching gas fired plants industrial plant shutdown load loss competitive fuels local distribution companies loss customer base success transmission gathering processing operations subject continued development additional oil natural gas reserves ability access additional suppliers interconnecting pipelines offset natural decline existing wells connected systems decline energy prices could precipitate decrease development activities could cause decrease volume reserves available transmission gathering processing systems facilities fluctuations energy prices caused number factors including regional domestic international supply demand availability adequacy transportation facilities energy legislation federal state taxes sale transportation natural gas natural gas liquids abundance supplies alternative energy sources political unrest among oil producing countries agencies regulate pipeline businesses customers affect profitability pipeline businesses regulated ferc us department transportation various state local regulatory agencies regulatory actions taken agencies potential adversely affect profitability particular ferc regulates rates pipelines permitted charge customers services pipelines tariff rates reduced future proceeding pipelines volume business currently permitted rates decreased significantly pipelines required substantially discount rates services competition profitability pipeline businesses could reduced state agencies regulate pipelines local distribution company customers could impose requirements could impact demand pipelines services success natural gas oil exploration production businesses dependent factors beyond control performance natural gas oil exploration production businesses dependent upon number factors cannot control factors include fluctuations natural gas crude oil prices including basis differentials results future drilling activity ability identify precisely locate prospective geologic structures drill successfully complete wells structures timely manner ability expand leased land positions desirable areas often subject intensely competitive leasing conditions increased competition search acquisition reserves risks incident operations natural gas oil wells future drilling production development costs including drilling rig rates oil field services costs future tax policies rates drilling production incentives state federal foreign governments increased federal state regulations including environmental regulations limit restrict ability drill natural gas oil wells reduce operational flexibility increase capital operating costs decreased demand use natural gas oil market concerns global warming changes governmental policies regulations due climate change initiatives continued access sufficient capital fund drilling programs develop replace reserve base rapid depletion characteristics estimates natural gas oil reserves may change actual production revenues taxes development expenditures operating expenses respect reserves likely vary estimates proved reserves natural gas oil variances may material process estimating natural gas oil reserves complex requiring significant decisions assumptions evaluation available geological geophysical engineering economic data reservoir deposit result estimates inherently imprecise actual future production natural gas oil prices revenues taxes development expenditures operating expenses quantities recoverable natural gas oil reserves may vary substantially estimates addition may required revise reserve information downward upward based production history results future exploration development prevailing natural gas oil prices factors many beyond control success power generation activities depends many factors beyond control success domestic international power projects could adversely affected factors beyond control including alternative sources supplies energy becoming available due new technologies interest self generation cogeneration increases costs generation including increases fuel costs uncertain regulatory conditions resulting ongoing deregulation electric industry us foreign jurisdictions ability negotiate successfully enter restructure recontract advantageous longterm power purchase agreements possibility reduction projected rate growth electricity usage result factors regional economic conditions excessive reserve margins implementation conservation programs risks incidental operation maintenance power generation facilities inability customers pay amounts owed power purchase agreements increasing price volatility due deregulation changes commodity trading practices use derivative financial instruments could result financial losses subsidiaries use futures swaps option contracts traded new york mercantile exchange overthecounter options price basis swaps natural gas merchants financial institutions could incur financial losses future result volatility market values energy commodities trade one counterparties fails perform contract valuation financial instruments involve estimates changes assumptions underlying estimates occur changing valuation instruments potentially resulting financial losses extent hedge commodity price exposure interest rate exposure forego benefits would otherwise experience commodity prices increase interest rates change use derivatives also requires posting cash collateral counterparties impact working capital commodity prices interest rates change additional information concerning derivative financial instruments see item 7a quantitative qualitative disclosures market risk item 8 financial statements supplementary data note 13 foreign operations investments involve special risks activities areas outside us subject risks inherent foreign operations including loss revenue property equipment result hazards expropriation nationalization wars insurrection political risks effects currency fluctuations exchange controls devaluation foreign currencies economic problems changes laws regulations policies foreign governments including associated changes governing parties costs environmental liabilities regulations litigation could exceed estimates operations subject various environmental laws regulations laws regulations obligate us install maintain pollution controls clean various sites regulated materials may disposed released sites designated superfund sites epa comprehensive environmental response compensation liability act also party legal proceedings involving environmental matters pending various courts agencies possible us estimate reliably amount timing future expenditures related environmental matters uncertainties estimating clean costs discovery new sites information uncertainty quantifying liability environmental laws impose joint several liability potentially responsible parties nature environmental laws regulations possible introduction future environmental laws regulations although believe established appropriate reserves liabilities including clean costs could required set aside additional reserves future due uncertainties additional information concerning environmental matters see item 8 financial statements supplementary data note 20 operations subject operational hazards uninsured risks operations subject inherent risks normally associated operations including pipeline ruptures explosions pollution release toxic substances fires adverse weather conditions hazards could result damage destruction facilities damages persons property addition operations face possible risks associated acts aggression domestic foreign assets events occur could suffer substantial losses maintain insurance many risks financial condition operations could adversely affected significant event occurs fully covered insurance terrorist attacks aimed energy operations could adversely affect business september 11 2001 us target terrorist attacks unprecedented scale since september 11th attacks us government issued warnings energy assets including nations pipeline infrastructure may future target terrorist organizations developments subjected energy operations increased risks future terrorist attack facilities customers cases energy companies could material adverse effect business breach covenants applicable longterm debt financial obligations could accelerate longterm debt financial obligations subsidiaries longterm debt financial obligations contain restrictive covenants crossacceleration provisions breach covenants could accelerate longterm debt financial obligations subsidiaries occur may able repay longterm debt financing obligations upon acceleration subject financing interest rate exposure risks future success depends ability access capital markets obtain financing cost effective rates addition recent downgrades current credit ratings triggered higher cash requirements operating costs energy trading business process exiting pursuant orderly liquidation trading portfolio ability access financial markets obtain costeffective rates future dependent number factors many cannot control including changes credit ratings interest rates structured commercial financial markets market perceptions us natural gas energy industry tax rates due new tax laws stock price face competition third parties produce transport gather process fractionate store otherwise handle oil natural gas natural gas liquids petroleum products natural gas oil business highly competitive search acquisition reserves gathering marketing natural gas oil production competitors include major oil companies independent oil gas concerns individual producers gas marketers major pipeline companies well participants industries supplying energy fuel industrial commercial individual consumers unable compete effectively services offered energy enterprises future profitability may negatively impacted item 7aitem 7 managements discussion analysis financial condition results operations managements discussion analysis includes forwardlooking statements subject risks uncertainties actual results may differ substantially statements make section due number factors discussed beginning page 78 historical financial information section restated discussed item 8 financial statements supplementary data note 1 information contained discussion also presents petroleum markets coal mining businesses discontinued operations periods overview business purpose provide natural gas related energy products safe efficient dependable manner north americas largest natural gas pipeline system large independent natural gas producer also operate midstream assets investments domestic international power business energy marketing trading business small telecommunications business currently sale sold petroleum coal liquified natural gas businesses since end 2001 business activities largely focused maintaining core businesses pipelines production attempting liquidate otherwise divest businesses operations core longterm objectives performing consistently expectations time made investment overall objective period reduce debt improve liquidity time invest core business activities 2002 2003 spent 87 percent 91 percent respectively capital investment dollars pipeline midstream production businesses liquidated divested interests many noncore assets coupled declines value business ventures sales resulted sales prices well carrying values businesses assets resulting significant recorded losses year ended december 31 2003 year significant change business strategy financial condition 2003 completed sale number assets investments including production properties 50 percent general partner interest gulfterra significant portion worldwide petroleum markets operations portion domestic power generation operations merchant lng business total proceeds sales approximately 33 billion completed number financial transactions allowed us maintain access needed capital meet cash requirements simplify capital structure eliminate significant amount offbalance sheet obligations preferred securities implemented costreduction program identified 445 million cost reductions business 2003 2004 initiated program targeting additional 150 million savings 2006 completed western energy settlement became effective june 2004 resolving substantial uncertainty arising california energy crisis 2001 announced longrange plan among things defines core businesses establishes timeline debt reduction sets timetable exiting noncore businesses assets sets financial goals company many changes experienced 2003 resulted significant losses declining operating cash flows produced businesses furthermore february 2004 completed december 31 2003 reserve estimation process proved natural gas oil reserves production segment results process indicated significant downward revision reserve estimates needed august 2004 also determined properly applied generally accepted accounting principles related many historical hedges primarily associated hedges anticipated natural gas production investigations issues determined restatement historical financial information required accordingly restated historical financial statements reflect financial impact revised proved reserve estimates revise historical accounting derivatives see item 8 financial statements supplementary data note 1 discussion restatements events described increased risk involved owning securities despite reductions credit ratings well investment grade believe longrange plan outlined allow us manage increased risks acceptable manner allow us become strong natural gas company north america following sections managements discussion analysis address events outlook longrange plan greater detail capital structure 2003 took steps intended simplify financial capital structure refinance shorter term obligations reduce guarantees offbalance sheet obligations replacing direct financial obligations actions included entering new 3 billion revolving credit facility acquiring consolidating number entities existing debt refinancing shorterterm obligations longerterm borrowings redeeming eliminating preferred interests subsidiaries follows millions 1 includes 500 million borrowings 1150 million repayments 3 billion revolving credit facility 2 approximately 16 billion amount relates nonrecourse project financing contract debt includes 75 million related macae consolidated consequence acquisition gemstone april 2003 3 relates adoption sfas 150 see item 8 financial statements supplementary data notes 2 20 21 4 includes 571 million debt obligations related sale east coast power 139 million related sale mohawk river funding 5 see item 8 financial statements supplementary data note 24 6 redemptions eliminations represent preferred interests consolidated subsidiaries either repaid refinanced debt 7 include 370 million longterm debt retired march 2004 related aruba refinery classified discontinued operations 174 million debt related power assets classified held sale discussion longterm debt financing obligations credit facilities see item 8 financial statements supplementary data note 20 capital resources liquidity rely cash generated internal operations primary source liquidity well available credit facilities project bank financings proceeds asset sales issuance longterm debt preferred securities equity securities time also used structured financing transactions sometimes referred offbalance sheet arrangements expect future funding working capital needs capital expenditures longterm debt repayments dividends financing activities continue provided sources although expect use offbalance sheet arrangements degree future existing projected sources cash impacted operational financial risks influence overall amount cash generated capital available us example cash generated business operations may impacted changes commodity prices demands commodities services due weather patterns competition providers alternative energy sources collateral demands recovery cash posted collateral impacted natural gas prices hedging levels credit quality us counterparties cash generated future asset sales may depend overall economic conditions industries served assets condition location assets number interested buyers addition future liquidity impacted ability access capital markets may restricted due credit ratings general market conditions limitations ability access shelf registration statement discussed item 8 financial statements supplementary data note 20 discussion risks impact liquidity see risk factors beginning page 78 following summary cash flow activities january 1 2004 june 30 2004 1 2004 made payments western energy settlement approximately 602 million included 468 million held escrow december 31 2003 602 million payment liability shown operating cash outflow decrease restricted cash related release escrowed funds shown cash inflow investing activities 2 relates primarily proceeds sale aruba refinery first half 2004 discretionary maintenance capital needs met primarily operating cash flows next twelve months anticipate discretionary maintenance capital needs continue met primarily operating cash flows supplemented continued recovery cash provided collateral various counterparties project financings cheyenne plains project estimated cash flow cash requirements may change significantly analysis intended provide better understanding liquidity outlook following tables reflect available liquidity june 30 2004 estimated sources uses funds period july 2004 june 2005 billions 1 upon close enterprise transaction includes sale series c units gulfterra collateralize revolver borrowing capacity revolver decrease approximately 05 billion 2 includes approximately 10 billion expected received upon completion enterprise transaction 08 billion received upon completion remaining announced power plant asset sales 3 reflect 11 billion letters credit issued pursuant 3 billion revolving credit facility process refinancing facility matures june 30 2005 net available liquidity includes 3 billion revolving credit facility matures june 30 2005 facility collateralized equity interests tgp epng anr cig southern gas storage company anr storage company series common units series c units gulfterra process negotiating refinancing facility currently expect successful obtaining refinancing event unable refinance existing 3 billion revolving credit facility june 30 2005 would obligated repay outstanding amounts make alternative arrangements letters credit issued pursuant credit facility june 30 2004 borrowed 600 million issued approximately 11 billion letters credit facility although expect successfully refinance portion existing 3 billion revolving credit facility unsuccessful believe could adjust planned capital expenditures increase planned asset sales meet shortfall liquidity time provide operations company required repay obligations 3 billion revolving credit facility many assets currently collateralize facility including equity interests tgp epng anr cig southern gas storage company anr storage company series common units gulfterra would become available support new financing transactions although cannot guarantee outcome future events believe available collateral would adequate provide financing sufficient meet liquidity needs february 2004 completed december 31 2003 reserve estimation process proved natural gas oil reserves production segment result review announced significantly reducing proved natural gas oil reserve estimates august 2004 also determined properly accounted certain derivatives primarily related hedges anticipated natural gas production investigations matters concluded restatement historical financial statements matters required believe material restatements financial statements discussed item 8 financial statements supplementary data note 1 would constituted events default 3 billion revolving credit facility various financing transactions specifically provisions arrangements related representations warranties accuracy historical financial statements debt total capitalization ratio 2004 received several waivers 3 billion revolving credit facility various financing transactions address issues waivers continue effective also received extension time various lenders november 30 2004 file first second quarter 2004 forms 10q expect meet unable file forms 10q date able negotiate additional extension filing deadline 3 billion revolving credit facility various transactions could accelerated part obtaining waivers also amended various provisions 3 billion revolving credit facility including provisions related events default limitations ability well ability subsidiaries repay indebtedness scheduled mature june 30 2005 based upon review covenants contained indentures financing agreements outstanding indebtedness acceleration 3 billion revolving credit facility could constitute event default debt agreements addition three subsidiaries indentures associated public debt contain 5 million crossacceleration provisions various financing arrangements entered us subsidiaries including el paso cgp company el paso cgp el paso production holding company include covenants require us file financial statements within specified time periods noncompliance covenants constitute automatic event default instead agreements subject acceleration indenture trustee holders least 25 percent outstanding principal amount series debt provides notice issuer noncompliance indenture event noncompliance cured filing financial statements within specified periods time 30 90 days receipt notice depending particular indenture avoid acceleration repayment holders el paso production holding companys debt obligations waived financial filing requirements december 31 2004 filing first second quarter 2004 forms 10q subsidiaries cure events noncompliance resulting failure file financial statements subsidiaries addition neither subsidiaries received notice default caused failure subsidiaries file financial statements event acceleration may unable meet payment obligations respect related indebtedness furthermore material restatement financial statements period ended december 31 2001 could cause default financing agreements entered connection 950 million gemstone notes due october 31 2004 currently 748 million gemstone notes outstanding however currently expect repay notes full upon maturity october 31 2004 subsidiaries significant potential source liquidity us participate cash management program extent permitted financing agreements indentures cash management program depending whether participating subsidiary shortterm cash surpluses requirements either provide cash provides cash us incur event default credit facilities would unable obtain cash pipeline subsidiaries primary source cash program currently one subsidiaries cig advancing funds us via cash management program due expected cash needs addition ownership interests number subsidiaries investments serve collateral revolving credit facility borrowings lenders credit facility borrowings exercise rights collateral could required liquidate investments result events described subject voluntary involuntary bankruptcy proceedings creditors could attempt make claims subsidiaries including claims substantively consolidate subsidiaries believe claims substantively consolidate subsidiaries would without merit however assurance creditors would advance claim bankruptcy proceeding creditors able substantively consolidate subsidiaries bankruptcy proceeding could material adverse effect financial condition liquidity despite events described believe able meet liquidity cash needs remainder 2004 june 2005 combination sources including cash hand cash generated operations borrowings 3 billion revolving credit facility proceeds asset sales reduction discretionary capital expenditures possible issuance longterm debt preferred andor equity securities however number factors could influence liquidity sources well timing ultimate outcome ongoing efforts plans factors discussed detail beginning page 78 overview cash flow activities 2003 years ended december 31 2003 2002 cash flows summarized follows 1 individual line items cash flows operating activities restated total cash flows continuing operating activities investing activities financing activities well discontinued operations unaffected restatements generated cash several sources including principal continuing operations well discontinued operations sales assets issuances longterm debt used major portion cash fund capital expenditures purchase additional investments subsidiaries retire longterm debt make payments amounts outstanding revolving credit facilities redeem preferred interests several subsidiaries held minority interest owners overall cash sources uses 2003 summarized follows billions cash continuing operating activities overall cash generated continuing operating activities 24 billion 2003 versus 07 billion 2002 17 billion yearoveryear increase operating cash flow due primarily timing cash receipts payments related energy marketing trading operations 2002 increases natural gas prices credit rating downgrades caused us use approximately 09 billion operating cash flow meet margin calls trading positions late 2002 began actively liquidating positions trading portfolio part recover cash part reduction involvement energy trading activities 2003 generated operating cash flow approximately 05 billion primarily settlement positions trading portfolio since beginning 2003 recovered 01 billion cash posted collateral margin call requirements overall reduction transactions requiring collateral also recovered cash totalling 06 billion margin calls 2003 substituting letters credit 3 billion revolving credit facilities actual cash deposit result overall margin activity 2003 source cash approximately 07 billion cash margin positions significantly impacted credit quality credit quality counterparties commodity prices availability letter credit noncash collateral following credit rating downgrades credit extended us counterparties lowered requiring us post additional margins many counterparties also posted letters credit us requiring us return margin deposits addition impact operating cash flows changes commodity prices depends whether prices derivative instruments market prices time prices market 2002 2003 required make margin deposits however margin deposits recovered sell underlying commodities settle positions natural gas prices decrease december 31 2003 held 02 billion cash 03 billion letters credit collateral third parties related price risk management activities posted collateral 02 billion cash 09 billion letters credit third parties related activities partially offsetting overall increase operating cash flow yearoveryear 04 billion increase interest payments longterm financing obligations resulted issuance consolidation debt 2003 cash continuing investing activities net cash used continuing investing activities 16 billion year ended december 31 2003 continuing investing activities consisted primarily capital expenditures equity investments 36 billion additions restricted cash 05 billion offset net proceeds sales assets investments 25 billion 2003 capital expenditures net additions equity investments included following billions 1 amounts include 02 billion capital expenditures paid 2003 related projects started costs accrued prior years 2 amount primarily related purchases third party investment interests chaparral gemstone see item 8 financial statements supplementary data note 3 indicated currently expect reduce total capital expenditures production segment approximately 14 billion 2003 approximately 850 million 2004 october 2003 entered agreements two separate third parties whereby agreed contribute capital drilling completion two specific packages wells exchange net profits interest well 2003 received funds approximately 130 million third parties agreements supplemented overall capital program additional wells drilled agreements 2004 one party elected cease investment one specific packages wells additional funds received 2004 agreements supplement 2004 capital program see item 8 financial statements supplementary data note 30 discussion agreements cash received continuing investing activities includes 25 billion sale assets investments asset sales proceeds primarily relate sales natural gas oil properties western canada new mexico texas louisiana oklahoma gulf mexico 07 billion sale equity investment ce generation 02 billion sale east coast power 04 billion sale pipelines power processing assets 06 billion sale 50 percent interest general partner gulfterra interests gulfterra 06 billion segment sales completed 2003 2002 announced date completed 2004 follows 1 excludes proceeds sales discontinued operations 128 million 2002 747 million 2003 905 million 2004 continue divest noncore assets based strategic direction outlined longrange plan see item 1 business discussion longrange plan item 8 financial statements supplementary data notes 4 12 discussion divestitures asset divestitures discontinued operations cash continuing financing activities net cash used continuing financing activities 09 billion year ended december 31 2003 cash provided financing activities included net proceeds issuance longterm debt 36 billion 04 billion cash contributed discontinued operations cash generated issuance common stock 01 billion cash used financing activities included net repayments 07 billion revolving credit facilities 28 billion payments made retire third party longterm debt also paid 13 billion fully redeem trinity river clydesdale coastal securities preferred securities transactions paid dividends common stockholders 02 billion see item 8 financial statements supplementary data note 20 detail financing activities cash flows discontinued operations 2003 discontinued operations generated 04 billion cash sales inventories refineries asset sales raised combined 06 billion offset capital expenditures 02 billion net cash inflows distributed continuing operations contractual obligations offbalance sheet arrangements course business activities enter variety financing arrangements contractual obligations following discusses contingent obligations often referred offbalance sheet arrangements also present aggregated information contractual cash obligations reflected financial statements short longterm debt accrued liabilities obligations operating leases capital commitments reflected financial statements offbalance sheet arrangements related liabilities guarantees involved various joint ventures ownership arrangements sometimes require additional financial support results issuance financial performance guarantees financial guarantee obligated make payments guaranteed party fails make payments violates terms financial arrangement performance guarantee provide assurance guaranteed party execute terms contract required perform behalf example guaranteed party required deliver natural gas third party fails would required either deliver natural gas make payments third party equal difference contract price market value natural gas december 31 2003 approximately 277 million financial performance guarantees otherwise reflected financial statements also periodically provide indemnification arrangements related assets businesses sold arrangements include indemnifications income taxes resolution existing disputes environmental matters necessary expenditures ensure safety integrity assets sold cases evaluate time guaranty entered period thereafter whether liability exists estimated record accruals criteria met december 31 2003 accrued 78 million related arrangements 2003 completed consolidation andor repayment remaining offbalance sheet obligations including chaparral gemstone residual value guarantees related two operating leases lakeside technology center telecommunications facility aruba refinery contractual obligations following table summarizes contractual obligations december 31 2003 years presented amounts undiscounted 1 see item 8 financial statements supplementary data note 20 2 see item 8 financial statements supplementary data note 6 december 31 2003 held deposits 468 million escrow account fund portion obligation june 2004 paid approximately 602 million related obligation 3 includes contractual environmental obligations included noncurrent liabilities balance sheet excludes expected contributions pension postretirement benefit plans 65 million 2004 229 million four year period ended december 31 2008 expected contributions contractually required 4 see item 8 financial statements supplementary data note 22 5 contractual commitments purchase obligations defined legally enforceable agreements purchase goods services fixed minimum quantities fixed minimum variable price provisions detail approximate timing underlying obligations 6 commitments demand charges tolling arrangements firm access natural gas transportation storage capacity 7 includes purchase commitments natural gas power 8 includes commitments drilling seismic activities production operations various maintenance engineering procurement construction contracts used operations commoditybased derivative contracts utilize derivative financial instruments hedging activities power contract restructuring activities historical energy trading activities tables derivatives designated hedges primarily consist instruments used hedge natural gas production derivatives power contract restructuring activities relate power purchase sale agreements arose activities business commoditybased derivative contracts relate historical energy trading activities following table details fair value commoditybased derivative contracts year maturity valuation methodology december 31 2003 1 includes 189 million intercompany derivatives eliminate consolidation impact consolidated assets liabilities price risk management activities 2004 sold power contract derivatives representing 942 million total assets power contract restructuring derivatives december 31 2003 2 exchangetraded positions traded active exchanges new york mercantile exchange international petroleum exchange london clearinghouse reconciliation commoditybased derivatives years ended december 31 2003 2002 amounts reflect restatement derivatives historically accounted hedges determined qualify hedge accounting august 2004 determined incorrectly accounted certain historical hedges primarily associated natural gas production see item 8 financial statements supplementary data note 1 discussion restatement fair value contract settlements period represents estimated amounts derivative contracts settled physical delivery commodity claim cash accounts receivable payable fair value contract settlements also includes physical financial contract terminations due counterparty bankruptcies sale settlement derivative contracts early termination sale entities contracts initially recorded value new contracts includes fair value origination transactions inception transaction 2002 initially recorded value new contracts includes 59 million gain related completion snohvit lng supply contract commoditybased derivatives 898 million gain related eagle point power contract restructuring transaction change fair value contracts year represents change value contracts beginning period date origination acquisition settlement settled end period 2003 conjunction acquisition chaparral consolidated derivative contracts fair value approximately 12 billion date acquired majority value contracts power purchase agreements power supply agreements related power contract restructuring activities conducted chaparral results operations overview since 2001 experienced tremendous change businesses prior time grown mergers acquisitions internal growth initiatives time incurred significant amounts debt obligations late 2001 driven bankruptcy number energy sector participants followed increased scrutiny debt levels credit rating downgrades debt many competitors focus changed improving liquidity paying debt resolving substantial contingences returning core natural gas businesses accordingly operating results three year period substantially impacted number significant events asset sales significant legal settlements ongoing business restructuring efforts part change focus february 2004 completed december 31 2003 reserve estimation process proved natural gas oil reserve estimates results process indicated 18 tcfe downward revision proved reserves needed investigation factors caused revision determined material portion reserve revisions reflected historical periods annual report form 10k august 2004 also determined properly applied accounting related many historical hedges primarily associated hedges anticipated natural gas production following investigation matter concluded historical financial statements restated accordingly historical financial results 1999 2002 first three quarters 2003 restated matters see item 8 financial statements supplementary data note 1 discussion restatements december 31 2003 operating business segments pipelines production field services merchant energy segments provide variety energy products services managed separately requires different technology operational marketing strategies longrange plan announced december 2003 businesses divided two primary business lines regulated unregulated regulated business include existing pipelines segment unregulated business include existing production field services merchant energy segments management uses ebit assess operating results effectiveness business segments define ebit net income loss adjusted items impact income loss continuing operations extraordinary items discontinued operations impact accounting changes ii income taxes iii interest debt expense iv distributions preferred interests consolidated subsidiaries businesses consist consolidated operations well investments unconsolidated affiliates exclude interest debt expense distributions preferred interests consolidated subsidiaries investors may evaluate operating results without regard financing methods capital structure believe ebit helpful investors allows effectively evaluate operating performance consolidated businesses unconsolidated investments using performance measure analyzed internally management ebit may comparable measurements used companies additionally ebit considered conjunction net income performance measures operating income operating cash flow reconciliation ebit segment consolidated net loss three years ended december 31 earnings period impacted favorably unfavorably number factors affecting businesses enumerated table discussion follows summarizes factors impact operating segments corporate operations detailed discussion factors items impacting financial performance see individual segment results included item 8 financial statements supplementary data notes 5 10 28 1 includes net impairments costbased investments included income expense 2 includes 51 million accretion expense 15 million charges included operation maintenance expense associated western energy settlement 3 includes 182 million charges related changes accounting estimates 2001 associated additional environmental remediation liabilities accrued legal obligations usability spare parts inventories indicated tables ebit past three years impacted number significant developments events business industry addition items described two operating segments experienced significant earnings volatility period much volatility occurred merchant energy segment beginning 2002 merchant energy began process exiting trading business time overall energy trading industry declined following financial collapse enron late 2001 combination actions events resulted substantial losses merchant energy 2002 2003 compared 2001 expect segment continue experience losses 2004 continues liquidation trading business production segment also experienced earnings volatility 2001 2003 benefited favorable pricing environment allowed improved results however threeyear period production segment sold significant number natural gas oil properties coupled generally disappointing drilling results mechanical failures certain wells produced steady decline production volumes timeframe favorable pricing environment continue provide benefits segment 2004 although future results largely impacted ability grow existing reserve base successful drilling program andor acquisitions finally 2001 2002 2003 incurred approximately 18 billion including 14 billion 2003 pretax losses exiting petroleum markets coal chemicals businesses classified discontinued operations discussion year results business segments corporate activities interest debt expense distributions preferred interests consolidated subsidiaries income taxes results discontinued operations individual segment results 2002 2001 well nine months ended september 30 2003 pipelines production merchant energy segments presented discussed restated adjustments natural gas reserve estimates manner accounted many historical hedges primarily associated hedges anticipated natural gas production see item 8 financial statements supplementary data note 1 discussion restatements manner segments affected addition merchant energy segment restated reflect reclassification historical coal mining petroleum markets businesses discontinued operations regulated businesses pipelines segment pipelines segment consists interstate natural gas transmission storage related services primarily us interstate natural gas transportation systems face varying degrees competition pipelines well alternative energy sources used generate electricity hydroelectric power nuclear coal fuel oil addition customers shifted traditional dependence solely longterm contracts portfolio approach balances shortterm opportunities longterm commitments shift impacted volatility revenues due changes market conditions competition driven state utility deregulation local distribution company mergers new supply sources volatility natural gas prices demand shortterm capacity new markets power plants regulated ferc regulates rates charge customers rates function costs providing services customers including reasonable return invested capital result revenues historically relatively stable however subject volatility due factors weather changes natural gas prices market conditions regulatory actions competition creditworthiness customers addition ability extend existing customer contracts remarket expiring contracted capacity dependent competitive alternatives regulatory environment federal state local levels market supply demand factors relevant dates contracts extended expire duration new renegotiated contracts affected current prices competitive conditions judgments concerning future market trends volatility subject regulatory constraints attempt recontract remarket capacity maximum rates allowed tariffs although times discount rates remain competitive level discount varies pipeline systems addition ferc issued various orders related allocation capacity epng system one pipeline systems orders impacted 2003 pipeline segment revenues continue impact future results addition expect lower annual revenues approximately 22 million due expiration certain risk sharing provisions epng system operating results analysis results pipelines segment three years ended december 31 1 within revenues operating expenses amounts recorded number natural gas purchase sale agreements contracts based market prices impact revenues operating expenses little impact operating income ebit years ended december 31 2003 2002 2001 revenues contracts 70 million 56 million 91 million operating expenses 68 million 53 million 90 million 2 throughput volumes excludes volumes related equity investments alliance pipeline portland natural gas transmission systems sold throughput volumes exclude intrasegment activities prior period volumes restated reflect current year presentation includes billable transportation throughput volume storage injection withdrawal segment results restated 2002 2001 reflect adjustments nonqualifying cash flow hedges production owned cig discussion restatement see item 8 financial statements supplementary data note 1 year ended december 31 2003 compared year ended december 31 2002 year ended december 31 2003 ebit 418 million higher 2002 reduced operating expenses 238 million higher nonoperating income 143 million improved revenues 37 million 2003 contributed improved ebit performance 2003 operating expense reductions resulted primarily impact western energy settlement reached 2003 epng party settlement recorded charge 2002 operating expenses 412 million share expected settlement amounts charge represented value el paso stock cash epng would pay settling parties second quarter 2003 settlement finalized epng recorded additional net pretax charge 127 million also 2003 accretion expense miscellaneous charges 13 million recorded included operating expenses year difference recorded charges western energy settlement resulted positive operating expense impact 272 million 143 million increase income resulted primarily impairment charges 2002 related equity investment epic energy australia trust epic 2002 recorded impairments australian investment 153 million due unfavorable regulatory environment increased competition operational complexities australia second quarter 2004 substantially exited investments australian operations partially offsetting impairment charges lower equity earnings 20 million investment alliance pipeline sold first quarter 2003 ebit also favorably impacted reapplication statement financial accounting standards sfas 71 accounting effects certain types regulation cig wic systems resulting 18 million onetime increase income resulted recording regulatory assets systems sfas 71 allows company capitalize items considered future rate proceedings income resulted capitalization items believe considered cigs wics future rate cases time cig wic reapplied sfas 71 adopted ferc depreciation rate regulated plant equipment change result depreciation expense increases future approximately 9 million annually based estimates anticipate overall annual ebit impact result reapplication sfas 71 annual reduction ebit approximately 10 million 37 million increase revenues result number revenue items significant discussed 2003 experienced higher revenues 57 million due higher volumes prices natural gas retained regulated systems excess amounts used pipeline operations addition completed system expansions new transportation contracts increased revenues 41 million considering operating expense impact expansions increased ebit 37 million offsetting revenue increases impact expiring capacity contracts epng prohibited remarketing due ferc orders capacity epng required make available former full requirements fr customers related line 2000 powerup project impact orders decrease revenues 35 million completion phases ii line 2000 powerup project february april 2004 epngs requirement dedicate capacity fr customers terminated also contributing lower revenues cigs sale panhandle field production properties july 2002 reduced revenues 50 million considering related operating expense reductions resulted ebit decline 29 million year ended december 31 2002 compared year ended december 31 2001 ebit 2002 decreased 216 million 2001 decrease primarily resulted 153 million impairment charge recorded income investment australia 99 million increase 2002 operating expenses operating expenses included 412 million charge 2002 associated western energy settlement 313 million merger related asset impairment charges 2001 related merger coastal also impacting ebit decrease 49 million lower revenues capacity sold shortterm contracts lower throughput reduced electric demand milder weather market areas 59 million decrease revenues lower natural gas prices impacts income recognize natural gas recovered tariffs excess amounts used pipeline operations 49 million reduction revenues 27 million decrease ebit result cigs sale panhandle field july 2002 partially offsetting ebit reductions 27 million lower general administrative operating costs result cost efficiencies achieved following coastal merger 49 million operating cost reductions due lower electrical prices natural gas imbalance pricing changes lower allocated overhead environmental legal costs offsetting ebit reductions favorable impact system expansions completed 2001 2002 well full year operations elba island lng facility increased revenues 83 million operating expenses 33 million ebit 50 million unregulated businesses production segment production segment results restated revisions natural gas oil reserve estimates accounting many historical hedges primarily associated hedges anticipated natural gas production segment conducts natural gas oil exploration production activities operating results driven variety factors including ability locate develop economic natural gas oil reserves extract reserves minimal production costs sell products attractive prices consistent longrange plan announced december 2003 longterm strategy includes developing production opportunities primarily us brazil prudently divesting production properties outside regions september 2004 sold production operations canada substantially operations indonesia operations canada included activities nova scotia first quarter 2004 drilled exploratory well commercially viable recorded 24 million ceiling test charge also 2004 acquired remaining 50 percent interest investment unopaso increase production operations brazil june 2004 announced backtobasics plan production business plan emphasizes strict capital discipline designed improve capital efficiency use standardized risk analysis heightened focus cost control revised controls booking proved natural gas oil reserves backtobasics approach expected stabilize production improving production mix across operating areas generate predictable returns reserves costs february 2004 completed estimates proved natural gas oil reserves december 31 2003 estimates prepared internally us ryder scott company huddleston co inc independent petroleum engineering firms performed independent reserve estimates proved reserves 90 percent 10 percent properties total estimate proved reserves prepared engineers within five percent internally prepared estimates proved reserve estimate december 31 2003 indicated 18 tcfe downward revision proved natural gas oil reserves needed downward revisions related primarily coal seam texas onshore offshore gulf mexico regions due significance reserve revision audit committee board directors engaged law firm conduct independent investigation reasons revisions investigation concluded material portion revisions related prior periods result restated historical reserve estimates historical financial information derived estimates reserve restatement involved utilizing reserve estimate prepared december 31 2003 reconstructing historical reserve data using actual historical production data reengineered sales proved reserves following reserve reconstruction recalculation discounted future net cash flows ceiling test calculations depletion rates gains losses asset sales recomputed period restated see item 8 financial statements supplementary data notes 1 9 30 discussion ceiling test calculation restatement natural gas oil reserves restatement result lower depletion rate reduced exposure ceiling test charges future would case absent restatement since december 31 2001 sold approximately 13 tcfe proved reserves multiple sales transactions various third parties sale reserves combined normal production declines mechanical failures certain producing wells disappointing drilling results resulted total equivalent production levels declining quarter since first quarter 2002 2003 total equivalent production declined approximately 165 bcfe 28 percent compared 2002 addition since depletion rate determined full cost method accounting expect higher depletion rate result higher finding development costs experienced year coupled significantly lower reserve base taking consideration restatement natural gas oil reserves prior periods impacts restatement production hedges discussed unit production depletion rate approximately 158 per mcfe 164 per mcfe first second quarters 2004 expect rate approximately 174 per mcfe third quarter 2004 see item 8 financial statements supplementary data note 30 discussion natural gas oil reserves first eight months 2004 daily production averaged approximately 855 mmcfed however month august 2004 daily production averaged approximately 810 mmcfed future trends production depreciation depletion amortization rates dependent upon amount capital allocated production segment level success drilling programs future sales activities relating proved reserves production hedging historically hedged portion anticipated natural gas production entering affiliated hedge transactions merchant energy segment would enter identical transactions third parties complete hedge august 2004 determined properly applied accounting rules related many historical hedges anticipated natural gas production specifically determined many hedges put place merchant energy qualify hedges consolidated reporting purposes many cases merchant energy entered offsetting trading transaction consequently restated accounting hedges reflected transactions hedges segment results information presented primarily conduct hedging activities natural gas oil derivatives natural gas oil production stabilize cash flows reduce risk downward commodity price movements sales hedging strategy partially reduces exposure downward movements commodity prices reported results operations financial position cash flows impacted significantly movements commodity prices period 2003 add additional hedges future production hedging positions anticipated natural gas production december 31 2003 may 2004 entered following additional hedges future natural gas production august 2004 entered following hedges future oil production brazil operating results operating results analysis results production segment three years ended december 31 1 amounts restated include operating revenues depreciation depletion amortization ceiling test charges well related subtotals totals additionally average realized prices including hedges unit production depletion costs restated 2 production costs include lease operating costs production related taxes including ad valorem severance taxes 3 includes ceiling test charges restructuring mergerrelated costs asset impairments gain loss longlived assets changes accounting estimates 4 transportation costs included operating expenses consolidated statements income 5 prices stated transportation costs year ended december 31 2003 compared year ended december 31 2002 year ended december 31 2003 ebit 259 million higher 2002 increase primarily due higher revenues resulting higher realized natural gas prices partially offset lower production volumes result asset sales normal production declines disappointing drilling results operating revenues following table describes variance revenue 2003 2002 due changes average realized market prices excluding hedges ii changes production volumes iii effects hedges revenues 2003 operating revenues increased 226 million compared 2002 primarily due higher market prices natural gas oil offset lower production volumes unfavorable impact hedging program decline natural gas volumes due sale properties new mexico oklahoma texas utah offshore gulf mexico western canada normal production declines mechanical failures several producing wells disappointing drilling results production declines mechanical failures primarily texas onshore offshore gulf mexico regions 2003 oil condensate liquids volume declines also primarily due asset sales production declines mechanical failures certain producing wells offshore gulf mexico region average realized natural gas prices 2003 excluding hedges 232 per mcf higher 2002 increase 73 percent however partially offsetting revenue increase 36 million hedging losses 2003 compared 83 million hedging gains 2002 relating natural gas hedge positions hedging losses gains represent difference hedge price market price time hedge positions settled expect continue incur hedge losses 2004 based current market prices natural gas relative prices natural gas production hedged operating expenses total operating expenses 3 million lower 2003 compared 2002 primarily due lower depreciation depletion amortization expenses result asset sales lower production costs offset higher ceiling test charges general administrative costs total depreciation depletion amortization expense decreased 16 million 2003 compared 2002 primarily due lower production volumes partially offset higher unit production depletion rates lower production volumes 2003 due asset sales normal production declines mechanical failures discussed reduced depreciation depletion amortization expenses 168 million partially offsetting lower production volumes higher depletion rates contributed increase 130 million depreciation depletion amortization expense higher depletion rate due higher finding development costs 2003 result disappointing drilling results lower reserve base due asset sales also offsetting overall decrease 2003 23 million incurred 2003 accretion liability asset retirement obligations production costs decreased 65 million 2003 compared 2002 due asset sales discussed however production cost per equivalent unit 2003 increased 10 percent 005 per mcfe primarily result higher production taxes 2003 due higher natural gas oil prices higher tax credits taken 2002 high cost natural gas wells ceiling test charges increased 45 million 2003 compared 2002 2003 incurred 76 million noncash full cost ceiling test charges canadian full cost pool international properties primarily brazil australia 75 million impairment goodwill associated canadian operations also 2003 recorded 18 million asset impairments net gains nonfull cost pool asset sales 6 million restructuring costs 2002 recorded noncash full cost ceiling test charges 128 million related canadian full cost pool international properties primarily brazil indonesia turkey australia general administrative expenses 35 million higher 2002 increase 017 per mcfe increase primarily due higher corporate overhead allocations lower capitalized costs also contributing per unit increase lower production volumes due asset sales discussed total general administrative expenses decreased primarily due staff reductions first quarter 2004 additionally el paso announced plans reduce corporate expenses part longrange plan expected reduce corporate overhead allocations year ended december 31 2002 compared year ended december 31 2001 year ended december 31 2002 ebit 18 billion higher 2001 increase primarily due lower operating expenses 2002 lower ceiling test charges partially offset impacts lower natural gas prices lower natural gas volumes due asset sales operating revenues following table describes variance revenue 2002 2001 due changes average realized market prices excluding hedges ii changes production volumes iii effects hedges revenues 2002 operating revenues decreased 483 million compared 2001 primarily due lower natural gas prices lower production volumes decline natural gas volumes primarily due sale properties colorado utah texas average realized natural gas prices 2002 excluding hedges 107 per mcf lower 2001 decrease 25 percent partially offsetting reductions 83 million hedging gains 2002 versus 247 million hedging losses 2001 relating natural gas hedge positions hedge losses gains represent difference hedge price market price time hedge positions settled operating expenses total operating expenses 23 billion lower 2002 compared 2001 primarily due lower noncash full cost ceiling test charges depreciation depletion amortization expense ceiling test charges year ended december 31 2002 21 billion lower 2001 2002 incurred 128 million noncash full cost ceiling test charges canadian full cost pool international properties primarily brazil indonesia turkey australia compared charges 21 billion 2001 domestic international properties primarily canada brazil indonesia turkey addition 2001 incurred mergerrelated costs 73 million related combining production operations following coastal merger total depreciation depletion amortization expense decreased 2002 175 million compared 2001 primarily due lower production volumes result asset sales lower unit production depletion rates lower production volumes 2002 reduced depreciation depletion amortization expense 71 million lower depletion rates contributed decrease 106 million production costs decreased 32 million 2002 compared 2001 primarily due lower production volumes result asset sales mentioned however production costs per equivalent unit relatively flat 2002 compared 2001 decrease 43 percent 006 per mcfe production taxes largely offset increase lease operating costs 005 per mcfe due higher labor workover expenses lower production taxes primarily due lower natural gas oil prices tax credits taken 2002 related high cost natural gas wells general administrative expenses increased 32 million 2001 increase 006 per mcfe primarily due higher corporate overhead allocations lower production volumes unregulated businesses field services segment field services segment conducts midstream activities include gathering processing natural gas majority 2003 assets principally consisted general limited partner holdings gulfterra publicly traded master limited partnership subsidiary serves general partner consolidated processing assets south texas south louisiana discussion ownership interests gulfterra activities partnership see item 8 financial statements supplementary data note 28 prior 2003 field services segment owned gathering processing fractionation assets investment gulfterra recognize earnings receive cash gulfterra several ways including share partnerships cash distributions ownership limited preferred general partner interests 2003 primary source earnings field services segment equity investment gulfterra sale effective 50 percent interest gulfterras general partner december 2003 well expected completion sale 2004 remaining interest general partner gulfterra upon receive cash 99 percent interest general partner gulfterra enterprise result lower equity earnings 2004 also receive management fees agreement provide operational administrative services partnership management fees increased result gulfterras asset acquisitions 2002 2003 terminate time merger gulfterra enterprise addition reimbursed costs paid directly us partnerships behalf years ended december 31 2003 2002 2001 reimbursed approximately 91 million 60 million 33 million expenses incurred behalf partnership 2003 equity investment earnings cash distributions received gulfterra follows addition equity investment earnings realized income losses fourth quarter 2003 related investment gulfterra follows realized loss 11 million redemption gulfterra series b units total proceeds 156 million realized gain 8 million related sale gulfterra common units net realized gain 269 million related sale effective 50 percent interest general partner enterprise net proceeds 421 million discussed sale onehalf general partner interest enterprise first step series transactions gulfterra merge enterprise form one largest energy master limited partnerships us merger related transactions discussed fully item 8 financial statements supplementary data note 28 subject customary approvals expected completed third quarter 2004 2001 2003 entered number asset sales transactions gulfterra 2003 exchanged communications assets release obligation repurchase chaco cryogenic natural gas processing plant 2021 recognized net gain transaction 67 million 2002 sold assets gulfterra total proceeds 15 billion including gathering processing transmission assets substantially assets san juan basin total net gains recognized assets sold 2002 approximately 210 million 2001 sold assets gulfterra total proceeds 255 million including processing ngl transportation fractionation assets well investment deepwater holdings entity owned several pipeline gathering systems gulf mexico majority assets acquired us one year earlier purchase transaction accordingly recorded fair value result sales resulted gains losses conjunction 2002 sales agreed reimburse gulfterra portion future pipeline integrity costs related assets 2006 time sales unable estimate liability associated obligation gulfterra early stages pipeline integrity programs december 2003 amended agreement clarify types amounts reimbursable costs also began reviewing gulfterras pipeline integrity results review continued 2004 based results experience date related pipeline integrity projects determined obligation probable could estimated result recognized 74 million loss agreement 2003 asset sales addition sales gulfterra discussed 2003 sold gathering systems located wyoming western gas resources inc also sold midstream assets midcontinent north louisiana regions regency gas services llc investment charlesbank capital partners llc midcontinent assets primarily included greenwood hugoton keyes mocane natural gas gathering systems sturgis mocane lakin processing plants processing arrangements three additional processing plants north louisiana assets primarily included dubach processing plant gulf states interstate natural gas transmission system gathering processing operations end 2003 remaining gathering processing assets consisted primarily south texas gathering processing assets south louisiana processing assets south texas processing plants sold enterprise 2004 part merger enterprise gulfterra point gathering processing business conducted ownership interests merged partnership attempt balance earnings gathering processing business combination fixed feebased marketbased services majority gathering operations earn margins fixed feebased services however operations earn margins marketbased rates revenues marketbased rate services product market price usually related monthly natural gas price index volume gathered processing operations earn margin based fixedfee contracts percentageofproceeds contracts makewhole contracts percentageofproceeds contracts allow us retain percentage product fee service provided makewhole contracts allow us retain extracted liquid products return producer btu equivalent amount natural gas percentageofproceeds contracts makewhole contracts may sensitivity price changes periods natural gas ngl prices volatile operating results analysis results field services segment three years ended december 31 1 gross margins consist operating revenues less cost products sold believe measurement meaningful understanding analyzing field services operating results commodity costs play significant role determination profit midstream activities year ended december 31 2003 compared year ended december 31 2002 year ended december 31 2003 ebit 156 million lower 2002 asset sales 2003 2002 contributed year decrease ebit 119 million also 191 million additional impairments 2003 compared 2002 throughout 2003 natural gas prices higher relative ngl prices reduced ebit processing plants 11 million partially offsetting declines 71 million year net gains realized sale assets 2003 2002 well higher equity earnings 83 million investment gulfterra decrease gathering processing gross margins primarily combined result asset sales impact higher natural gas prices relative ngl prices asset sales decreased 2003 gathering margins 154 million 2003 processing margins 46 million processing gathering assets experienced higher natural gas prices 2003 reduced margin per unit plants also minimized amount ngls extracted resulting lower realized margins ebit 2003 11 million higher operating expenses 2003 result 74 million loss related pipeline integrity agreement gulfterra 2003 impairments south texas gathering processing assets based planned sale assets enterprise along impairment altonah processing facility totaled 171 million 2003 compared 66 million impairments 2002 north louisiana facilities resulting decision sell facilities also realized net gains sales assets 74 million 2003 compared 245 million 2002 increase impairments 2003 higher realized gains 2002 resulted year increase operating expenses 276 million partially offsetting increases higher reimbursements gulfterra 17 million administrative services lower operating expenses 81 million related asset sales 310 million increase income primarily due 269 million net gain sale effective 50 percent interest general partner gulfterra enterprise well increase earnings investment partnership 83 million 2003 also contributing year increase loss 2002 investment aux sable ngl plant black forks natural gas processing plant 50 million gain 8 million sale portion interest gulfterras common units 2003 partially offsetting increases impairments 2003 investments dauphin island gathering partners mobile bay processing partners 86 million 11 million loss redemption series b units gulfterra year ended december 31 2002 compared year ended december 31 2001 year ended december 31 2002 ebit 93 million higher 2001 2002 lower margins 134 million sales midstream assets gulfterra along decrease processing margins 58 million due lower ngl prices offset lower 2002 operating costs 361 million operating expenses recognized net gain 2002 sales san juan basin assets natural buttes ouray systems dragon trail processing plant 245 million also experienced lower operating costs 2002 result asset sales 83 million favorable impact operating expenses 2001 merger charges 46 million incurred related el pasos merger coastal see item 8 financial statements supplementary data note 5 discussion merger charges partially offsetting lower operating costs 2002 impairment charges 66 million north louisiana facilities 2002 equity earnings investments 54 million lower 2001 decrease primarily due 50 million losses 2002 sales investments aux sable ngl plant black forks natural gas processing plant unregulated businesses merchant energy segment merchant energy segment consists global power division energy marketing trading division lng division historically also petroleum markets division 2003 board directors approved sale petroleum markets operations result reclassified division discontinued operations periods presented energy marketing trading division merchant energy segment historically entered transactions third parties accomplish hedges production segment subsidiary pipelines segment behalf capacity held natural gas pipelines division also conducted nonhedging transactions behalf august 2004 determined properly applied accounting related many historical hedges primarily associated hedges anticipated natural gas production result required restate historical financial information revise accounting included restatement historical financial statements energy marketing trading division discussion restatement see item 8 financial statements supplementary data note 1 restated operating results analysis results merchant energy segment three years ended december 31 millions 1 gross margin global power division consists revenues power plants initial net gains losses incurred connection restructuring power contracts well subsequent revenues cost electricity purchases changes fair value contracts cost fuel used power generation process included operating expenses gross margin energy marketing trading division consists revenues commodity trading origination activities less costs commodities sold including changes fair value derivative contracts global power division global power division three primary business activities domestic power plant operations domestic power contract restructuring activities international power plant operations since december 31 2003 sold substantial portion domestic power plant operations domestic power contract restructuring activities proceeds approximately 537 million assumption buyer approximately 926 million debt activity discussed operating results activities within global power division three years ended december 31 evaluated operating results using ebit due several significant consolidations transactions affect yeartoyear comparability operations include equity consolidated investments 1 consists indirect expenses general administrative costs associated domestic international operations including legal finance engineering costs effects financial services business power turbine inventory operations direct general administrative expenses domestic international operations included ebit operations domestic power plant operations overview domestic operations relate ownership operation power plant assets us two types domestic plants contracted power operations merchant power operations contracted power operations include power plants dedicated power contracts customers generally electric utilities generation sale power since longterm sales contracts longterm fuel contracts operations generally contain fixed prices operating results business fairly stable however contracted operations derivative fuel supply contracts recorded fair value subject changes fair value generally driven changing prices fuels used fire plants primarily natural gas operating results plants may vary period merchant power operations include plants operate peak periods without dedicated power contracts generally plants operate demand power market price power exceeds plants variable costs generating power many merchant plants contractual obligations transportation capacity contracts represent fixed costs plant ability recover fixed operating costs depends largely electricity demand volume power generated well margins realized historically conducted significant portion domestic power operations chaparral unconsolidated joint venture 2003 acquired remaining joint venture partners interest chaparral consolidated operations effective january 1 2003 result 2003 operating results include consolidated revenues expenses equity earnings chaparrals power plants 2001 2002 operating results include equity earnings management fees earned chaparral ebit analysis 2003 ebit loss domestic power plant operations 383 million primarily due 419 million asset impairments domestic power plants chaparral investment plant impairments resulted anticipated sale domestic power plants 2004 well operational contractual issues several domestic plants impairment chaparral result declines investments value considered temporary see item 8 financial statements supplementary data notes 2 3 information impairments 2004 may record additional impairments power plants result ongoing negotiations related sales domestic power plants ongoing operational contractual issue one domestic plants see note 28 discussion matter 2003 also recorded 88 million loss primarily due writeoff receivables result transfer interest milford power facility plants lenders see item 8 financial statements supplementary data note 28 description milford transfer also contributing losses 21 million operating loss eagle point power plant partially offsetting losses 105 million operating income generated power plants chaparral consolidated january 2003 december 2003 board directors approved sale substantially domestic power plant operations expect complete 2004 majority plants sold 2003 2004 expect sell 2004 contracted plants generated ebit realized gains losses impairments 2003 160 million comparison merchant plants sold expect sell 2004 generated ebit losses also realized gains losses impairments 2003 47 million 2004 operating results impacted timing nature plants sold year ended december 31 2002 domestic power plant operations generated ebit 80 million ebit primarily generated equity earnings management fees received chaparral 124 million 2002 described chaparral consolidated 2003 also contributing ebit 20 million operating income generated eagle point plant restructuring power sales contract march 2002 see power restructuring discussion following restructuring eagle point plants operating income decreased partially offsetting increases 74 million impairment ce generation power plant 2002 resulted anticipated sale plant early 2003 plant generated operating income 22 million 2002 year ended december 31 2001 domestic power plant operations generated ebit 317 million ebit primarily generated equity earnings management fees received chaparral 222 million 2001 also contributing 2001 ebit 22 million operating income earned eagle point power plant 2001 restructuring power sales contract 2002 ce generation power plant sold early 2003 also generated operating income 29 million 2001 domestic power contract restructuring business overview 2001 2002 chaparral restructured several abovemarket longterm power sales contracts regulated utilities originally tied older power plants built purpa contracts amended power sold utilities required delivered specified power generation plant could obtained wholesale power market discussion power restructuring activities see item 8 financial statements supplementary data note 15 result credit rating downgrades economic changes power market longer pursuing additional power contract restructuring activities 2003 power restructuring business related solely management existing restructured power contracts 2001 2002 results included impact power contract restructuring transactions completed years addition results managing contracts ongoing basis results power restructuring business consist physical sales purchases electricity changes fair value derivative contracts changes discount rate used calculate fair value power restructuring derivatives based part credit ratings counterparties significantly impact earnings see item 7a quantitative qualitative disclosures market risk discussion discount rate risk domestic restructured power contracts currently face number risks may impact operating results future actively divesting entities hold domestic restructured power contracts entities hold power supply power purchase agreements debt power agreements derivatives carried fair value debt recorded based original issuance cost proceeds received past sale transactions may receive future transactions generally differs net assets entities resulting losses reasons differences include use different assumptions buyer determining fair value instruments experienced sold utility contract funding ucf loss approximately 100 million 2004 mohawk river funding iv loss approximately 15 million 2003 based pending sale cedar brakes ii approved board directors could incur significant additional losses future restructured power contracts fair value 15 billion single counterparty public service electric gas pseg currently rated investment grade moodys investors services standard poors changes creditworthiness pseg could materially impact fair value contracts results operations risk reduced june 2004 sold ucf bear stearns also restructured power contract held mohawk river funding iii us gen new england us gen filed bankruptcy 2003 increases decreases amount recoverable bankruptcy claims may significantly impact future operating results ebit analysis year ended december 31 2003 domestic power contract restructuring business generated ebit 150 million restructured power contracts acquired chaparral 2003 increased fair value 75 million ucf restructured power contracts increased fair value 65 million increases resulted primarily accretion discounted value contracts partially offsetting ebit 15 million losses impairments related sale two power contract restructuring entities mohawk river funding iv year ended december 31 2002 domestic power contract restructuring business generated ebit 341 million 2002 restructured power sales contracts eagle point also known ucf mount carmel power plants resulted net gains 501 million net minority interest partially offsetting gains 90 million contract termination fee paid 2002 terminate steam contract eagle point power plant eagle point refinery included discontinued operations also offsetting gains 80 million loss power supply agreement entered energy marketing trading division 2002 associated eagle point power contract restructuring transaction 90 million 80 million losses eliminated el pasos consolidated results year ended december 31 2001 domestic power contract restructuring business generated ebit 31 million 2001 restructured power sales contract cdecca power plant also known mohawk river funding iv resulted net gain 31 million international power plant operations overview international operations primarily include contracted plants pipelines located south america central america asia europe november 2001 april 2003 conducted majority power plant operations brazil gemstone unconsolidated joint venture second quarter 2003 acquired joint venture partners interest gemstone began consolidating gemstones debt investments macae porto velho araucaria power plants result consolidated operating results beginning april 2003 include revenues expenses equity earnings gemstones assets 2001 2002 operating results include equity earnings earned gemstone due deteriorating economic conditions several south american central american asian countries recorded impairments international power plants 2001 2002 discussion impairments see item 8 financial statements supplementary data note 28 part longrange plan announced intent dispose majority international power operations next several years exception brazilian power operations future operating results global power division impacted timing sales ebit analysisbrazil year ended december 31 2003 brazilian power operations generated ebit 177 million ebit primarily generated operating income 156 million macae power plant operated full operational capacity throughout 2003 macae power plants power sales contract expires 2007 time plant convert merchant plant enter new bilateral power contracts also contributing ebit 28 million earnings interest porto velho power plant reached full commercial operations third quarter 2003 year ended december 31 2002 brazilian power operations generated ebit 78 million ebit primarily generated equity earnings 109 million gemstone created november 2001 described consolidated gemstone interests macae porto velho power plants 2003 operations two power plants primary contributors gemstones equity earnings partially offsetting earnings 19 million fee paid related cancellation turbine purchase order year ended december 31 2001 brazilian power operations generated ebit 114 million ebit primarily generated 75 million fees earned engineering construction management services macae power project gemstone acquired macae also contributing ebit 23 million operating income rio negro power plant 2002 2003 rio negros power purchaser disputed pay billings significantly decreased power plants operating income years power purchase agreements manaus rio negro plants expire 2005 2006 based anticipated results negotiations renewal contracts recorded 135 million impairment charge first quarter 2004 see item 8 financial statements supplementary data note 22 description matters ebit analysisother international year ended december 31 2003 international power operations generated ebit 119 million ebit primarily generated operating income 49 million 15 asian power plants also contributing ebit 28 million gain sale two argentinean power plants remaining ebit primarily generated central american european power plants year ended december 31 2002 ebit loss international power plant operations 246 million loss primarily due 342 million impairment argentinean power plants 48 million impairment chinese indian power plants due deteriorating economic conditions countries partially offsetting losses 77 million net gain recorded restructuring termination power contract nejapa power plant el salvador also offsetting losses operating income 46 million asian power plants year ended december 31 2001 international power operations generated ebit 9 million ebit primarily generated operating income 52 million asian power plants 21 million operating income earned nejapa power plant restructuring power sales contract also contributing ebit operating income 12 million samalayuca power plant mexico sold 2002 partially offsetting income 74 million impairment east asia fife power plants 2001 due deteriorating economic conditions countries power plants located global power operations year ended december 31 2003 ebit loss global power operations 70 million loss primarily due 22 million settlement charge 2003 associated cancellation purchase obligations two power turbines 11 million impairment capitalized turbine costs remaining ebit loss primarily due general administrative costs global power division remained relatively consistent 2002 2003 expect costs decrease 2004 sell domestic power assets partially offset increased severance due asset sales year ended december 31 2002 ebit loss global power operations 259 million loss primarily due 162 million impairment capitalized domestic international turbine costs 44 million goodwill impairment charge financial services business recorded 2002 due reduced capital expenditure plans related future power financial services investments remaining ebit loss primarily due general administrative costs global power division year ended december 31 2001 ebit loss global power operations 10 million loss primarily due general administrative costs global power division energy marketing trading division energy marketing trading divisions operations primarily center around management trading portfolio marketing natural gas oil production mentioned previously information related division restated correct manner accounted many hedges anticipated natural gas production certain derivative transactions result deterioration energy trading environment late 2001 2002 announced november 2002 would reduce involvement energy marketing trading business pursue orderly liquidation trading portfolio part longrange plan announced historical energy trading operations would become marketing trading business focused principally physical marketing natural gas oil produced production segment time anticipate early liquidation transactions trading portfolio end contract term may retain contracts either uneconomical sell terminate current environment due contractual terms credit concerns counterparty ii sale would require acceleration cash demands iii represent hedges associated activities reflected segments business including production segment global power division changes liquidation strategy may impact cash flows financial results division trading portfolio contains derivative nonderivative contracts derivative contracts primarily impact gross margin changes fair value period fair value derivative contracts fluctuates monthly variety market factors impact commodity prices difficult estimate predict discussion methodology determining fair value derivative contracts see item 8 financial statements supplementary data note 15 nonderivative contracts primarily relate obligations longterm pipeline transportation natural gas storage contracts 2003 demand charges contracts 177 million transportation contracts impact gross margin delivery service contract occurs income loss based difference demand charge locational price difference delivery points contract 2003 trading business operated challenging environment reduced liquidity lower credit standing participants general decline number trading counterparties additionally fourth quarter 2002 implemented new accounting rules emerging issues task force eitf issue 023 issues related accounting contracts involved energy trading risk management activities significantly impacted carrying value portfolio many contracts accounted derivative contracts 2002 accounted nonderivative contracts factors reduce comparability operating results periods operating results analysis results energy marketing trading division three years ended december 31 year ended december 31 2003 year ended december 31 2003 ebit loss 809 million 2003 experienced 424 million decrease fair value derivatives primarily natural gas contracts sell natural gas fixed price many contracts significant increase natural gas prices 2003 difference fixed prices contracts market prices continued increase result fair value derivatives decreased resulting losses also contributing loss 47 million gross margin losses early termination derivative nonderivative contracts resulted ongoing liquidation trading portfolio 2003 also recorded 32 million net reduction carrying value bankruptcy claims three trading counterparties nrg power marketing mirant corporation enron corporation included gross margin nonderivative contracts settlement losses 165 million 2003 primarily due demand charges could recover transportation contracts 2003 price differentials contractual delivery points wide enough recover demand charges contracts partially offsetting losses 30 million gross margin gain sale several lng contracts 78 million increase fair value midwest derivative tolling agreement tolling contract sensitive changes forecasted power prices relative natural gas prices midwest forecasted power prices increased significantly relative natural gas prices end 2003 increased fair value contract 52 million fourth quarter 2003 expect fair value contract volatile entire contract term extends 2019 2003 also recorded 26 million accretion expense net adjustments portion western energy settlement 28 million bad debt expense associated fuel supply agreement berkshire power plant operating expenses see item 8 financial statements supplementary data note 28 discussion berkshire remaining 2003 operating expenses 129 million included general administrative expenses decreased 2002 2003 due decreases employee headcount 2003 anticipate costs continue decline result previous future employee headcount cost reductions division 2004 year ended december 31 2002 year ended december 31 2002 ebit loss approximately 2 billion loss primarily result 12 billion decrease fair value derivative positions included gross margin 2002 experienced general market declines energy trading resulting lower price volatility natural gas power markets generally weaker trading credit environment 2002 additionally fourth quarter 2002 many participants trading industry including us publicly announced intention discontinue significantly reduce trading operations believe along factors caused deterioration market valuations trading marketing assets decrease fair value derivatives primarily related reduced option value remainder decrease resulting volatility forward prices reductions creditworthiness counterparties additionally issues significantly reduced origination activities 2002 compared 2001 also contributing loss decrease gross margin 25 million resulted early termination several nonderivative transportation contracts resulted ongoing liquidation trading portfolio 2002 partially offsetting losses 59 million gain recorded second quarter 2002 longterm lng supply contract snohvit subsequently sold fourth quarter 2002 also contributing loss 487 million charge related western energy settlement included operating expenses remaining 2002 operating expenses 190 million include general administrative expenses increased 2001 2002 due expansion trading operations 2002 decision liquidate trading portfolio late 2002 year ended december 31 2001 year ended december 31 2001 ebit approximately 17 billion ebit primarily due 16 billion increase fair value derivatives 2001 increases trading volumes price volatility trading portfolio net reserves established bankruptcy enron 2001 addition sell natural gas fixed price many natural gas derivative contracts significant decrease natural gas prices 2001 difference fixed prices contracts market prices continued improve result fair value derivatives increased resulting marktomarket gains also originated several power natural gas transportation contracts 2001 generated gross margin 211 million partially offsetting ebit 2001 operating expenses 137 million operating expenses include general administrative expenses steadily increased decision liquidate trading portfolio late 2002 lng division 2001 2002 lng division included development lng terminals energy bridge technology holding longterm charter arrangements ships employed technology 2003 announced intent exit business significant capital credit requirements associated business either sold process selling lng operations results lng division follows three years ended december 31 year ended december 31 2003 reported ebit loss 185 million year ended december 31 2003 loss primarily resulted 119 million loss sale assets intellectual property rights related energy bridge technology well termination obligations longterm ship charters related technology also contributing loss 33 million asset impairments capitalized terminal development testing facility costs realized unrealized losses included part operating expenses years ended december 31 2002 2001 reported ebit loss 35 million 25 million years ended december 31 2002 2001 related primarily operating expenses operating expenses related environmental engineering costs incurred related development terminals testing regasification process used energy bridge technology corporate expenses net corporate operations include general administrative functions well operations telecommunications miscellaneous businesses 2001 significant downturn telecommunications market result refocused telecommunications strategy reduced capital investment business currently provide wholesale metropolitan transport services texas collocation services facility chicago april 2004 sold 28 percent interest texas metro transport business genesis park lp third party investment partnership changed name alpheus communications december 2002 decided exit longhaul metro dark fiber business minimal contribution high cost maintaining business circumstances reduced carrying value inventory 5 million recording impairment 153 million market value determined independent appraiser evaluated dark fiber value based market conditions existing fourth quarter 2002 recent liquidation values dark fiber addition continuing decline economic conditions telecommunications industry periodically evaluated fair value texasbased assets 2003 recognized 163 million goodwill impairment based evaluations amounts would recover business collocation crossconnect services available lakeside technology center chicagobased telecommunications facility building design beneficial needs telecommunications provider limited alternative uses due ongoing decline industry loss significant tenant building 2002 recorded contingent loss totaling 113 million 11 million recognized immediately remaining 102 million recorded quarterly charge end lease 2006 2003 upon consolidation lessor provided full guarantee repayment recognized additional impairment 127 million may 2004 announced would consolidate houstonbased operations one location anticipate consolidation substantially complete end 2004 result established establish accrual record liability obligations terms leases period space vacated available subleasing currently lease approximately 912000 square feet office space buildings vacating various leases lease terms expiring 2004 2014 estimate total accrual relocation approximately 80 million 100 million expenses related relocation expensed period incurred year ended december 31 2003 compared year ended december 31 2002 corporate net expenses year ended december 31 2003 368 million higher 2002 2003 recorded impairment charges 396 million including impairment goodwill 163 million telecommunications business losses recorded lakeside technology center discussed 2002 recorded 153 million valuation adjustments dark fiber inventory 15 million impairment rightofway assets telecommunications business 2003 also incurred 42 million employee severance costs 37 million loss compared 21 million gain 2002 early debt extinguishments actions part continuing efforts reduce debt lower costs expect incur additional employee severance costs 2004 cost reduction efforts continue 2002 recorded 51 million restructuring related costs see item 8 financial statements supplementary data note 5 discussion charges finally recorded 112 million net foreign currency losses 2003 versus 90 million net losses 2002 primarily related eurodenominated debt year ended december 31 2002 compared year ended december 31 2001 corporate net expenses year ended december 31 2002 11 billion lower 2001 recorded 12 billion mergerrelated asset impairment charges related merger coastal also recognized additional 2001 costs 144 million related increased estimates environmental remediation costs legal obligations reductions fair value spare parts inventories reflect changes usability spare parts inventories based ongoing evaluation operating standards plans following coastal merger 2002 recorded 168 million valuation adjustment dark fiber inventory rightofway assets discussed 90 million net foreign currency losses various incremental costs related 2002 restructuring activities interest debt expense past three years interest debt expense increased period issued debt finance growth business segments consolidated several offbalance sheet financing obligations order simplify balance sheet period overall debt balances increased approximately 16 billion 2001 22 billion december 31 2003 growth period raised funds domestic international capital markets majority fixed rate debt future ability access capital markets issue debt securities function market conditions credit ratings time based number rating actions since latter part 2002 anticipate incur higher interest rates future debt issuances furthermore since debt offerings foreign markets currency fluctuations impact cost debt december 2003 announced longterm plan would reduce longterm debt continue repay debt obligations interest expense decline 2004 beyond discussion changes debt instruments see item 8 financial statements supplementary data note 20 analysis interest debt expense three years ended december 31 millions year ended december 31 2003 compared year ended december 31 2002 interest expense longterm debt year ended december 31 2003 475 million higher 2002 increase due higher average debt balances 2003 compared 2002 consolidated chaparral gemstone lakeside 2003 increased debt 21 billion december 31 2003 increased interest expense 236 million 2003 addition debt financing obligations increased another 10 billion 2003 associated debt issuances consolidations also consolidated approximately 15 billion debt early 2003 paid late 2003 two changes debt increased interest expense approximately 219 million 2003 also contributing increase 20 million due reclassification 625 million preferred securities result adoption sfas 150 additionally interest expense increased 2003 due debt issuances debt consolidations 2003 higher average interest rates debt retired period interest expense revolving credit facilities year ended december 31 2003 105 million higher 2002 due higher borrowings facilities 2003 average revolving credit balances based daily ending balances approximately 15 billion average interest rate 397 2003 interest expense commercial paper year ended december 31 2003 26 million lower 2002 due discontinuance commercial paper activities fourth quarter 2002 interest year ended december 31 2003 58 million lower 2002 decrease primarily due 23 million reduction interest expense retirement financing obligations 16 million reduction affiliated interest expense notes chaparral gemstone eliminated result consolidation investments second quarter 2003 19 million decrease due discontinuance factoring activities 2003 decreases partially offset 7 million increase result writeoff unamortized financing costs due retirement trinity river financing arrangement 2003 capitalized interest year ended december 31 2003 2 million higher 2002 primarily due higher average interest rates 2003 2002 year ended december 31 2002 compared year ended december 31 2001 interest expense longterm debt year ended december 31 2002 204 million higher 2001 increase due higher average debt balance 2002 issued longterm debt approximately 44 billion average interest rate 79 issuances increased interest longterm debt approximately 233 million year retired approximately 15 billion longterm debt average interest rate 519 resulting decrease interest expense retirements approximately 35 million remaining increase primarily due various debt issuances 2001 outstanding entire year 2002 interest expense revolving credit facilities year december 31 2002 12 million lower 2001 due lower borrowings facilities 2002 average revolving credit balances based daily ending balances approximately 144 million average interest rate 336 2002 interest expense commercial paper year ended december 31 2002 44 million lower 2001 primarily due lower average shortterm interest rates commercial paper activities 2002 interest year ended december 31 2002 15 million lower 2001 decrease primarily due 8 million decrease interest resulting retirement financing obligations 8 million decrease interest related decline receivable factoring 8 million decrease interest due termination marketing sales contract 2002 decreases partially offset 9 million increase interest debt securities issued gemstone november 2001 capitalized interest year ended december 31 2002 31 million lower 2001 primarily due lower interest rates 2002 2001 distributions preferred interests consolidated subsidiaries year ended december 31 2003 compared year ended december 31 2002 distributions preferred interests consolidated subsidiaries year ended december 31 2003 107 million lower 2002 due redemptions preferred stock two subsidiaries trinity river coastal securities consolidation gemstone preferred interest 300 million one subsidiaries refinancing redemption clydesdale financing arrangement reclassification capital trust coastal finance mandatorily redeemable preferred securities longterm financing obligations result adoption sfas 150 result reclassification began recording preferred returns securities interest expense rather distributions preferred interests result actions 2003 remaining preferred interests outstanding december 31 2003 consist 300 million preferred stock el paso tennessee pipeline co number smaller interests consolidated subsidiaries year ended december 31 2002 compared year ended december 31 2001 distributions preferred interests consolidated subsidiaries year ended december 31 2002 58 million lower 2001 primarily due redemptions preferred interests related el paso oil gas resources el paso oil gas associates coastal limited ventures capital trust iv partial redemption clydesdale financing arrangement decrease also due lower interest rates 2002 preferred returns based variable shortterm rates lower average 2002 2001 partially offsetting decreases higher returns preferred interests issued part gemstone investment completed november 2001 discussion borrowings financing activities related consolidated subsidiaries see item 8 financial statements supplementary data note 21 income taxes income tax benefits years ended december 31 2003 2002 2001 584 million 649 million 70 million resulting effective tax rates 49 percent 33 percent 15 percent 2003 amount 139 million related tax benefits recorded abandonments sales certain foreign investments effective tax rate 2003 absent benefits would 37 percent included 2001 tax benefit tax charge 115 million related nondeductible merger charges changes estimate additional tax liabilities taxes majority estimated additional liabilities paid 2001 effective tax rate 2001 absent charges would 40 percent differences effective tax rates statutory tax rate 35 percent years primarily result following factors state income taxes earnings unconsolidated affiliates anticipate receiving dividends nondeductible portion mergerrelated costs tax adjustments provide revised estimated liabilities foreign income taxed different rates abandonments sales foreign investments valuation allowances deferred credit loss carryovers nondeductible dividends preferred stock subsidiary nonconventional fuel tax credits goodwill impairment depreciation depletion amortization reconciliation statutory rate effective tax rate well matters could impact future tax expense see item 8 financial statements supplementary data note 11 included deferred tax assets excluding valuation allowances december 31 2003 400 million related western energy settlement proposed tax legislation introduced us senate would disallow deductions certain settlements made behalf governmental entities enacted tax legislation could impact deductibility expenses related western energy settlement could result writeoff associated deferred tax assets event tax expense would increase discussion valuation allowances based ability utilize state tax benefits deduction charge took related western energy settlement see item 8 financial statements supplementary data note 11 discontinued operations 2002 2003 made decision eliminate involvement several businesses sell related assets liabilities result reported following operations discontinued operations december 31 2003 2002 years ended december 31 2003 2002 2001 petroleum markets operations 2003 board directors authorized sale substantially petroleum markets operations based intent dispose operations adjusted assets estimated fair value recognized pretax charges 2003 totaling approximately 15 billion included 11 billion related aruba refinery 264 million related impairment eagle point refinery 2003 completed sales 664 million assets completed additional 905 million early 2004 completed sale substantially remaining petroleum markets assets 2004 coal mining operations late 2002 first quarter 2003 sold coal mining operations consisted fifteen active underground two surface mines located kentucky virginia west virginia following authorization sale board directors recorded impairment charges 185 million loss discontinued operations 2002 fully exited coal operations three years ended december 31 aftertax income loss related discontinued operations follows millions year ended december 31 2003 reported loss discontinued operations 13 billion primarily due impairments longlived assets 15 billion including 11 billion related aruba refinery 264 million related eagle point refinery addition aruba refinery continued generate operating losses approximately 82 million losses resulted lower throughput aruba due primarily operational difficulties following fire facility april 2001 scheduled turnaround maintenance activities losses partially offset operating income eagle point refinery approximately 42 million income resulted higher margins eagle point due widening difference price crude oil inputs used refinery prices sold refined products produced loss also partially offset 90 million gains recorded sale florida terminalling transportation assets asphalt facilities chemical facilities 2003 65 million business interruption property damage insurance recoveries related aruba facility fire 2001 year ended december 31 2002 reported loss discontinued operations 365 million primarily due operating losses approximately 129 million aruba refinery resulting operational difficulties following fire facility also contributing loss 185 million impairment coal mining operations 91 million impairment mtbe chemical processing plant losses partially offset operating income eagle point refinery approximately 97 million resulting higher throughput eagle point 2002 due widening difference price crude oil input used refinery prices sold products produced loss also partially offset 46 million insurance recoveries 2002 related assets destroyed aruba fire year ended december 31 2001 reported loss discontinued operations 85 million loss included 262 million mergerrelated costs asset impairments charges associated merger coastal 2001 see item 8 financial statements supplementary data notes 5 7 discussion mergerrelated costs asset impairments also contributing loss operating loss 87 million eagle point refinery result lower margins throughput partially offsetting losses 97 million insurance recoveries related fire aruba refinery operating income 126 million refined product crude oil marketing activities 23 million income includes equity earnings income lease corpus christi refinery valero commitments contingencies discussion commitments contingencies see item 8 financial statements supplementary data note 22 incorporated herein reference critical accounting policies critical accounting policies accounting policies involve use complicated processes assumptions andor judgments preparation financial statements discussed development selection critical accounting policies related disclosures audit committee board directors identified following critical accounting policies current year price risk management activities record derivative instruments used price risk management activities fair values balance sheet estimate fair value derivative instruments using exchange prices thirdparty pricing data valuation techniques incorporate specific contractual terms statistical simulation analysis present value concepts one primary assumptions used estimate fair value derivative instruments pricing assumptions based upon price curves derived actual prices observed market pricing information supplied thirdparty valuation specialist independent pricing sources models rely forward pricing information significant assumptions use determining fair value derivative instruments related time value anticipated market liquidity credit risk counterparties assumptions methodologies use determine fair values derivatives may differ used derivative counterparties differences significant could impact future operating results settle derivative positions accounting natural gas oil producing activities use full cost method account natural gas oil producing activities accounting method capitalize substantially costs incurred connection acquisition development exploration natural gas oil reserves full cost pools maintained geographic areas regardless whether reserves actually discovered process estimating natural gas oil reserves particularly proved undeveloped proved nonproducing reserves complex requiring significant judgment evaluation available geological geophysical engineering economic data december 31 2003 total proved reserves 34 percent undeveloped 12 percent developed nonproducing addition data given field may also change substantially time result numerous factors including additional development activity evolving production history continual reassessment viability production changing economic conditions result material revisions existing reserve estimates occur time although every reasonable effort made ensure reserve estimates reported represent accurate assessments possible subjective decisions variances available data various fields increases likelihood significant changes estimates factors held constant increase estimated proved reserves decreases unit production depletion rate higher reserves also reduce likelihood ceiling test impairments discussions reserves well restatement historical financial statements result downward revisions reserve estimates see part item 1 business production segment item 8 financial statements supplementary data notes 1 30 full cost accounting method required conduct quarterly impairment tests capitalized costs full cost pools impairment test referred ceiling test total capitalized costs net related income tax effects limited ceiling based present value future net revenues using end period spot prices discounted 10 percent plus lower cost fair market value unproved properties net related income tax effects discounted revenues equal greater total capitalized costs required writedown capitalized costs level ceiling test calculations include effects derivative instruments designated qualify cash flow hedges anticipated future natural gas oil production result determining properly applied accounting rules hedges natural gas production recorded additional ceiling test charges 2001 see discussion restatement manner historically accounted natural gas hedges item 8 financial statements supplementary data note 1 ceiling test calculation assumes price effect last day quarter held constant life reserves even though actual prices natural gas oil volatile change period attempt realize determinable cash flows use hedges decline commodity prices impact results ceiling test may result writedowns asset impairments asset impairment accounting rules require us continually monitor businesses business environment determine event occurred indicating longlived asset investment may impaired event occurs determination involves judgment assess expected future cash flows compare carrying value asset group evaluated process also involves judgment ultimately arrive fair value asset determined combination estimating proceeds sale asset less anticipated selling costs intend sell asset discounted estimated cash flows asset based current anticipated future market conditions intend hold asset assessment project level cash flows requires us make projections assumptions many years future pricing demand competition operating costs legal regulatory issues factors variables often differ estimates changes either positive negative impact impairment estimates recorded impairments longlived assets 880 million 444 million 75 million years ended december 31 2003 2002 2001 recorded impairments discontinued operations 15 billion 290 million 103 million years ended december 31 2003 2002 2001 future changes economic business environment impact original ongoing assessments potential impairments accounting environmental reserves accrue environmental reserves assessments indicate probable liability incurred asset recovered amount reasonably estimated estimates liabilities based currently available facts existing technology presently enacted laws regulations taking consideration likely effects societal economic factors include estimates associated onsite offsite groundwater technical studies legal costs actual results may differ estimates often revised future either negatively positively depending upon actual outcomes changes expectations based facts surrounding exposure december 31 2003 accrued approximately 412 million environmental matters reserve estimates range approximately 412 million approximately 632 million accrual represents combination two estimation methodologies first likely outcome reasonably estimated cost accrued 94 million second likely outcome cannot estimated range costs established 318 million 538 million lower end range accrued accounting pension postretirement benefits accruals related pension postretirement benefits based actuarial calculations performing calculations actuaries must use assumptions including related return expect earn plan assets discount rates used calculating benefit obligations rate expect compensation employees increase plan term cost health care benefits provided plans factors actual results may differ assumptions included actuarial calculations result estimates associated pension postretirement benefits often revised future either negative positive effect costs recognize accruals make following table shows impact one percent change primary assumptions used actuarial calculations associated pension postretirement benefits year ended december 31 2003 millions 1 actual return plan assets one percent lower expected return plan assets expected cash contributions pension postretirement benefit plans would significantly change discount rate assumptions reflect rates return investments expect use settle pension postretirement obligations future combined current expected rates return investment grade corporate bonds develop discount rates used benefit expense obligation estimates september 30 2003 estimates net benefit expense income partially based expected return pension plan assets use marketrelated value plan assets determine expected return pension plan assets determining marketrelated value plan assets differences expected actual asset returns deferred recognized three years due losses pension plan assets 2002 fair value plan assets used determine 2003 net benefit expense income less marketrelated value plan assets used fair value plan assets instead marketrelated value plan assets determining expected return pension plan assets net benefit income would 108 million lower year ended december 31 2003 recorded additional pension liability primary pension plan fair value plan assets exceeded accumulated benefit obligation plan approximately 202 million 362 million september 30 2003 december 31 2003 accumulated benefit obligation exceeded plan assets primary pension plan september 30 2003 would recorded pretax additional pension liability approximately 960 million plus amount equal excess accumulated benefit obligation plan assets primary pension plan would also recorded amount equal additional pension liability accumulated comprehensive loss net taxes balance sheet new accounting pronouncements issued yet adopted see item 8 financial statements supplementary data note 2 new accounting pronouncements issued yet adopted incorporated herein reference risk factors cautionary statement purposes safe harbor provisions private securities litigation reform act 1995 report contains incorporates reference forwardlooking statements within meaning private securities litigation reform act 1995 forwardlooking statement includes statement assumptions bases underlying forwardlooking statement caution believe assumptions bases reasonable good faith assumed facts bases almost always vary actual results differences assumed facts bases actual results material depending upon circumstances forwardlooking statement management express expectation belief future results expectation belief expressed good faith believed reasonable basis cannot assure however statement expectation belief result achieved accomplished words believe expect estimate anticipate similar expressions generally identify forwardlooking statements forwardlooking statements whether written oral expressly qualified cautionary statements cautionary statements may accompany forwardlooking statements addition disclaim obligation update forwardlooking statements reflect events circumstances date report mind consider risks discussed elsewhere report documents file sec time following important factors could cause actual results differ materially expressed forwardlooking statement made us behalf risks related liquidity significant debt investment grade credit ratings impacted continue impact financial condition results operations liquidity significant debt approximately 22 billion december 31 2003 significant debt service debt maturity obligations ratings assigned senior unsecured indebtedness investment grade currently rated caa1 moodys negative outlook review possible downgrade ccc standard poors negative outlook ratings increased cost capital operating costs particularly trading operations could impede access capital markets moreover must retain greater liquidity levels operate business investment grade credit ratings expected debt maturities december 31 2003 2004 2005 2006 1409 million 1585 million 1769 million respectively ability generate access capital becomes significantly restrained financial condition future results operations could significantly adversely affected see item 8 financial statements supplementary data note 20 discussion debt may achieve objectives set forth longrange plan timely manner ability achieve objectives longrange plan well timing achievement subject part factors beyond control factors include 1 ability raise cash asset sales may impacted ability locate potential buyers timely fashion obtain reasonable price competing asset sale programs competitors 2 ability recover working capital 3 ability generate additional cash improving performance pipeline production operations 4 ability exit power trading lng businesses manner within time period expect 5 ability significantly reduce debt 6 ability preserve sufficient cash flow service debt obligations fail achieve timely manner targets longrange plan liquidity financial position could materially adversely affected addition possible asset sales contemplated longrange plan could prices current book value assets could result recorded losses could substantial breach covenants applicable debt financing obligations could affect ability borrow funds could accelerate debt financing obligations subsidiaries debt financing obligations contain restrictive covenants crossacceleration provisions breach covenants could preclude us subsidiaries issuing letters credit borrowing 3 billion revolving credit facility could accelerate longterm debt financing obligations subsidiaries occur may able repay debt financing obligations upon acceleration discussed item 8 financial statements supplementary data note 1 restated historical financial statements reflect reduction historically reported proved natural gas oil reserves revise manner accounted certain hedges primarily associated anticipated natural gas production believe material restatements financial statements discussed item 8 financial statements supplementary data note 1 would constituted events default 3 billion revolving credit facility various financing transactions specifically provisions arrangements related representations warranties accuracy historical financial statements debt total capitalization ratio 2004 received several waivers 3 billion revolving credit facility various financing transactions address issues waivers continue effective also received extension various lenders november 30 2004 file first second quarter 2004 forms 10q expect meet unable file forms 10q date able negotiate additional extension filing deadline 3 billion revolving credit facility various transactions could accelerated part obtaining waivers also amended various provisions 3 billion revolving credit facility including provisions related events default limitations ability well subsidiaries repay indebtedness scheduled mature june 30 2005 based upon review covenants contained indentures financing agreements outstanding indebtedness acceleration 3 billion revolving credit facility could constitute event default debt agreements addition three subsidiaries indentures associated public debt contain 5 million crossacceleration provisions various financing arrangements entered us subsidiaries including el paso cgp el paso production holding company include covenants require us file financial statements within specified time periods noncompliance covenants constitute automatic event default instead agreements subject acceleration indenture trustee holders least 25 percent outstanding principal amount series debt provides notice issuer noncompliance indenture event noncompliance cured filing financial statements within specified periods time 30 90 days receipt notice depending particular indenture avoid acceleration repayment holders el paso production holding companys debt obligations waived financial filing requirements december 31 2004 filing first second quarter 2004 forms 10q subsidiaries cure event noncompliance resulting failure file financial statements subsidiaries addition neither subsidiaries received notice default caused failure file financial statements financial statements subsidiaries also impacted restatement event acceleration may unable meet payment obligations respect related indebtedness furthermore material restatements financial statements period ended december 31 2001 could cause default financing agreements entered connection 950 million gemstone notes due october 31 2004 currently 748 million gemstone notes outstanding however currently expect repay notes full upon maturity october 31 2004 ability access capital markets existing shelf registration statement may limited result restatement historical financial results march 2004 announced downward revision natural gas oil reserves would result restatement historical financial statements august 2004 announced would required restate historical financial statements manner applied accounting rules related hedges natural gas production certain derivatives result time required complete revisions annual report form 10k filed timely manner period 12 months date filing restrict ability access approximately 1 billion capacity shelf registration statement without filing additional disclosure information sec may subject full review additional disclosure requirements related review sec could expensive impede ability access capital timely fashion ability access capital becomes significantly restrained financial condition future results operations could significantly adversely affected subject financing interest rate exposure risks future success depends ability access capital markets obtain financing cost effective rates ability access financial markets obtain costeffective rates future dependent number factors many cannot control including changes credit ratings interest rates structured commercial financial markets market perceptions us natural gas energy industry changes tax rates due new tax laws stock price changes market prices energy risks related legal regulatory matters ongoing litigation investigations related financial statements associated reserve estimates hedges could significantly adversely affect business may 2004 completed independent investigation reason cause significant revisions natural gas oil reserves following investigation announced would reduce proved natural gas oil reserve estimates december 31 2003 approximately 18 tcfe result restate historical financial statements august 2004 announced would required restate historical financial statements manner applied accounting rules related many historical hedges primarily associated hedges anticipated natural gas production conducted additional investigation reasons restatement result reduction reserve estimates several class action lawsuits filed us several subsidiaries reserve revisions also subject investigations sec us attorney hedging matters also subject investigation us attorney may become subject separate inquiry sec could result significant fines us investigations lawsuits possible future claims based facts may negatively impact credit ratings place demands liquidity cannot provide assurance time effects results investigations class action lawsuits material financial conditions results operations liquidity unable certify effectiveness internal controls financial reporting could suffer loss public confidence internal controls could negative impact financial performance market value common stock item 308 regulation sk promulgated pursuant section 404 sarbanesoxley act 2002 requires us december 31 2004 provide annual report internal controls financial reporting including assessment whether internal controls financial reporting effective also required auditors attest assessment individually opine effectiveness internal controls financial reporting connection ongoing efforts assess effectiveness design operation internal controls identified several deficiencies collectively constitute material weakness internal controls taken taking significant steps remediate deficiencies information regarding evaluation internal controls identified deficiencies therein remediation efforts related thereto see item 9a controls procedures timely complete assessment internal controls adequately address known material weaknesses discover material weaknesses disclosed managements assessment internal controls periodic filings auditor either disagrees assessment otherwise concludes internal controls effective disclosed auditors report internal controls periodic filings furthermore auditors unable timely complete assessment internal controls auditors review assessment efforts would deficient reporting obligations securities exchange act 1934 may restrict access capital markets would result noncompliance filing obligations significant portion financing documents could result event default one documents circumstances could subjected additional regulatory scrutiny suffer loss public confidence internal controls could negative impact financial performance market value common stock agencies regulate pipeline businesses customers affect profitability pipeline businesses regulated ferc us department transportation various state local regulatory agencies regulatory actions taken agencies potential adversely affect profitability particular ferc regulates rates pipelines permitted charge customers services pipelines tariff rates reduced future proceeding pipelines volume business currently permitted rates decreased significantly pipelines required substantially discount rates services competition regulatory pressure profitability pipeline businesses could reduced addition increased regulatory requirements relating integrity pipelines requires additional spending order maintain compliance requirements additional requirements enacted could significantly increase amount expenditures state agencies regulate pipelines local distribution company customers could impose requirements could impact demand pipelines services costs environmental liabilities regulations litigation could exceed estimates operations subject various environmental laws regulations laws regulations obligate us install maintain pollution controls clean various sites regulated materials may disposed released sites designated superfund sites epa comprehensive environmental response compensation liability act also party legal proceedings involving environmental matters pending various courts agencies compliance environmental laws regulations require significant costs cleanup damages arising contaminated properties failure comply environmental laws regulations may result fines penalties imposed possible us estimate reliably amount timing future expenditures related environmental matters uncertainties estimating clean costs discovery new sites information uncertainty quantifying liability environmental laws impose joint several liability potentially responsible parties nature environmental laws regulations possible introduction future environmental laws regulations although believe established appropriate reserves liabilities including clean costs could required set aside additional reserves future due uncertainties amounts could material additional information concerning environmental matters see part item 3 legal proceedings item 8 financial statements supplementary data note 22 costs litigation matters could exceed estimates involved various lawsuits subsidiaries sued although believe established appropriate reserves liabilities could required set aside additional reserves future amounts could material additional information concerning litigation matters see part item 8 financial statements supplementary data note 22 risks related business operations subject operational hazards uninsured risks operations subject inherent risks normally associated operations including pipeline ruptures explosions pollution release toxic substances fires adverse weather conditions hazards could result damage destruction facilities damages persons property addition operations face possible risks associated acts aggression domestic foreign assets events occur could suffer substantial losses maintain insurance many risks extent amounts believe reasonable financial condition operations could adversely affected significant event occurs fully covered insurance success pipeline business part depends factors beyond control natural gas natural gas liquids transport store owned third parties result volume natural gas natural gas liquids involved activities depends actions third parties beyond control following factors beyond control may unfavorably impact ability maintain increase current throughput renegotiate existing contracts expire remarket unsubscribed capacity pipeline systems future weather conditions including favor alternative energy sources hydroelectric power price competition drilling activity supply availability natural gas expiration andor turn back significant contracts service area competition changes regulation action regulatory bodies credit risk customer base increased cost capital opposition energy infrastructure development especially environmentally sensitive areas adverse general economic conditions expiration andor renewal existing interests real property associated pipeline subsidiary unfavorable movements natural gas liquids prices revenues pipeline businesses generated contracts must renegotiated periodically substantially pipeline subsidiaries revenues generated contracts expire periodically must renegotiated extended replaced cannot assure able extend replace contracts expire terms renegotiated contracts favorable existing contracts example southern california gas company epngs largest customer requested september 2004 received approval california public utilities commission give notice terminate certain transportation agreements us february 25 2005 intent negotiating reduce capacity holdings pipeline system part effort diversify capacity holdings discussion matters see part item business regulated businesses pipelines segment markets competition particular ability extend andor replace contracts could adversely affected factors cannot control including competition pipelines including proposed construction companies additional pipeline capacity lng terminals markets served interstate pipelines changes state regulation local distribution companies may cause negotiate shortterm contracts turn back capacity contracts expire reduced demand market conditions areas serve availability alternative energy sources gas supply points regulatory actions unable renew extend replace contracts renew less favorable terms may suffer material reduction revenues earnings fluctuations energy commodity prices could adversely affect pipeline businesses revenues generated transmission storage processing contracts depend volumes rates affected prices natural gas natural gas liquids increased prices could result reduction volumes transported customers power companies depending price fuel may dispatch gas fired power plants increased prices could also result industrial plant shutdowns load losses competitive fuels well local distribution companies loss customer base success transmission storage processing operations subject continued development additional oil natural gas reserves ability access additional suppliers interconnecting pipelines offset natural decline existing wells connected systems decline energy prices could precipitate decrease development activities could cause decrease volume reserves available transmission storage processing systems facilities natural gas prices supply basins connected pipeline systems higher delivered basis offsystem markets delivered prices natural gas producing regions ability compete transporters may negatively impacted fluctuations energy prices caused number factors including regional domestic international supply demand availability adequacy transportation facilities energy legislation federal state taxes sale transportation natural gas natural gas liquids abundance supplies alternative energy sources political unrest among oil producing countries natural gas oil prices volatile substantial decrease natural gas oil prices changes basis differentials could adversely affect financial results exploration production business future financial condition revenues results operations cash flows future rate growth carrying value natural gas oil properties depend primarily upon prices receive natural gas oil production natural gas oil prices historically volatile likely continue volatile future especially given current world geopolitical conditions prices natural gas oil subject variety additional factors beyond control factors include level consumer demand supply natural gas oil commodity processing gathering transportation availability level imports price foreign natural gas oil ability members organization petroleum exporting countries agree maintain oil price production controls domestic governmental regulations taxes price availability alternative fuel sources weather conditions market uncertainty political conditions hostilities natural gas oil producing regions worldwide economic conditions decreased demand use natural gas oil market concerns global warming changes governmental policies regulations due climate change initiatives approximately 83 percent proved reserves december 31 2003 natural gas reserves substantially sensitive changes natural gas prices changes oil prices declines natural gas oil prices would reduce revenue could reduce amount natural gas oil produce economically result could adversely affect financial results production business changes natural gas oil prices significant impact calculation full cost ceiling test significant decline natural gas oil prices could result downward revision reserves writedown carrying value natural gas oil properties could substantial would negatively impact net income stockholders equity success natural gas oil exploration production businesses dependent part factors beyond control addition prices performance natural gas oil exploration production businesses dependent part upon number factors cannot control including results future drilling activity including exploratory programs recently successful ability identify precisely locate prospective geologic structures drill successfully complete wells structures timely manner ability expand leased land positions desirable areas often subject intensely competitive conditions increased competition search acquisition reserves future drilling production development costs including drilling rig rates oil field services costs future tax policies rates drilling production incentives state federal foreign governments increased federal state regulations including environmental regulations limit restrict ability drill natural gas oil wells reduce operational flexibility increase capital operating costs decreased demand use natural gas oil market concerns global warming changes governmental policies regulations due climate change initiatives declines production volumes including gulf mexico continued access sufficient capital fund drilling programs develop replace reserve base rapid depletion characteristics natural gas oil drilling producing operations involve many risks may profitable operations subject risks normally incident operation development natural gas oil properties drilling natural gas oil wells including well blowouts cratering explosions pipe failure fires formations abnormal pressures uncontrollable flows natural gas oil brine well fluids release contaminants environment environmental hazards risks nature risks liabilities could exceed insurance policy limits case environmental fines penalties cannot insured result could incur substantial costs could adversely affect future results operations cash flows financial condition addition drilling operations subject risk encounter commercially productive reservoirs evidenced lack success recent exploratory programs new wells drilled us may unproductive may recover portion investment wells drilling natural gas oil unprofitable dry holes also due wells productive produce sufficient net reserves return profit realized prices deducting drilling operating costs estimating reserves production future net cash flow difficult estimating quantities proved natural gas oil reserves complex process involves significant interpretations assumptions requires interpretations available technical data various estimates including estimates based upon assumptions relating economic factors future commodity prices production costs severance excise taxes capital expenditures workover remedial costs assumed effect governmental regulation result reserve estimates inherently imprecise also use 10 percent discount factor estimating value reserves prescribed sec may necessarily represent appropriate discount factor given actual interest rates risks production business natural gas oil industry general subject significant variations interpretations assumptions used estimates changes conditions could cause estimated quantities net present value reserves differ materially reserve data included report represents estimates assume present values referred report represent current market value estimated natural gas oil reserves timing production expenses development production natural gas oil properties affect timing actual future net cash flows proved reserves present value changes present value reserves could cause writedown carrying value natural gas oil properties could substantial would negatively affect net income stockholders equity december 31 2003 approximately 34 percent estimated proved reserves undeveloped recovery undeveloped reserves requires significant capital expenditures successful drilling operations reserve data assumes make expenditures conduct operations successfully future events including commodity price changes may cause assumptions change addition estimates undeveloped reserves proved nonproducing reserves subject greater uncertainties estimates producing reserves success power generation activities part depends many factors beyond control success remaining domestic international power projects could adversely affected factors beyond control including alternative sources supplies energy becoming available due new technologies interest self generation cogeneration increases costs generation including increases fuel costs uncertain regulatory conditions resulting ongoing deregulation electric industry us foreign jurisdictions ability negotiate successfully enter advantageous power purchase supply agreements possibility reduction projected rate growth electricity usage result factors regional economic conditions excessive reserve margins implementation conservation programs risks incidental operation maintenance power generation facilities inability customers pay amounts owed power purchase agreements increasing price volatility due deregulation changes commodity trading practices overcapacity generation markets served power plants interest use derivative financial instruments could result financial losses subsidiaries use futures swaps option contracts traded new york mercantile exchange overthecounter options price basis swaps natural gas merchants financial institutions extent unhedged positions hedging procedures work planned fluctuating commodity prices could cause sales net income cash requirements volatile could incur financial losses future result volatility market values energy commodities trade one counterparties fails perform contract valuation financial instruments involves estimates changes assumptions underlying estimates occur changing valuation instruments potentially resulting financial losses extent hedge commodity price exposure interest rate exposure forego benefits would otherwise experience commodity prices increase interest rates change use derivatives also requires posting cash collateral counterparties impact working capital current assets liabilities commodity prices interest rates change additional information concerning derivative financial instruments see item 7a quantitative qualitative disclosures market risk item 8 financial statements supplementary data note 14 foreign operations investments involve special risks activities areas outside us including material concentration investment exposure international power pipeline production projects approximately 16 billion located brazil approximately 03 billion pakistan subject risks inherent foreign operations including loss revenue property equipment result hazards expropriation nationalization wars insurrection political risks effects currency fluctuations exchange controls devaluation foreign currencies economic problems changes laws regulations policies foreign governments including associated changes governing parties item 7aitem 7 management’s discussion analysis financial condition results operations management’s discussion analysis includes forwardlooking statements subject risks uncertainties actual results may differ substantially statements make section due number factors discussed beginning page 76 overview business purpose provide natural gas related energy products safe efficient dependable manner north america’s largest natural gas pipeline system large independent natural gas producer also operate energy marketing trading business power business midstream assets investments investment small telecommunications business power business primarily consists international assets since end 2001 business activities largely focused maintaining core businesses pipelines production attempting liquidate otherwise divest businesses operations core longterm objectives performing consistently expectations time made investment overall objective period reduce debt improve liquidity time invest core business activities actions period significantly impacted financial condition sale almost 10 billion operating assets actions also resulted significant financial losses asset impairments realized losses asset sales reduction income businesses sold believe 2004 watershed year us able meet exceed number goals established 2003 long range plan part efforts 2004 • focused capital investment core pipeline production businesses 2002 2003 2004 spent 87 percent 91 percent 97 percent total capital dollars • completed sale number assets investments including international production properties substantial portion general limited partnership interests gulfterra significant portion worldwide petroleum markets operations significant portion domestic power generation operations merchant lng business total proceeds sales approximately 33 billion • reduced net debt net cash 34 billion 2004 lowering net debt 171 billion december 31 2004 • continued costreduction efforts goal achieving 150 million savings end 2006 noted 2004 focused expanding pipeline operations beginning turnaround production business year completed major expansions pipeline operations including cheyenne plains project provide transmission outlets natural gas supply rocky mountains moving forward seafarer cypress projects fulfill demand natural gas southeastern united states primarily florida additionally continue work recontracting capacity systems successful date efforts production operations instituted new rigorous risk analysis process emphasizes strict capital discipline second half 2004 process resulted shifting capital areas higher returns improved drilling results helped us begin stabilization domestic production addition recently made several strategic acquisitions production properties texas 2005 continue work achieve longrange goals • simplifying capital structure • continuing focus expansions core pipeline business completing turnaround production business • selling additional assets expect generate proceeds 18 billion 22 billion • reducing outstanding debt net cash 15 billion end 2005 • continuing reduce costs achieve cost savings outlined plan capital resources liquidity rely cash generated internal operations primary source liquidity well available credit facilities project bank financings proceeds asset sales issuance longterm debt preferred securities equity securities time also used structured financing transactions sometimes referred offbalance sheet arrangements expect future funding working capital needs capital expenditures longterm debt repayments dividends financing activities continue provided sources although expect use offbalance sheet arrangements degree future existing projected sources cash impacted operational financial risks influence overall amount cash generated capital available us example cash generated business operations may impacted among things changes commodity prices demands commodities services success recontracting existing contracts drilling success competition providers alternative energy sources collateral demands recovery cash posted collateral impacted natural gas prices hedging levels credit quality us counterparties cash generated future asset sales may depend condition location assets number interested buyers addition future liquidity impacted ability access capital markets may restricted due credit ratings general market conditions limitations ability access existing shelf registration statement discussed part ii item 8 financial statements supplementary data note 15 discussion risks impact liquidity see risk factors beginning page 83 subsidiaries significant potential source liquidity us participate cash management program extent permitted financing agreements indentures cash management program depending whether participating subsidiary shortterm cash surpluses requirements either provide cash provide cash us 2004 took additional steps reduce overall debt obligations actions included entering new 3 billion credit agreement selling entities substantial debt obligations follows millions 1 includes proceeds 125 billion term loan new 3 billion credit agreement 2 includes 850 million repayments previous 3 billion revolving credit facility 3 consists 815 million debt related utility contract funding 72 million debt related mohawk river funding iv discussion longterm debt financing obligations credit facilities see part ii item 8 financial statements supplementary data note 15 december 31 2004 available liquidity follows billions addition available liquidity expect generate significant operating cash flow 2005 supplement operating cash flow proceeds asset sales expect range 18 billion 22 billion next 12 24 months 07 billion already closed filing date form 10k also utilize proceeds financing activities needed march 2005 completed 200 million financing cig proceeds used refinance 180 million bonds cig mature june 2005 general purposes 2005 expect spend 16 billion 17 billion capital investments mainly core pipeline production businesses also spent approximately 03 billion acquisitions natural gas oil operations 2005 may make additional acquisitions 2005 december 31 2004 contractual debt maturities 2005 2006 approximately 06 billion 13 billion additionally approximately 08 billion zerocoupon debentures stated maturity 2021 contain option whereby holders require us redeem obligations february 2006 currently expect holders exercise right combined contractual maturities could require us retire 21 billion debt 2006 far 2005 prepaid approximately 07 billion euro denominated debt originally scheduled mature march 2006 02 billion zerocoupon debentures result prepayments reduced 2006 expected maturities approximately 12 billion give us greater financial flexibility next year finally 2005 may also prepay number obligations including derivative positions marketing trading operations possibly amounts outstanding western energy settlement among items prepayments could total approximately 11 billion amount already prepaid approximately 240 million obligations transfer derivative contracts constellation power march 2005 connection sale cedar brakes ii net available liquidity includes 3 billion credit agreement december 31 2004 borrowed 125 billion term loan issued approximately 12 billion letters credit agreement availability borrowings credit agreement ability incur additional debt subject various conditions described part ii item 8 financial statements supplementary data note 15 currently meet conditions include compliance financial covenants ratios required agreements absence default agreements continued accuracy representations warranties contained agreements financial coverage ratios 3 billion credit agreement change time however covenants currently require debt consolidated ebitda exceed 65 1 ratio consolidated ebitda interest expense dividends equal greater 16 1 defined credit agreement december 31 2004 ratio debt consolidated ebitda 485 1 ratio consolidated ebitda interest expense dividends 193 1 3 billion credit agreement collateralized equity interests tgp epng anr cig wic southern gas storage company anr storage company based upon review covenants contained indentures financing obligations acceleration outstanding amounts credit agreement could constitute event default debt agreements event default lenders credit agreement exercise rights collateral could required liquidate interests entities collateralize credit agreement additionally would unable obtain cash pipeline subsidiaries cash management program event default subsidiaries’ indentures finally three subsidiaries indentures associated public debt contain 5 million crossacceleration provisions believe able meet ongoing liquidity cash needs combination available cash borrowings 3 billion credit agreement also believe actions taken date allow us greater financial flexibility remainder 2005 2006 2004 however number factors could influence liquidity sources well timing ultimate outcome ongoing efforts plans factors discussed detail beginning page 83 overview cash flow activities 2004 compared 2003 years ended december 31 2004 2003 cash flows summarized follows cash continuing operating activities overall cash generated continuing operating activities decreased 12 billion largely due payment 06 billion related principal litigation western energy settlement 2004 higher cash recovered margin deposits 2003 recovered 07 billion cash 2003 margin deposits substituting letters credit cash deposit compared 01 billion recovered 2004 cash continuing investing activities year ended december 31 2004 net cash provided continuing investing activities 08 billion year received net proceeds approximately 09 billion sales domestic power assets well 10 billion sales general limited partnership interests gulfterra various field services assets also released restricted cash 06 billion escrow paid settling parties western energy settlement discussed 2004 capital expenditures included following billions 2005 expect total capital expenditures including acquisitions approximately 19 billion divided approximately equally production pipelines segments 2004 production segment received funds approximately 110 million third parties net profits interest agreements march 2005 purchased interests held party one agreements 62 million see part ii item 8 financial statements supplementary data heading supplemental natural gas oil operations discussion agreements september 2004 incurred significant damage sections offshore pipeline facilities due hurricane ivan cost estimates currently 80 million 95 million range damage assessment still progress expect insurance reimbursement exception 2 million deductible event however timing reimbursements may occur later capital expenditures damaged facilities may increase net capital expenditures 2005 january 2005 sold remaining interests enterprise general partner 425 million also sold membership interest two subsidiaries operate natural gas gathering systems indian springs processing facility enterprise 75 million 2005 continue divest appropriate noncore assets based longterm business strategy including additional power assets asia countries see part item 1 business part ii item 8 financial statements supplementary data note 3 discussion divestitures asset divestitures discontinued operations timing extent additional sales based level market interest based upon obtaining necessary approvals cash continuing financing activities net cash used continuing financing activities 12 billion year ended december 31 2004 significant financing cash inflows included 125 billion borrowed term loan new 3 billion credit agreement also 10 billion cash contributed discontinued operations amount contributed discontinued operations 02 billion generated operations 12 billion received proceeds sales eagle point aruba refineries international production operations primarily western canada 04 billion used repay longterm debt related aruba refinery significant financing cash outflows included net repayments 09 billion previous 3 billion revolving credit facilities 2004 prior entering new 3 billion credit agreement also made 25 billion payments retire third party longterm debt redeem preferred interests continued efforts reduce overall debt obligations longrange plan see part ii item 8 financial statements supplementary data note 15 detail financing activities contractual obligations offbalance sheet arrangements course business activities enter variety financing arrangements contractual obligations following discusses contingent obligations often referred offbalance sheet arrangements also present aggregated information contractual cash obligations reflected financial statements shortterm longterm debt accrued liabilities obligations operating leases capital commitments reflected financial statements offbalance sheet arrangements related liabilities guarantees involved various joint ventures ownership arrangements sometimes require additional financial support form financial performance guarantees financial guarantee obligated make payments guaranteed party fails make payments violates terms financial arrangement performance guarantee provide assurance guaranteed party execute terms contract required perform behalf example guaranteed party required deliver natural gas third party fails would required either deliver natural gas make payments third party equal difference contract price market value natural gas also periodically provide indemnification arrangements related assets businesses sold arrangements include indemnifications income taxes resolution existing disputes environmental matters necessary expenditures ensure safety integrity assets sold evaluate guarantees indemnity arrangements time entered period thereafter determine whether liability exists estimated record accruals criteria met december 31 2004 accrued 70 million related arrangements december 31 2004 also approximately 40 million financial performance guarantees indemnification arrangements otherwise reflected financial statements contractual obligations following table summarizes contractual obligations december 31 2004 years presented amounts undiscounted 1 see part ii item 8 financial statements supplementary data note 15 2 see part ii item 8 financial statements supplementary data note 17 3 includes contractual environmental obligations included noncurrent liabilities balance sheet excludes expected contributions pension postretirement benefit plans 68 million 2005 209 million four year period ended december 31 2009 expected contributions contractually required 4 see part ii item 8 financial statements supplementary data note 17 5 contractual commitments purchase obligations defined legally enforceable agreements purchase goods services fixed minimum quantities fixed minimum variable price provisions detail approximate timing underlying obligations 6 commitments demand charges tolling arrangements firm access natural gas transportation storage capacity 7 includes purchase commitments natural gas power 8 includes commitments drilling seismic activities production operations various maintenance engineering procurement construction contracts well service license agreements used operations commoditybased derivative contracts utilize derivative financial instruments hedging activities power contract restructuring activities historical energy trading activities tables derivatives designated hedges primarily consist instruments used hedge natural gas production derivatives power contract restructuring activities relate power purchase sale agreements arose activities business commoditybased derivative contracts relate historical energy trading activities well derivative contracts designated hedges following table details fair value commoditybased derivative contracts year maturity valuation methodology december 31 2004 1 includes 259 million intercompany derivatives eliminate consolidation impact consolidated assets liabilities price risk management activities 2 march 2005 sold cedar brakes ii subsidiaries related restructured power contracts fair value 596 million december 31 2004 connection sale also assigned terminated commoditybased derivatives fair value loss 240 million december 31 2004 3 exchangetraded positions traded active exchanges new york mercantile exchange international petroleum exchange london clearinghouse following reconciliation commoditybased derivatives years ended december 31 2004 2003 1 includes 861 million 75 million derivative contracts sold conjunction sales utility contract funding mohawk river funding iv 2004 see part ii item 8 financial statements notes 3 5 additional information sales 2 fourth quarter 2004 recorded 227 million charge associated sale cedar brakes ii subsidiaries related restructured power contracts see part ii item 8 financial statements supplementary data notes 3 5 additional information sale 3 second quarter 2004 reclassified 69 million liability western energy settlement obligation price risk management activities fair value contract settlements period represents estimated amounts derivative contracts settled physical delivery commodity claim cash accounts receivable payable fair value contract settlements also includes physical financial contract terminations due counterparty bankruptcies sale settlement derivative contracts early termination sale entities contracts change fair value contracts year represents change value contracts beginning period date origination acquisition settlement early termination settled terminated end period 2003 conjunction acquisition chaparral consolidated number derivative contracts majority value contracts power purchase agreements power supply agreements related power contract restructuring activities conducted chaparral december 2004 designated number commoditybased derivative contracts marketing trading segment hedges 2005 2006 natural gas production result reclassified amount derivatives designated hedges beginning fourth quarter 2004 combination positions production segment’s hedges result us receiving following prices natural gas production 1 production segment record revenues related natural gas volumes price operating results 2 difference production segment’s hedge price cash price receive upon settlement derivative transactions previously recorded losses marketing trading segment stabilize company’s pricing outlook 2005 2007 marketing trading segment entered additional contracts provide floor price portion unhedged production 2005 2006 2007 ceiling price portion unhedged 2006 production contracts reported marktomarket basis result us receiving following cash prices natural gas production 1 floor price minimum cash price received option contract 2 ceiling price maximum cash price received option contract results operations overview since 2001 experienced tremendous change businesses prior time grown mergers acquisitions internal growth initiatives time incurred significant amounts debt obligations late 2001 driven bankruptcy number energy sector participants followed increased scrutiny debt levels credit rating downgrades debt many competitors focus changed improving liquidity paying debt simplifying capital structure reducing cost capital resolving substantial contingences returning core natural gas businesses accordingly operating results three year period 2002 2004 substantially impacted number significant events asset sales significant legal settlements ongoing business restructuring efforts part change focus december 31 2004 operating business segments pipelines production marketing trading power field services segments provide variety energy products services managed separately requires different technology marketing strategies businesses divided two primary business lines regulated nonregulated regulated business includes pipelines segment nonregulated business includes production marketing trading power field services segments management uses ebit assess operating results effectiveness business segments define ebit net income loss adjusted items impact income loss continuing operations extraordinary items discontinued operations impact accounting changes ii income taxes iii interest debt expense iv distributions preferred interests consolidated subsidiaries businesses consist consolidated operations well investments unconsolidated affiliates exclude interest debt expense distributions preferred interests consolidated subsidiaries investors may evaluate operating results independently financing methods capital structure believe ebit helpful investors allows effectively evaluate operating performance consolidated businesses unconsolidated investments using performance measure analyzed internally management ebit may comparable measurements used companies additionally ebit considered conjunction net income performance measures operating income operating cash flow reconciliation ebit segment consolidated net loss three years ended december 31 1 see part ii item 8 financial statements supplementary data note 1 discussion restatement 2002 financial statements affected pipelines segment results amounts reported cumulative effect accounting change 2002 refocused activities core businesses divesting noncore businesses restructuring organization incurred losses incremental costs year period also resolved significant legal contingencies items described table detailed discussion factors items impacting financial performance see individual segment results included part ii item 8 financial statements supplementary data notes 3 5 21 1 includes net impairments costbased investments included income expense 2 includes gain transactions enterprise goodwill impairment 3 includes 66 million accretion expense charges included operation maintenance expense associated western energy settlement 4 excludes intercompany transactions related ucf restructuring transaction eliminated consolidation pipelines segment experienced improved financial performance 2002 2004 benefitting completion number expansion projects resolution significant legal issues related western energy crisis 2001 production segment experienced earnings volatility 2002 2004 threeyear period production segment sold significant number natural gas oil properties coupled reduced capital spending program generally disappointing drilling results mechanical failures certain wells produced steady decline production volumes timeframe however 2004 benefited favorable pricing environment allowed better anticipated results favorable pricing environment expected continue provide benefits production segment 2005 although future results largely impacted production levels volumes produce driven ability grow existing reserve base successful drilling program andor acquisitions marketing trading segment also experienced significant earnings volatility 2002 2003 2004 beginning 2002 began process exiting trading business time overall energy trading industry declined combination actions events decrease value fixedprice natural gas derivative contracts due natural gas price increases resulted substantial losses marketing trading segment 2002 2003 2004 expect segment continue experience losses 2005 continues performing transportation tolling contracts however due repositioning number natural gas derivative contracts hedges december 2004 expect future losses segment less experienced 2002 2004 finally 2002 2004 continued refocus restructure company around core businesses incurred significant charges related asset sales impairments restructuring costs field services power segments well corporate results also incurred approximately 20 billion including 14 billion 2003 tax losses exiting certain international natural gas oil production operations petroleum markets coal businesses classified discontinued operations discussion year results business segments corporate activities income statement items individual segment results 2002 pipelines segment presented discussed restated errors resulting misinterpretation provisions sfas nos 141 142 upon adoption standards see part ii item 8 financial statements supplementary data note 1 discussion restatement regulated business pipelines segment pipelines segment consists interstate natural gas transmission storage lng terminalling related services primarily united states face varying degrees competition segment pipelines proposed lng facilities well alternative energy sources used generate electricity hydroelectric power nuclear coal fuel oil ferc regulates rates charge customers rates function cost providing services customers including reasonable return invested capital result revenues historically relatively stable however financial results subject volatility due factors changes natural gas prices market conditions regulatory actions competition creditworthiness customers weather 2004 84 percent transportation service storage lng terminalling revenues attributable reservation charges paid firm customers remaining 16 percent revenues variable also experience earnings volatility amount natural gas utilized operations differs amounts receive purpose historically much business conducted longterm contracts customers however past several years customers shifted traditional dependence solely longterm contracts portfolio approach balances shortterm opportunities longterm commitments shift increase volatility revenues due changes market conditions competition driven state utility deregulation local distribution company mergers new supply sources volatility natural gas prices demand shortterm capacity new power plants markets addition ability extend existing customer contracts remarket expiring contracted capacity dependent competitive alternatives regulatory environment federal state local levels market supply demand factors relevant dates contracts extended expire duration new renegotiated contracts affected current prices competitive conditions judgments concerning future market trends volatility subject regulatory constraints attempt recontract remarket capacity maximum rates allowed tariffs although times discount rates remain competitive level discount varies pipeline systems existing contracts mature various times varying amounts throughput capacity continue manage recontracting process limit risk significant impacts revenues weighted average remaining contract term active contracts approximately five years december 31 2004 expiration schedule contracts executed december 31 2004 including whose terms begin 2005 later 1 reflects impact agreement entered extend 750 mmcfd socal’s current capacity effective september 1 2006 terms three five years agreement subject ferc approval 2 includes approximately 1564 mmcfd currently contract epng’s system 2011 beyond subject early termination august 2006 provided customers give timely notice intent terminate operating results operating results analysis results pipelines segment three years ended december 31 1 throughput volumes exclude volumes related equity investments portland natural gas transmission system epic energy australia trust alliance pipeline sold addition volumes exclude intrasegment activities throughput volumes include volumes related mexico investments transferred power segment effective january 1 2004 following contributed overall ebit increases 2004 compared 2003 compared 2002 1 consists costs operations electric power purchase costs shared services allocations environmental costs 2 consists individually insignificant items across several pipeline systems following provides discussion items listed well outlook events may affect operations future contract modificationsterminations included item impacts expiration epng’s historical risk sharing provisions reduced revenues 24 million 2004 ii impact epng’s ferc ordered restrictions remarketing expiring capacity contracts reduced epng’s 2003 revenues 35 million compared 2002 iii renegotiation restructuring several contracts pipeline systems including anr’s contracts energies contributed decrease revenues 36 million 2004 12 million 2003 iv termination dakota gasification facility contract anr’s system resulted lower operating revenues lower operating expenses 2004 without significant overall impact operating income ebit 2003 epng prohibited remarketing expiring capacity contracts due certain ferc orders capacity restrictions terminated completion phases ii epng’s line 2000 powerup project 2004 epng remains risk portion capacity turned back permanently released basis epng able however remarket capacity subject general requirement demonstrate sale capacity adversely impact service firm customers epng entered agreement effective september 1 2006 extend 750 mmcfd capacity pipeline system socalgas new service agreements primary term three five years serve socalgas’ core customers socalgas currently contracted epng’s system approximately 13 bcfd capacity epng continues efforts market remaining capacity including marketing efforts serve directly indirectly socalgas’ noncore customers serve new markets time uncertain whether remaining capacity recontracted guardian pipeline owned part energies currently provides portion energies’ firm transportation requirements therefore directly competes anr portion markets wisconsin could impact anr’s existing customer contracts well future contractual negotiations energies addition anr entered agreement shipper restructure one transportation contracts southeast leg well related gathering contract march 2005 restructuring completed anr received approximately 26 million included earnings first quarter 2005 gas used operations natural gas sales regulated pipelines financial impact operational gas net gas used operations based amount natural gas allowed recover dispose according applicable tariff relative amounts gas use operating purposes price natural gas disposition gas needed operations results revenues us driven volumes prices period 2003 2004 recovered fairly consistently volumes natural gas utilized operations regulated pipeline systems recoveries based factors system throughput facility enhancements ability operate systems efficient safe manner additionally steadily increasing natural gas price environment timeframe also resulted favorable impacts operating results 2004 versus 2003 versus 2002 anticipate area business continue vary future impacted things rate actions already implemented efficiency pipeline operations natural gas prices factors expansions three years ended december 31 2004 completed number expansion projects generated generate new sources revenues significant anr westleg expansion sng south system expansions tgp south texas expansion cig front range expansion expansions three year period added approximately 1968 mmcfd overall pipeline system pipeline systems connect principal gas supply regions largest consuming regions us wellpositioned capture growth opportunities rocky mountains deepwater gulf mexico infrastructure complements lng growth aggressively seeking attach new supplies natural gas systems order maintain adequate supply gas serve growing markets replace quantities lost due natural decline production wells currently attached system expansion projects currently process include rocky mountain expansions order provide outlet growing supply rocky mountain natural gas markets midwest region united states several expansion projects increase transportation capacity subject regulatory approval follows • cheyenne plains gas pipeline commenced freeflow operations december 2004 january 31 2005 fully inservice approval already received cheyenne plains phase ii add additional 179 mmcfd capacity scheduled available end 2005 • cig’s raton basin 2005 expansion add 104 mmcfd capacity scheduled available end 2005 • wic expects complete piceance lateral capacity 333 mmcfd end 2005 • epng’s line 1903 project consisting expansion cadiz california ehrenberg arizona expected inservice end 2005 increase capacity 372 mmcfd lng related expansions order help serve growing electrical generation needs state florida commenced 35 bcf expansion elba island lng facility targeted completed first quarter 2006 ii begun developing cypress project transport additional supplies florida market iii filed application ferc authority construct operate us portion proposed seafarer natural gas pipeline transport natural gas lng facility bahamas southern florida tgp anr systems continue experience intense competition along mainline corridors however wellpositioned provide transportation service discoveries deepwater gulf mexico lng supply growth along gulf coast new supplies expected offset continued decline production gulf mexico shelf additionally tgp developing connexion expansions northeast market area anr proceeding eastleg northleg expansions wisconsin market area regulatory matters november 2004 ferc issued proposed accounting release may impact certain costs interstate pipelines incur related pipeline integrity programs release enacted written would required expense certain future pipeline integrity costs instead capitalizing part property plant equipment although continue evaluate impact potential accounting release currently estimate release enacted written would required expense additional amount pipeline integrity expenditures range approximately 25 million 41 million annually next eight years 2003 reapplied statement financial accounting standards sfas 71 accounting effects certain types regulation cig wic systems resulting income recording regulatory assets systems sfas 71 allows company capitalize items considered future rate proceedings 18 million income resulted capitalization items believe considered cig’s wic’s future rate cases time cig wic reapplied sfas 71 adopted ferc depreciation rate regulated plant equipment change resulted increase depreciation expense approximately 9 million 2004 increase continue future december 31 2004 anr storage company reapplied sfas 71 immaterial impact also adopted ferc depreciation rate result future depreciation expense increases approximately 4 million annually pipeline systems periodically file changes rates subject approval ferc changes rates tariff provisions resulting regulatory proceedings potential negatively impact profitability listed status rate proceedings • sng filed rate case august 2004 settlement discussions major customers underway settlement conference scheduled early 2005 • epng expected file new rates would effective january 2006 • cig required file new rates would effective october 2006 • mpc expected file new rates would effective february 2007 pipelines requirements file new rate cases expect continue operating existing rates australian impairment 2002 impairment epic energy australia trust 141 million occurred due unfavorable regulatory environment increased competition operational complexities australia second quarter 2004 substantially exited investments australian operations western energy settlement 2003 el paso entered western energy settlement epng party settlement recorded charge 2002 operating expenses 412 million share expected settlement amounts charge represented value el paso stock cash epng paid settling parties second quarter 2003 settlement finalized epng recorded additional net pretax charge 127 million also 2003 accretion expense miscellaneous charges 13 million recorded included operating expenses nonregulated business production segment production segment conducts natural gas oil exploration production activities operating results driven variety factors including ability locate develop economic natural gas oil reserves extract reserves minimal production costs sell products attractive prices minimize total administrative costs longterm strategy includes developing production opportunities primarily united states brazil prudently divesting production properties outside regions emphasize strict capital discipline designed improve capital efficiencies use standardized risk analysis heightened focus cost control also implemented rigorous process booking proved natural gas oil reserves includes multiple layers reviews personnel independent reserve estimation process plan stabilize production improving production mix across operating areas generate predictable returns intend improve production mix allocating capital longlife slower decline projects develop projects longer reserve life areas accomplished rigorous capital review process balanced allocation capital development exploration projects supplemented acquisition activities lowrisk development locations provide operating synergies existing operations january 2005 announced two acquisitions east texas south texas 211 million march 2005 acquired interests held one parties net profits interest agreements 62 million see part ii item 8 financial statements supplementary data heading supplemental natural gas oil operations discussion net profits interest agreements acquisitions added properties approximately 139 bcfe existing proved reserves 52 mmcfed current production importantly texas acquisitions offer additional exploration upside two key operating areas reserves production costs estimate proved natural gas oil reserves december 31 2004 reflects 20 tcfe proved reserves united states 02 tcfe proved reserves brazil estimates prepared internally us ryder scott company independent petroleum engineering firm prepared estimate natural gas oil reserves 88 percent properties total estimate proved reserves prepared ryder scott within four percent internally prepared estimates ryder scott retained reports audit committee board directors properties reviewed ryder scott represented 88 percent properties based value additional information estimated proved reserves processes developed see part item 1 business non regulated business production segment part item 7 critical accounting policies risk factors part ii item 8 financial statements supplementary data heading supplemental natural gas oil operations 2004 total equivalent production declined 112 bcfe 27 percent compared 2003 decrease due steep production declines texas gulf coast offshore gulf mexico regions sale properties oklahoma new mexico end first quarter 2003 significantly reduced capital expenditure program 2004 compared 2003 began see production stabilize third fourth quarters 2004 instituted rigorous capital review process balanced allocation capital described depletion rate determined full cost method accounting due disappointing drilling performance 2004 resulted higher finding development costs expect domestic unit production depletion rate increase 180mcfe fourth quarter 2004 197mcfe first quarter 2005 future trends production depletion rates dependent upon amount capital allocated production segment level success drilling programs future sale acquisition activities relating proved reserves production hedge position part overall strategy hedge natural gas oil production stabilize cash flows reduce risk downward commodity price movements sales protect economic assumptions associated capital investment programs conduct hedging activities natural gas oil derivatives natural gas oil production hedging strategy partially reduces exposure downward movements commodity prices reported results operations financial position cash flows impacted significantly movements commodity prices period 2005 expect hedged approximately 50 percent anticipated daily natural gas production approximately 8 percent anticipated daily oil production hedging positions anticipated natural gas oil production december 31 2004 natural gas oil hedged natural gas prices listed 2005 2006 include impact designating trading contracts marketing trading segment hedges anticipated natural gas production december 1 2004 summary overall cash price el paso receive natural gas production including effect contracts see commoditybased derivative contracts beginning page 38 operational factors affecting year ended december 31 2004 production segment experienced following • higher realized prices realized natural gas prices include impact hedges increased eight percent oil condensate ngl prices increased 33 percent compared 2003 • average daily production 814 mmcfed excluding discontinued canadian international operations 15 mmcfed achieved low end projected production volume despite impact hurricanes gulf mexico • capital expenditures acquisitions 790 million excluding discontinued canadian international expenditures 29 million first quarter 2004 experienced disappointing drilling results result significantly reduced drilling activities instituted new rigorous risk analysis program emphasis strict capital discipline implementing new program increased domestic drilling activities third fourth quarters 2004 improved drilling results 2004 drilled 325 wells 96 percent success rate also acquired remaining 50 percent interest unopaso brazil july 2004 acquisition performed expectations fourth quarter 2004 • sale canadian international operations sold order focus operations united states brazil operating results production segment’s operating results analysis results three years ended december 31 1 production costs include lease operating costs production related taxes including ad valorem severance taxes 2 includes ceiling test charges restructuring charges asset impairments gains asset sales 3 transportation costs included operating expenses consolidated statements income 4 prices stated transportation costs year ended december 31 2004 compared year ended december 31 2003 ebit 2004 decreased 357 million compared 2003 despite eight percent increase natural gas prices including hedges experienced significant decrease operating revenues due lower production volumes result normal production declines asset sales lower capital spending program disappointing drilling results table lists significant variances operating results 2004 compared 2003 1 consists primarily changes transportation costs income operating revenues 2004 experienced significant decrease production volumes decline production volumes due normal production declines offshore gulf mexico texas gulf coast regions asset sales impact hurricanes gulf mexico lower capital expenditures disappointing drilling results declines partially offset increased natural gas production coal seam operations raton arkoma black warrior basins also increased oil production brazil result acquisition remaining interest unopaso july 2004 addition experienced higher average realized prices natural gas oil condensate ngl favorable impact hedging program hedging losses 18 million 2004 compared 44 million 2003 depreciation depletion amortization expense lower production volumes 2004 due production declines discussed reduced depreciation depletion amortization expense partially offsetting decrease higher depletion rates due higher finding development costs production costs 2004 experienced higher workover costs due implementation programs second half 2004 improve production offshore gulf mexico texas gulf coast regions also incurred higher utility expenses higher salt water disposal costs onshore region offsetting increases lower production taxes result higher tax credits taken 2004 high cost natural gas wells cost per unit increased due higher lease operating costs lower production volumes discussed general administrative expenses increased primarily due higher contract labor costs lower capitalized costs 2004 cost per unit increased due combination higher costs lower production volumes discussed year ended december 31 2003 compared year ended december 31 2002 ebit 2003 increased 283 million compared 2002 year ended december 31 2003 natural gas prices including hedges increased 61 percent however also experienced significant decrease production volumes result asset sales normal production declines mechanical failures several producing wells lower capital spending program disappointing drilling results table lists significant variances operating results 2003 compared 2002 1 consists primarily changes transportation costs income operating revenues 2003 experienced significant decrease production volumes due sale properties new mexico oklahoma texas colorado utah offshore gulf mexico normal production declines mechanical failures primarily texas gulf coast offshore gulf mexico regions lower capital spending program disappointing drilling results addition incurred unfavorable impact hedging program hedging losses 44 million 2003 compared 82 million hedging gains 2002 despite lower production unfavorable hedging results revenues higher due higher average realized prices natural gas oil condensate ngl 2003 depreciation depletion amortization expense lower volumes 2003 due production declines discussed reduced depreciation depletion amortization expense partially offsetting decrease higher depletion rates due higher finding development costs also recorded accretion expense related liabilities asset retirement obligations connection adoption sfas 143 2003 production costs 2003 experienced lower production costs primarily due asset sales discussed however also incurred higher production taxes 2003 result higher natural gas oil prices larger tax credits taken 2002 high cost natural gas wells cost per unit increased due higher production taxes lower production volumes ceiling test charges 2003 incurred impairment charge related nonfull cost pool assets 5 million net gains asset sales noncash ceiling test charges 5 million associated operations brazil 6 million employee severance costs 2002 incurred noncash ceiling test charge 3 million associated operations brazil general administrative expenses higher corporate overhead allocations lower capitalized costs main factors leading increase general administrative expenses 2003 cost per unit increased due combination higher costs lower production volumes discussed outlook 2005 based strategy develop balanced portfolio natural gas oil production allocate capital longer life slower decline projects development projects longer reserve life areas anticipate 2005 • total capital expenditure budget including acquisitions approximately 900 million • daily production volumes average excess 800 mmcfed • focus cost control operating efficiencies process improvements keep per unit cash operating costs 125 mmcfe 140 mmcfe • industrywide increases drilling costs oilfield service costs require constant monitoring capital spending programs nonregulated business marketing trading segment marketing trading segment’s operations focus marketing natural gas oil production management remaining trading portfolio past several years number significant events occurred business industry 2001 2002 • deterioration energy trading environment followed announcement november 2002 would reduce involvement energy marketing trading business pursue orderly liquidation trading portfolio 2003 2004 • challenging trading environment reduced liquidity lower credit standing industry participants general decline number trading counterparties • ongoing liquidation historical trading portfolio • announcement december 2003 would change operations primarily focus physical marketing natural gas oil produced production segment currently anticipate liquidate transactions trading portfolio end contract term may retain contracts either uneconomical sell terminate current environment due contractual terms credit concerns counterparty ii sale would require acceleration cash demands iii represent hedges associated activities reflected segments business including production power segments changes liquidation strategy may impact cash flows financial results segment marketing trading segment’s portfolio includes contracts third parties contracts affiliates require physical delivery commodity financial settlement following discussion significant types contracts used marketing trading segment impact financial results natural gas contracts productionrelated natural gas derivatives designated hedges enter contracts third parties primarily fixed floating swaps behalf production segment hedge anticipated natural gas production natural gas contracts consist obligations deliver natural gas fixed prices december 31 2004 contracts effectively hedged total 244 tbtu anticipated natural gas production 2012 total amount 84 percent contracts designated accounting hedges december 1 2004 contracts designated hedges production segment’s natural gas oil production accounted operating results segment productionrelated options contracts marked market results period accounting hedges provide price protection el paso natural gas price declines related natural gas production 2005 2006 entered fourth quarter 2004 contracts allow el paso achieve floor price 600 per mmbtu 60 tbtu natural gas production 2005 120 tbtu 2006 first quarter 2005 entered additional contracts provide el paso floor price 600 per mmbtu 30 tbtu natural gas production 2007 also capped us ceiling price 950 per mmbtu 60 tbtu natural gas production 2006 natural gas derivatives natural gas derivatives consist physical financial natural gas contracts impact earnings fair values contracts change contracts obligate us either purchase sell natural gas fixed prices exposure natural gas price changes vary period based whether overall purchase less natural gas sell contracts transportationrelated contracts transportation contracts provide us approximately 15 bcf pipeline capacity per day charged approximately 149 million annual demand charges contracts accrualbased contracts impact gross margin delivery service contracts occurs following table details transportation contracts historically contracts resulted significant losses el paso extent losses dependent upon ability utilize contracted pipeline capacity impacted • difference natural gas prices contractual receipt delivery locations • capital needed use capacity ie cash margins letters credit associated purchase sale natural gas use capacity • capacity required meet long term obligations storage contracts 2003 eliminated significant portion natural gas storage capacity contracts ongoing liquidation trading portfolio retained storage capacity 47 bcf tgp’s bear creek storage field enterprise products partners’ wilson storage facilities operational balancing purposes anticipate retained storage contracts significantly impact earnings future power contracts tolling contracts two tolling contracts supply fuel power plants receive power generated plants exchange right power generated pay demand charge ability recover demand charges primarily dependent upon difference cost fuel supply plant value power receive plant contract tolling contracts derivatives impact earnings fair value changes period largest tolling contract provides us approximately 548 mw generating capacity cordova power plant 2019 charged 27 million 32 million annual demand charges addition cordova power plant option repurchase 50 percent generating capacity us historically experienced significant volatility fair value tolling contract primarily due changes natural gas power prices market cordova serves expect volatility continue tolling contract provides us approximately 257 mw generating capacity alberta power pool third quarter 2005 expect charged 14 million demand charges 2005 contracts related power restructuring activities contracts consist longterm obligations provide power restructured power contracts power segment sale substantially restructured power contracts process eliminating substantially obligations exception contract morgan stanley related ucf contract calls us deliver 1700 mmwh per year 2016 fixed price may continue impact earnings future operating results overall operating results analysis results marketing trading segment three years ended december 31 substantial changes composition portfolio yeartoyear comparability affected 1 gross margin marketing trading segment consists revenues commodity trading origination activities less costs commodities sold including changes fair value derivative contracts overall 2004 2003 2002 experienced substantial losses gross margin trading contracts due number factors 2002 experienced losses natural gas power contracts result general market declines energy trading resulting lower price volatility natural gas power markets generally weaker trading credit environment also contributing deterioration market valuations trading marketing assets announcement fourth quarter 2002 many participants trading industry including us discontinue significantly reduce trading operations following announcement liquidated number positions earlier scheduled maturity caused us incur additional losses gross margin 2002 2003 held contracts maturity also experienced difficulty 2002 2003 collecting several claims various industry participants experiencing financial difficulty several sought bankruptcy protection settlements ongoing proceedings matters could impact future financial results listed discussion factors significant contract type affected profitability marketing trading segment three years ended december 31 2004 natural gas contracts productionrelated natural gas derivatives • derivatives designated hedges amounts table represent changes fair values derivative contracts designated accounting hedges production segment’s natural gas production december 1 2004 losses indicated result increases natural gas prices 2002 2003 2004 relative fixed prices contracts losses historically included financial results following designation accounting hedges future income impacts contracts reflected production segment however act designating contracts hedges impact el paso’s overall cash flows period • productionrelated options natural gas prices decreased fourth quarter 2004 fair value options entered 2004 increased contracts fair value 120 million december 31 2004 includes premium initially paid options gas prices remain option price 600 per mmbtu fair value contracts decrease term since would expire unexercised paid total net premium 64 million options additional option contracts entered first quarter 2005 • natural gas derivatives obligated purchase natural gas fixed price sold contracts 2003 2004 fair value contracts increased natural gas prices increased years 2002 incurred significant losses contracts lower price volatility deterioration energy trading environment described • early contract terminations amount includes 50 million gain recognized termination lng contract elba island facility 2004 transportationrelated contracts • fourth quarter 2002 began accounting transportation contracts accrualbased contracts adoption eitf issue 023 result 2002 results include demand charges accrual settlements recorded fourth quarter 2002 marktomarket losses contracts first nine months 2002 included change fair value natural gas derivatives annual demand charges contracts approximately 149 million 2004 156 million 2003 decrease 2004 due liquidation number positions prior original settlement dates • ability use alliance pipeline capacity contract relatively consistent 2003 2004 allowing us recover approximately 73 percent demand charges paid year resulted price differentials receipt delivery points staying relatively consistent years resulted ebit losses contract 15 million 2003 17 million 2004 texas intrastate transportation contracts incurred ebit losses 36 million 2003 26 million 2004 unable utilize significant portion capacity pipelines primarily due decrease price differentials south texas receipt points houston ship channel delivery locations contracts differences prices improve continue experience losses contracts storage contracts fourth quarter 2002 began accounting storage contracts accrualbased contracts adoption eitf issue 023 result 2002 results include demand charges accrual settlements recorded fourth quarter 2002 marktomarket losses contracts first nine months 2002 included change fair value natural gas derivatives annual demand charges contracts approximately 2 million 2004 21 million 2003 2002 2003 terminated significant number storage positions recognized 56 million gain 2002 31 million gain 2003 withdrawal sale gas held storage locations based actions remaining contracts wilson bear creek storage facilities significant impact future financial results segment power contracts cordova tolling agreement cordova agreement sensitive changes forecasted natural gas power prices 2003 forecasted power prices increased relative natural gas prices resulting significant increase fair value contract 2004 forecasted natural gas prices increased relative power prices resulting decrease fair value contract additionally although cordova power plant historically sold power relatively illiquid power market midwest power market incorporated liquid pennsylvanianew jerseymaryland power pool 2004 believe change reduce volatility fair value contract future power derivatives • historically many contract origination activities related power contracts changes energy trading environment change focus marketing trading segment activities substantially decreased 2002 2004 • ongoing liquidation trading book significantly impacted power contracts also recorded 25 million gain termination power contract power segment 2004 eliminated el paso’s consolidated results • first quarter 2005 assigned contracts supply power segment’s cedar brakes ii entities constellation energy commodities group inc recorded loss approximately 30 million fourth quarter 2004 upon signing assignment termination agreement contracts decreased fair value 64 million 67 million 48 million 2004 2003 2002 • first quarter 2002 recorded 80 million gain related power supply agreement entered power segment gain associated ucf restructured power contract eliminated el paso’s consolidated results later 2002 terminated contract entered new power supply agreement morgan stanley related ucf morgan stanley contract decreased fair value 72 million 77 million 58 million 2004 2003 2002 • remaining power contracts include used manage risk associated obligations supply power increased fair value 81 million 2004 48 million 2003 operating expenses operating expenses marketing trading segment decreased significantly year due primarily following • 2002 2003 recorded 487 million 26 million charges operating expenses related western energy settlement late 2003 obligation transferred corporate operations • 2003 2004 recorded 28 million 10 million bad debt expense associated fuel supply agreement berkshire power plant • result decision november 2002 reduce size trading portfolio experienced significant decline employee headcount resulted lower general administrative expenses 2003 decline headcount coupled closing london office 2003 contributed decreases general administrative expenses 2004 • overall cost reduction efforts corporate level reduced level operations resulted lower corporate overhead allocated us 2003 2004 nonregulated business power segment december 31 2004 power segment primarily consisted international power business historically segment also included domestic power plant operations domestic power contract restructuring business sold announced sale substantially domestic businesses ongoing focus within power segment maximize value assets brazil designated international power operations noncore activities expect exit activities future market conditions warrant international power plant operations brazil december 31 2004 brazilian operations include macae porto velho manaus rio negro araucaria power plants investments bolivia brazil argentina chile pipelines • macae power plant sells majority power wholesale brazilian power market macae also contract requires petrobras make minimum revenue payments august 2007 petrobras pay amounts due contract december 2004 january 2005 filed lawsuit arbitration discussion matter see part ii item 8 financial statements supplementary data note 17 future financial performance macae plant affected outcome dispute regional changes power markets • porto velho porto velho plant sells power eletronorte two power sales agreements expire 2010 2023 eletronorte absorbs substantially plant’s fuel costs purchases power plant able generate long plant operates within availability levels required contracts result profitability plant dependent primarily maintaining availability levels efficient operations maintenance practices availability levels expected decrease 2005 equipment failure plant 2004 expected repaired first quarter 2006 addition negotiating potential contractual amendments eletronorte may alter volumes prices power sold contracts may affect future earnings discussion negotiations see part ii item 8 financial statements supplementary data note 17 • manaus rio negro january 2005 signed new power sales contracts manaus rio negro power plants manaus energia new contracts manaus energia pay price power similar previous contracts addition manaus energia assume ownership manaus rio negro plants 2008 based ownership transfer contract terms deconsolidate plants first quarter 2005 begin account equity investments addition earnings assets decrease result new contracts • power sales contract araucaria power plant currently international arbitration due nonpayment utility purchases power plant result araucaria ceased operations 2003 discussion arbitration proceedings see part ii item 8 financial statements supplementary data note 17 two pipelines began operations 2003 generate income transportation natural gas various customers south america asia asian operations include interests 15 power plants 13 equity investments facilities sell electricity electrical generating capacity longterm power sales agreements local transmission distribution companies many government controlled majority contracts allow changes fuel costs passed customer power prices economic performance facilities impacted level electricity demand changes political regulatory environment countries serve well relative cost producing power recorded impairment assets 2004 connection decision sell assets international interests 10 power facilities located south central america europe equity investments facilities sell electricity electrical generating capacity longterm shortterm power sales agreements local transmission distribution companies well local spot markets economic performance facilities impacted fuel prices level demand electricity level competition power generators changes political regulatory environment countries serve relative cost producing power performance facilities central america also affected variances level rainfall region level rainfall increases level generation hydroelectric plants increases negatively impact power pricing spot market recently announced considering sale number assets although time actively marketed process progresses continue assess value assets may result impairments domestic power plant operations domestic operations december 31 2004 primarily consist equity ownership natural gasfired power plant midland cogeneration venture mcv price electricity sold mcv indexed coal plant fueled natural gas purchases longterm contracts spot market changes relationship coal natural gas prices directly impact economic performance facility 2004 recorded impairment interest plant based decline value investment considered temporary 2004 first quarter 2005 sold interests 33 domestic power plants sales incurred substantial impairments 2003 2004 result sales substantially lower earnings power segment domestic power contract restructuring business 2002 2003 maintained completed several contract restructuring transactions largest ucf 2004 completed sale ucf related restructured power contract entered agreement sell ownership cedar brakes ii related restructured power contracts december 31 2004 held interest mohawk river funding ii cedar brakes ii completed sale cedar brakes ii first quarter 2005 evaluating potential buyers mohawk river funding ii operating results overall operating results analysis activities within power segment three years ended december 31 substantial changes business periods affected yeartoyear comparability 1 gross margin power segment consists revenues power plants initial net gains losses incurred connection restructuring power contracts well subsequent revenues cost electricity purchases changes fair value contracts cost fuel used power generation process included operating expenses 2 consists indirect expenses general administrative costs associated domestic international operations including legal finance engineering costs direct general administrative expenses domestic international operations included ebit operations international power following table shows significant factors impacting ebit international power business 2004 2003 2002 brazil 2002 2003 completed construction several power plants pipelines allowed reach full operational capacity however financial results three years ended december 31 2004 impacted significantly regional economic political conditions affected renegotiation several power contracts brazilian power plants discussion significant assets brazil macae porto velho first quarter 2003 conducted majority power plant operations brazil gemstone unconsolidated joint venture april 2003 acquired joint venture partner’s interest gemstone began consolidating gemstone’s debt interests macae porto velho power plants result operating results 2002 first quarter 2003 include equity earnings earned gemstone consolidated operating results periods 2003 2004 include revenues expenses equity earnings gemstone’s assets ebit earned macae plant’s operations 172 million 156 million 136 million 2004 2003 2002 increase 2003 primarily due macae reaching full operational capacity third quarter 2002 addition consolidation gemstone described improved ebit 2003 2004 since interest taxes incurred gemstone longer included ebit earned porto velho plant’s operations 28 million 28 million 23 million 2004 2003 2002 increase 2003 primarily due porto velho reaching full operational capacity mid2003 fourth quarter 2004 porto velho plant experienced equipment failure expected temporarily reduce output plant approximately 30 percent equipment failure expected repaired first quarter 2006 combined net exposure macae porto velho plants approximately 08 billion december 31 2004 currently negotiations porto velho contracts eletronorte dispute petrobras macae contract negotiations disputes progress possible impairments assets may occur impairments may significant discussion negotiations disputes see part ii item 8 financial statements supplementary data note 17 manaus rio negro 2003 began negotiating extension manaus rio negro power contracts expire 2005 2006 based status negotiations extend contracts negatively impacted changes brazilian political environment 2004 recorded 167 million impairment investment manaus rio negro 2004 completed extension contracts first quarter 2005 manaus rio negro plants earnings plant operations 30 million 2004 12 million 2003 18 million 2002 south american pipelines ebit brazilian operations includes ebit earned bolivia brazil argentina chile pipelines amount 28 million 2004 18 million 2003 ebit earned pipelines significant 2002 increases three year period primarily due bolivia brazil pipeline reaching full operational capacity third quarter 2003 asia fourth quarter 2004 recorded 212 million charge asian power assets connection decision pursue sale assets impairment amounts based estimates fair value projects 2005 engaged financial advisor assist us sale assets first quarter 2005 sold investment ppn power facility india 20 million impaired plant 2002 primarily regional political economic events time sales process continues continue update fair value asian assets may result impairments 2002 2004 earnings asian power assets relatively stable underlying plants maintained steady levels availability production higher fuel costs periods materially impact plants’ operations substantially higher fuel costs passed power purchasers higher contracted power prices however three year period several significant events occurred improved financial performance assets including • conversion two chinese power plants heavy fuel oil natural gas lowered production costs facilities • issuance debt meizhou wan plant 2004 reduced liquidity concerns plant’s operation plant partially impaired 2002 based concerns • favorable completion negotiations philippine regulators fuel power prices east asia plants • closing singapore office 2002 lowered operating expenses international earnings international operations decreased 2002 2004 due primarily economic difficulties countries serve well specific transactions affected profitability underlying plants major factors contributing decreases • dominican republic economic crisis dominican republic 2002 2003 significantly reduced amount power generated impacted ability collect receivables power plants country 2003 2004 dominican republic’s economy began improve late 2004 following election new president see part ii item 8 financial statements supplementary data note 22 discussion investments dominican republic • el salvador 2002 restructured power contract el salvador power facility resulted 77 million gain 2002 restructuring converted plant merchant facility sells power shortterm contracts open market result power resulting earnings generated plant 2002 higher 2003 2004 • argentina 2002 impaired investment argentina based new legislation resulting economic crisis argentina sold plants 2003 attempting recover portion losses international arbitration • international operations also sensitive changes local demand power cost fuel run power facilities power plant england benefited increases demand power prices 2004 largely offset higher fuel prices central american power plants part long term business strategy considering sale number international power assets sales occur andor market indicators fair value become available possible impairments assets may occur impairments may significant domestic power following table shows significant factors impacting ebit within domestic power business 2004 2003 2002 1 2004 2003 recorded 60 million 105 million operating income generated power plants chaparral equity investment consolidated effective january 1 2003 prior january 2003 recorded earnings chaparral power plants equity earnings management fees received approximately 124 million 2002 mcv power plant natural gasfired plant sells power contracted price indexed coal prices 2004 mcv experienced reduced ebit primarily natural gas prices increased faster rate coal prices decrease ebit magnified increase volume power mcv required generate january 2005 mcv received regulatory approval reduce required level power generation fourth quarter 2004 impaired investment mcv based decline value investment due increased fuel costs continue assess ability recover investment mcv related operations future assets sold 2005 three years ended december 31 2004 recorded significant impairments domestic power business discussed • 2004 2003 2002 incurred approximately 105 million 208 million 89 million asset impairments net realized gains losses domestic power business based anticipated sale assets well operational contractual issues several facilities 2004 amounts included 81 million related impairing earnings assets held sale addition 24 million impairments net gains losses longlived assets related held sale merchant contracted plants also incurred 25 million loss termination power contract marketing trading segment related one assets sold reflected 2004 earnings plant operations • 2003 also • recorded impairment chaparral investment 207 million based decline investment’s value considered temporary see part ii item 8 financial statements supplementary data notes 2 3 22 discussion matters • wroteoff receivable 88 million milford power llc related transfer interest milford power llc lenders continued difficulties facility domestic power contract restructuring following table shows significant factors impacting ebit within domestic power contract restructuring activities 2004 2003 2002 restructured several abovemarket longterm power sales contracts regulated utilities originally tied older power plants contracts amended power sold utilities required delivered specified power generation plant could obtained wholesale power market result credit rating downgrades economic changes power market longer pursuing additional power contract restructuring activities exiting activities reduce ebit future periods discussion power restructuring activities see part ii item 8 financial statements supplementary data note 10 restructuring gain 2002 restructured power sales contracts eagle point power facility also known ucf mount carmel power plant resulted combined net gains 501 million net minority interest prior restructuring contracts power plants’ power purchase contracts accounted using accrual accounting following restructuring power purchase agreements accounted derivatives recorded fair value resulting net gain date contracts restructured conjunction ucf restructuring 2002 paid 90 million contract termination fee terminate steam contract eagle point power plant eagle point refinery recorded 80 million loss power supply agreement entered marketing trading segment 90 million 80 million losses eliminated el paso’s consolidated results sale ucf cedar brakes ii 2004 sold ucf march 2005 sold cedar brakes ii sales resulted impairments cedar brakes ii entities ucf 2004 nonregulated business field services segment field services segment conducts remaining midstream activities primarily include gathering processing assets south louisiana 2002 2003 2004 held significant general limited partner interests gulfterra enterprise december 2003 january 2005 sold general limited partner interests gulfterra enterprise south texas processing plants interests indian springs natural gas gathering processing assets enterprise series transactions described part ii item 8 financial statements supplementary data note 22 2003 2004 primary source earnings field services segment interests gulfterra enterprise sale interests gulfterra 2003 2004 recognized significant gains well goodwill impairment 480 million prior sale interests gulfterra also received management fees agreement provide operational administrative services partnership addition received reimbursements costs paid directly us gulfterra’s behalf twelve months ended december 31 2004 2003 2002 received approximately 71 million 91 million 60 million management fees cost reimbursements result sale general limited partnership interests september 2004 longer receive management fees result sale remaining interest january 2005 longer recognize equity earnings related investments significant remaining obligations enterprise provide estimated 45 million payments enterprise next three years provide reimbursement portion enterprise’s future pipeline integrity costs related assets sold us gulfterra 2002 recorded 74 million liability 2003 result regulatory changes relating pipeline integrity subsequent negotiations enterprise reduced estimated obligation enterprise approximately 9 million fourth quarter 2004 addition provide reimbursement portion gulfterra’s maintenance expenses certain previously sold assets recorded estimated liability charge operating expenses 8 million 2004 discussion indemnification agreements see part ii item 8 financial statements supplementary data note 17 2004 earnings cash distributions received gulfterra enterprise follows operating results analysis results field services segment three years ended december 31 1 gross margins consist operating revenues less cost products sold believe measurement meaningful understanding analyzing field services segment’s operating results commodity costs play significant role determination profit midstream activities summary significant factors related discussions affecting ebit three years ended december 31 gathering processing activities three years ended december 31 2004 experienced decrease gross margin corresponding decrease operation maintenance expenses primarily result asset sales additionally gathering processing margins periods impacted spread ngl prices natural gas prices spreads increase generally increase ngl volumes extract affects margin 2003 margins negatively impacted decrease spreads natural gas prices relative ngl prices increased also caused us reduce amount ngl extracted compared 2002 however 2004 margins positively impacted increase spreads ngl prices recovered also caused us increase amount ngl extracted natural gas processing facilities south texas addition margin attributable marketing ngl increased 2004 result lower fuel transportation costs future margins remaining assets remain sensitive spread natural gas pricing ngl pricing gulfterra enterprise related items 2002 2003 sold substantial amount assets gulfterra decreased gross margin operating expenses time increasing equity earnings general limited partner interests gulfterra listed significant transactions gulfterra • 2002 gain sale texas new mexico gathering pipeline assets san juan gathering assets • 2003 release chaco lease obligation return communication assets clarification obligation provide pipeline integrity costs 2006 december 2003 january 2005 entered series transactions enterprise sold interests gulfterra december 2003 sold 50 percent interest gulfterra enterprise recorded gain sale income time recorded impairment south texas assets operating expenses based planned sale assets enterprise 2004 september 2004 completed sale remaining 50 percent interest general partner gulfterra enterprise recorded gain sale income result substantial reduction asset base primarily sales enterprise recorded impairment operating expenses entire amount goodwill upon determination goodwill segment longer recoverable finally end 2004 entered negotiations sell indian springs assets enterprise recorded impairment charge operating expenses assets based planned sale 2005 completed sale indian springs assets january 2005 also sold remaining general limited partnership interests enterprise 425 million january 2005 asset sales 2002 recorded impairment operating expenses north louisiana assets based planned sale completed 2003 recorded impairment income investment dauphin island gathering system mobile bay processing plant based planned sale investments sold investments august 2004 corporate expenses net corporate operations include general administrative functions well telecommunications business petroleum ship charter operations various contracts assets including financial services lng related items immaterial results following table presents items impacting ebit corporate operations years ended december 31 number pending litigation matters including shareholder lawsuits filed us 2004 incurred additional legal costs related changes estimated reserves existing legal matters changes based ongoing assessments developments evaluations possible outcomes matters also incurred accretion expense related western energy settlement western energy settlement accrual assumes make payments claimants 2023 retire obligation earlier period could incur additional charges finally 2004 increased insurance reserves approximately 30 million accrual related decision withdraw mutual insurance company member accrual additional premiums another legal insurance matters evaluate suit claim merits defenses adverse rulings us andor unfavorable settlements related legal matters would impact future results discussed part ii item 8 financial statements supplementary information note 4 accrued 80 million 2004 related consolidation houstonbased operations estimated relocation costs based discounted liability includes estimates future sublease rentals earnings future periods impacted extent actual sublease rentals differ estimates accretion discounted liability estimated approximately 8 million 2005 total estimates sublease rentals vacated space subleased december 31 2004 excluded calculations discounted liability would approximately 121 million versus amount recorded 2005 unable collect estimated sublease rentals included accrual could incur additional 3 million rental expense also pursuing sale telecommunications facility chicago sales process progresses continue assess value facility may result impairment interest debt expense analysis interest debt expense three years ended december 31 millions year ended december 31 2004 compared year ended december 31 2003 2004 total interest debt expense decreased primarily due retirements longterm debt financing obligations net issuances 2003 2004 also paid 850 million borrowings previous 3 billion revolving credit facility however repayments offset 125 billion borrowed new 3 billion credit agreement entered november 2004 related charges fees incurred entering new credit agreement year ended december 31 2003 compared year ended december 31 2002 2003 total interest debt expense increased compared 2002 issued additional debt securities consolidated various financing obligations including associated chaparral gemstone lakeside also reclassified certain preferred securities longterm debt finally interest expense revolving credit facilities increased 2003 additional borrowings 2003 compared 2002 distributions preferred interests consolidated subsidiaries distributions preferred securities decreased significantly 2002 2004 period redeemed number obligations including related clydesdale trinity river coastal securities financing arrangements also reclassified coastal finance capital trust mandatorily redeemable securities longterm debt upon adoption sfas 150 2003 began recording distributions securities interest expense remaining preferred interests december 31 2004 consists 300 million 825 preferred stock consolidated subsidiary el paso tennessee pipeline co discussion borrowings financing activities related consolidated subsidiaries see part ii item 8 financial statements supplementary data notes 15 16 income taxes income taxes years ended december 31 2004 2003 2002 25 million 551 million 641 million resulting effective tax rates 3 percent 51 percent 34 percent differences effective tax rates statutory tax rate 35 percent primarily result following factors • state income taxes net federal income tax effect • earningslosses unconsolidated affiliates anticipate receiving dividends • foreign income taxed different rates • abandonments sales foreign investments • valuation allowances • nondeductible dividends preferred stock subsidiaries • nonconventional fuel tax credits • nondeductible goodwill impairments reconciliation statutory rate effective tax rate well matters could impact future tax expense see part ii item 8 financial statements supplementary data note 7 2004 overall effective tax rate continuing operations significantly different statutory rate due primarily gulfterra transactions impairments certain foreign investments sale interests gulfterra associated merger gulfterra enterprise september 2004 resulted significant net taxable gain compared lower book gain significant tax expense due nondeductibility significant portion goodwill written result transaction impact nondeductible goodwill increased tax expense 2004 approximately 139 million see part ii item 8 financial statements supplementary data note 22 discussion merger related transactions additionally received us federal income tax benefit impairment certain foreign investments effective tax rate 2004 absent items would 32 percent 2003 overall effective tax rate continuing operations significantly different statutory rate due primarily 124 million tax benefits related abandonments sales certain foreign investments effective tax rate 2003 absent tax benefits would 40 percent 2004 congress proposed failed enact legislation would disallow deductions certain settlements made behalf governmental entities possible congress reintroduce similar legislation 2005 enacted tax legislation could impact deductibility western energy settlement could result writeoff associated tax benefits event tax expense would increase total tax benefits related western energy settlement approximately 400 million december 31 2004 october 2004 american jobs creation act 2004 signed law legislation creates among things temporary incentive us multinational companies repatriate accumulated income earned outside us effective tax rate 525 us treasury department issued final guidelines applying repatriation provisions american jobs creation act provided us deferred taxes foreign earnings intended indefinitely reinvested outside us currently evaluating whether repatriate foreign earnings american jobs creation act evaluating provisions legislation may impact taxes future part longterm business strategy anticipate sell asian power investments discussed part ii item 8 financial statements supplementary data note 7 historically recorded united states deferred taxes book versus tax basis differences investments historical intent indefinitely reinvest earnings projects outside united states 2004 intent assets changed intend use proceeds sale within us result recorded us deferred tax liabilities instances book basis investment exceeded tax basis 2004 time however due uncertainties manner timing approval sale transactions recorded us deferred tax assets instances tax basis investment exceeded book basis except instances believe realization asset assured uncertainties become known record additional tax effects reflect ultimate sale transactions amounts could significant impact future recorded tax amounts effective tax rates periods number pending irs audits income tax contingencies various stages completion discussed part ii item 8 financial statements supplementary data note 7 provided reserves matters based best estimate ultimate outcome matter audits finalized contingencies resolved adjust estimates impact could material effect recorded amount income taxes effective tax rates periods discontinued operations year ended december 2004 loss discontinued operations 146 million compared loss 1396 million 2003 2004 76 million losses discontinued operations related canadian certain international production operations primarily losses sales impairment charges 70 million petroleum markets activities primarily related losses completed sales eagle point aruba refineries along operational severance costs losses 2003 related primarily impairment charges aruba eagle point refineries chemical assets result decision exit sell businesses ceiling test charges related canadian production operations loss 2002 primarily due operating losses aruba refinery impairment charges mtbe chemical plant coal mining operations ceiling test charges related canadian production operations commitments contingencies discussion commitments contingencies see part ii item 8 financial statements supplementary data note 17 incorporated herein reference critical accounting policies critical accounting policies accounting policies involve use complicated processes assumptions andor judgments preparation financial statements discussed development selection critical accounting policies related disclosures audit committee board directors identified following critical accounting policies current year price risk management activities record derivative instruments used price risk management activities fair values balance sheet estimate fair value derivative instruments using exchange prices thirdparty pricing data valuation techniques incorporate specific contractual terms statistical simulation analysis present value concepts one primary assumptions used estimate fair value derivative instruments pricing assumptions based upon price curves derived actual prices observed market pricing information supplied thirdparty valuation specialist independent pricing sources models rely forward pricing information table presents hypothetical sensitivity commoditybased price risk management activities changes fair values arising immediate selected potential changes quoted market prices significant assumptions use determining fair value derivative instruments related time value anticipated market liquidity credit risk counterparties assumptions methodologies use determine fair values derivatives may differ used derivative counterparties differences significant could impact future operating results settle derivative positions accounting natural gas oil producing activities natural gas oil reserves estimates underlie many accounting estimates financial statements discussed process estimating natural gas oil reserves particularly proved undeveloped proved nonproducing reserves complex requiring significant judgment evaluation available geological geophysical engineering economic data accordingly reserve estimates developed internally reserve reporting group separate operations group reviewed internal committees internal auditors addition third party engineering firm appointed reports audit committee board directors prepares independent estimate significant portion proved reserves december 31 2004 total proved reserves 29 percent undeveloped 13 percent developed nonproducing addition data given field may also change substantially time result numerous factors including additional development activity evolving production history continual reassessment viability production changing economic conditions result material revisions existing reserve estimates occur time addition subjective decisions variances available data various fields increases likelihood significant changes estimates proved natural gas oil reserves primarily impact property plant equipment amounts balance sheets depreciation depletion amortization amounts income statements among items use full cost method account natural gas oil producing activities accounting method capitalize substantially costs incurred connection acquisition development exploration natural gas oil reserves full cost pools maintained geographic areas regardless whether reserves actually discovered record depletion expense capitalized amounts life proved reserves based unit production method factors held constant 10 percent increase estimated proved reserves would decrease unit production depletion rate 9 percent 10 percent decrease estimated proved reserves would increase unit depletion rate 11 percent full cost accounting method required conduct quarterly impairment tests capitalized costs full cost pools impairment test referred ceiling test total capitalized costs net related income tax effects limited ceiling based present value future net revenues proved reserves using end period spot prices discounted 10 percent plus lower cost fair market value unproved properties net related income tax effects discounted revenues greater equal total capitalized costs required writedown capitalized costs level ceiling test calculations include effect derivative instruments designated qualify hedges anticipated natural gas oil production result higher proved reserves reduce likelihood ceiling test impairments recorded ceiling test charges continuing discontinued operations 35 million 76 million 128 million 2004 2003 2002 ceiling test calculation assumes price effect last day quarter held constant life reserves even though actual prices natural gas oil volatile change period decline commodity prices impact results ceiling test may result writedowns decrease commodity prices 10 percent price levels december 31 2004 would resulted ceiling test charge 2004 asset impairments asset impairment accounting rules require us continually monitor businesses business environment determine event occurred indicating longlived asset investment may impaired event occurs determination involves judgment assess expected future cash flows compare carrying value asset group evaluated process also involves judgment ultimately arrive fair value asset determined combination estimating proceeds sale asset less anticipated selling costs intend sell asset discounted estimated cash flows asset based current anticipated future market conditions intend hold asset assessment project level cash flows requires us make projections assumptions many years future pricing demand competition operating costs legal regulatory issues factors variables often differ estimates changes either positive negative impact impairment estimates recorded impairments longlived assets 11 billion 791 million 440 million years ended december 31 2004 2003 2002 impairments unconsolidated affiliates 397 million 449 million 566 million years ended december 31 2004 2003 2002 recorded impairments discontinued operations 9 million 15 billion 290 million years ended december 31 2004 2003 2002 future changes economic business environment impact assessments potential impairments accounting environmental reserves accrue environmental reserves assessments indicate probable liability incurred asset recovered amount reasonably estimated estimates liabilities based currently available facts existing technology presently enacted laws regulations taking consideration likely effects societal economic factors include estimates associated onsite offsite groundwater technical studies legal costs actual results may differ estimates often revised future either negatively positively depending upon actual outcomes changes expectations based facts surrounding exposure december 31 2004 accrued approximately 380 million environmental matters reserve estimates range approximately 380 million approximately 547 million accrual represents combination two estimation methodologies first likely outcome reasonably estimated cost accrued 82 million second likely outcome cannot estimated range costs established 298 million 465 million lower end range accrued accounting pension postretirement benefits december 31 2004 956 million pension asset 274 million postretirement benefit liability reflected assets liabilities balance sheet related pension postretirement benefit plans amounts primarily based actuarial calculations include assumptions including related return expect earn plan assets discount rates used calculating benefit obligations rate expect compensation employees increase plan term estimated cost health care benefits provided plans factors actual results may differ assumptions included calculations result estimates associated pension postretirement benefits often revised future income statement impact changes assumptions related benefit obligations generally deferred amortized income life plans cumulative amount deferred december 31 2004 recorded 800 million increase pension asset 32 million reduction postretirement liability following table shows impact one percent change primary assumptions used actuarial calculations associated pension postretirement benefits year ended december 31 2004 millions 1 actual return plan assets one percent lower expected return plan assets expected cash contributions pension postretirement benefit plans would significantly change discount rate assumptions reflect rates return investments expect use settle pension postretirement obligations future combined current expected rates return investment grade corporate bonds develop discount rates used benefit expense obligation estimates september 30 2004 estimates net benefit expense income partially based expected return pension plan assets use marketrelated value plan assets determine expected return pension plan assets determining marketrelated value plan assets differences expected actual asset returns deferred recognized three years used fair value plan assets instead marketrelated value plan assets determining expected return pension plan assets net benefit expense would 14 million higher year ended december 31 2004 recorded additional pension liability primary pension plan fair value assets plan exceeded accumulated benefit obligation plan approximately 262 million 366 million september 30 2004 december 31 2004 accumulated benefit obligation exceeded plan assets primary pension plan september 30 2004 would recorded pretax additional pension liability approximately 960 million plus amount equal excess accumulated benefit obligation plan assets plan would also recorded amount equal additional pension liability accumulated comprehensive loss net taxes balance sheet new accounting pronouncements issued yet adopted see part ii item 8 financial statements supplementary data note 1 new accounting pronouncements issued yet adopted incorporated herein reference risk factors cautionary statement purposes “safe harbor” provisions private securities litigation reform act report contains incorporates reference forwardlooking statements within meaning private securities litigation reform act 1995 forwardlooking statement includes statement assumptions bases underlying forwardlooking statement caution believe assumptions bases reasonable good faith assumed facts bases almost always vary actual results differences assumed facts bases actual results material depending upon circumstances forwardlooking statement management express expectation belief future results expectation belief expressed good faith believed reasonable basis cannot assure however statement expectation belief result achieved accomplished words “believe” “expect” “estimate” “anticipate” similar expressions generally identify forwardlooking statements forwardlooking statements whether written oral expressly qualified cautionary statements cautionary statements may accompany forwardlooking statements addition disclaim obligation update forwardlooking statements reflect events circumstances date report mind consider risks discussed elsewhere report documents file sec time following important factors could cause actual results differ materially expressed forwardlooking statement made us behalf risks related business operations subject operational hazards uninsured risks operations subject inherent risks normally associated operations including pipeline ruptures explosions pollution release toxic substances fires adverse weather conditions hazards could result damage destruction facilities damages persons property addition operations face possible risks associated acts aggression domestic foreign assets events occur could suffer substantial losses maintain insurance many risks extent amounts believe reasonable financial condition operations could adversely affected significant event occurs fully covered insurance success pipeline business depends part factors beyond control natural gas natural gas liquids transport store owned third parties result volume natural gas natural gas liquids involved activities depends actions third parties beyond control following factors beyond control may unfavorably impact ability maintain increase current throughput renegotiate existing contracts expire remarket unsubscribed capacity pipeline systems • service area competition • expiration andor turn back significant contracts • changes regulation action regulatory bodies • future weather conditions • price competition • drilling activity availability natural gas supplies • decreased availability conventional gas supply sources availability timing gas supply sources lng • increased availability popularity alternative energy sources hydroelectric power • increased cost capital • opposition energy infrastructure development especially environmentally sensitive areas • adverse general economic conditions • expiration andor renewal existing interests real property including real property native american lands • unfavorable movements natural gas liquids prices revenues pipeline businesses generated contracts must renegotiated periodically substantially pipeline subsidiaries’ revenues generated contracts expire periodically must renegotiated extended replaced cannot assure able extend replace contracts expire terms renegotiated contracts favorable existing contracts particular ability extend andor replace contracts could adversely affected factors cannot control including • competition pipelines including proposed construction companies additional pipeline capacity lng terminals markets served interstate pipelines • changes state regulation local distribution companies may cause negotiate shortterm contracts turn back capacity contracts expire • reduced demand market conditions areas serve • availability alternative energy sources gas supply points • regulatory actions unable renew extend replace contracts renew less favorable terms may suffer material reduction revenues earnings cash flows fluctuations energy commodity prices could adversely affect pipeline businesses revenues generated transmission storage processing contracts depend volumes rates affected prices natural gas natural gas liquids increased prices could result reduction volumes transported customers power companies depending price fuel may dispatch gasfired power plants increased prices could also result industrial plant shutdowns load losses competitive fuels well local distribution companies’ loss customer base also experience earnings volatility amount gas utilized operations differs amounts receive purpose success transmission storage processing operations subject continued development additional oil natural gas reserves ability access additional suppliers interconnecting pipelines offset natural decline existing wells connected systems decline energy prices could precipitate decrease development activities could cause decrease volume reserves available transmission storage processing systems facilities retain fixed percentage natural gas transported use fuel replace lost unaccounted gas risk difference retained amount actual gas consumed lost unaccounted pricing volatility may also impact value recoveries retained gas natural gas prices supply basins connected pipeline systems higher delivered basis offsystem markets delivered prices natural gas producing regions ability compete transporters may negatively impacted fluctuations energy prices caused number factors including • regional domestic international supply demand • availability adequacy transportation facilities • energy legislation • federal state taxes sale transportation natural gas natural gas liquids • abundance supplies alternative energy sources • political unrest among oil producing countries natural gas oil prices volatile substantial decrease natural gas oil prices could adversely affect financial results exploration production business future financial condition revenues results operations cash flows future rate growth depend primarily upon prices receive natural gas oil production natural gas oil prices historically volatile likely continue volatile future especially given current world geopolitical conditions prices natural gas oil subject variety additional factors beyond control factors include • level consumer demand supply natural gas oil • commodity processing gathering transportation availability • level imports price foreign natural gas oil • ability members organization petroleum exporting countries agree maintain oil price production controls • domestic governmental regulations taxes • price availability alternative fuel sources • availability pipeline capacity • weather conditions • market uncertainty • political conditions hostilities natural gas oil producing regions • worldwide economic conditions • decreased demand use natural gas oil market concerns global warming changes governmental policies regulations due climate change initiatives approximately 82 percent proved reserves december 31 2004 natural gas reserves substantially sensitive changes natural gas prices changes oil prices declines natural gas oil prices would reduce revenue could reduce amount natural gas oil produce economically result could adversely affect financial results production business changes natural gas oil prices significant impact calculation full cost ceiling test significant decline natural gas oil prices could result downward revision reserves writedown carrying value natural gas oil properties could substantial would negatively impact net income stockholders’ equity success natural gas oil exploration production businesses dependent part factors beyond control addition prices performance natural gas oil exploration production businesses dependent part upon number factors cannot control including • results future drilling activity • ability identify precisely locate prospective geologic structures drill successfully complete wells structures timely manner • ability expand leased land positions desirable areas often subject intensely competitive conditions • increased competition search acquisition reserves • future drilling production development costs including drilling rig rates oil field services costs • future tax policies rates drilling production incentives state federal foreign governments • increased federal state regulations including environmental regulations limit restrict ability drill natural gas oil wells reduce operational flexibility increase capital operating costs • decreased demand use natural gas oil market concerns global warming changes governmental policies regulations due climate change initiatives • declines production volumes including gulf mexico • continued access sufficient capital fund drilling programs develop replace reserve base rapid depletion characteristics natural gas oil drilling producing operations involve many risks may profitable operations subject risks normally incident operation development natural gas oil properties drilling natural gas oil wells including well blowouts cratering explosions pipe failure fires formations abnormal pressures uncontrollable flows natural gas oil brine well fluids release contaminants environment environmental hazards risks nature risks liabilities could exceed insurance policy limits case environmental fines penalties cannot insured result could incur substantial costs could adversely affect future results operations cash flows financial condition addition drilling operations subject risk encounter commercially productive reservoirs new wells drilled us may productive may recover portion investment wells drilling natural gas oil unprofitable dry holes wells productive may produce sufficient net reserves return profit realized prices deducting drilling operating costs estimating reserves production future net cash flow difficult estimating quantities proved natural gas oil reserves complex process involves significant interpretations assumptions requires interpretations available technical data various estimates including estimates based upon assumptions relating economic factors future commodity prices production costs severance excise taxes capital expenditures workover remedial costs assumed effect governmental regulation result reserve estimates inherently imprecise also use 10 percent discount factor estimating value reserves prescribed sec may necessarily represent appropriate discount factor given actual interest rates risks production business natural gas oil industry general subject significant variations interpretations assumptions used estimates changes conditions could cause estimated quantities net present value reserves differ materially reserve data represents estimate assume present values referred report represent current market value estimated natural gas oil reserves timing production expenses development production natural gas oil properties affect timing actual future net cash flows proved reserves present value changes present value reserves could cause writedown carrying value natural gas oil properties could substantial would negatively affect net income stockholders’ equity december 31 2004 approximately 29 percent estimated proved reserves undeveloped recovery undeveloped reserves requires significant capital expenditures successful drilling operations reserve data assumes make expenditures conduct operations successfully future events including commodity price changes may cause assumptions change addition estimates proved undeveloped reserves proved nonproducing reserves subject greater uncertainties estimates proved producing reserves success power activities depends part many factors beyond control success remaining domestic international power projects could adversely affected factors beyond control including • alternative sources supplies energy becoming available due new technologies interest self generation cogeneration • increases costs generation including increases fuel costs • uncertain regulatory conditions resulting ongoing deregulation electric industry united states foreign jurisdictions • ability negotiate successfully enter advantageous power purchase supply agreements • possibility reduction projected rate growth electricity usage result factors regional economic conditions excessive reserve margins implementation conservation programs • risks incidental operation maintenance power generation facilities • inability customers pay amounts owed power purchase agreements • increasing price volatility due deregulation changes commodity trading practices • overcapacity generation markets served power plants interest use derivative financial instruments could result financial losses subsidiaries use futures swaps option contracts traded new york mercantile exchange overthecounter options price basis swaps natural gas merchants financial institutions extent positions designated qualify hedges changes commodity prices interest rates volatility correlation factors liquidity market could cause revenues net income cash requirements volatile could incur financial losses future result volatility market values energy commodities trade one counterparties fails perform contract valuation financial instruments involves estimates changes assumptions underlying estimates occur changing valuation instruments potentially resulting financial losses extent hedge commodity price exposure interest rate exposure forego benefits would otherwise experience commodity prices increase interest rates change use derivatives also requires posting cash collateral counterparties impact working capital current assets liabilities commodity prices interest rates change additional information concerning derivative financial instruments see item 7a quantitative qualitative disclosures market risk part ii item 8 financial statements supplementary data note 10 businesses subject risk payment defaults counterparties frequently extend credit counterparties following performance credit analysis despite performing analysis exposed risk may able collect amounts owed us although many cases collateral secure counterparty’s performance could inadequate could suffer credit losses foreign operations investments involve special risks activities areas outside united states including material investment exposure power pipeline production projects brazil pakistan subject risks inherent foreign operations including • loss revenue property equipment result hazards expropriation nationalization wars insurrection political risks • effects currency fluctuations exchange controls devaluation foreign currencies economic problems • changes laws regulations policies foreign governments including associated changes governing parties retained liabilities associated businesses sold could exceed estimates sold significant number assets years including sale many assets since 2001 pursuant various purchase sale agreements relating businesses assets divested either retained certain liabilities indemnified certain purchasers liabilities might incur future liabilities many cases relate breaches warranties environmental tax litigation personal injury representations provided although believe established appropriate reserves liabilities could required accrue additional reserves future amounts could material addition exit businesses experienced substantial reductions turnover workforce previously supported ownership operation assets risk reductions turnover workforce could result errors mistakes managing businesses exiting prior closing also risk reductions could result errors mistakes managing retained liabilities closing including lack historical knowledge regard assets businesses managing liabilities defending associated litigation risks related legal regulatory matters ongoing litigation investigations related financial statements associated reserve estimates hedges could significantly adversely affect business 2004 restated historical financial statements result downward revision natural gas oil reserves manner applied accounting rules related many historical hedges primarily associated hedges anticipated natural gas production result reduction reserve estimates several class action lawsuits filed us several subsidiaries reserve revisions also subject investigations sec us attorney hedging matters also subject investigation us attorney may become subject separate inquiry sec could result significant fines us investigations lawsuits possible future claims based facts may negatively impact credit ratings place demands liquidity cannot provide assurance time effects results investigations class action lawsuits material financial conditions results operations liquidity agencies regulate pipeline businesses customers affect profitability pipeline businesses regulated ferc us department transportation various state local regulatory agencies regulatory actions taken agencies potential adversely affect profitability particular ferc regulates rates pipelines permitted charge customers services setting authorized rates return recent ferc decisions ferc utilized proxy group companies includes local distribution companies faced much competition risks interstate pipelines inclusion companies creates downward pressure approved tariff rates pipelines’ tariff rates reduced future proceeding pipelines’ volume business currently permitted rates decreased significantly pipelines required substantially discount rates services competition regulatory pressure profitability pipeline businesses could reduced addition increased regulatory requirements relating integrity pipelines requires additional spending order maintain compliance requirements additional requirements enacted could significantly increase amount expenditures state agencies regulate pipelines’ local distribution company customers could impose requirements could impact demand pipelines’ services costs environmental liabilities regulations litigation could exceed estimates operations subject various environmental laws regulations laws regulations obligate us install maintain pollution controls clean various sites regulated materials may disposed released sites designated superfund sites epa comprehensive environmental response compensation liability act also party legal proceedings involving environmental matters pending various courts agencies compliance environmental laws regulations require significant costs cleanup damages arising contaminated properties failure comply environmental laws regulations may result fines penalties imposed possible us estimate reliably amount timing future expenditures related environmental matters • uncertainties estimating pollution control clean costs • discovery new sites information • uncertainty quantifying liability environmental laws impose joint several liability potentially responsible parties • nature environmental laws regulations • potential changes environmental laws regulations including changes interpretation enforcement thereof although believe established appropriate reserves liabilities including clean costs could required set aside additional reserves future due uncertainties amounts could material additional information concerning environmental matters see part item 3 legal proceedings part ii item 8 financial statements supplementary data note 17 costs litigation matters contingencies could exceed estimates involved various lawsuits subsidiaries sued also contingent liabilities exposures although believe established appropriate reserves liabilities could required set aside additional reserves future amounts could material additional information concerning litigation matters contingent liabilities see part item 8 financial statements supplementary data note 17 system internal controls ensure accuracy completeness disclosures loss public confidence quality internal controls disclosures could negative impact us section 404 sarbanesoxley act 2002 requires us provide annual report internal controls financial reporting including assessment whether internal controls financial reporting effective also required auditors attest assessment opine effectiveness internal controls financial reporting based upon review concluded december 31 2004 maintain effective internal control financial reporting fully discussed item 9a identified several deficiencies internal control financial reporting management concluded constitute material weaknesses although taken steps remediate deficiencies additional steps must taken remediate remaining control deficiencies unable remediate identified internal control deficiencies financial reporting end 2005 identify additional deficiencies internal controls financial reporting could subjected additional regulatory scrutiny future delays filing financial statements suffer loss public confidence reliability financial reporting preparation financial statements external purposes accordance generally accepted accounting principles could negative impact liquidity access capital markets financial condition market value common stock addition risk completing remediation deficiencies internal controls financial reporting expect disclosure controls procedures internal controls financial reporting prevent mistakes errors fraud system internal controls matter well designed implemented provide reasonable absolute assurance objectives control system met design control system must reflect fact benefits controls must considered relative costs design system controls also based part upon certain assumptions likelihood future events assurance design succeed achieving stated goals potential future conditions therefore system internal controls subject inherent limitations including possibility controls may circumvented overridden judgments decisionmaking faulty misstatements due mistakes errors fraud may occur may detected also document assumptions review financial disclosures audit committee board directors regulations literature governing disclosures complex reasonable persons may disagree application particular situation set facts addition applicable regulations literature relatively new result potentially subject change future could include changes interpretation existing regulations literature well issuance detailed rules procedures risks related liquidity significant debt investment grade credit ratings impacted continue impact financial condition results operations liquidity significant debt approximately 19 billion december 31 2004 significant debt service debt maturity obligations ratings assigned senior unsecured indebtedness investment grade currently rated caa1 moody’s investor service moody’s ccc standard poor’s ratings increased cost capital operating costs particularly trading operations could impede access capital markets moreover must retain greater liquidity levels operate business investment grade credit ratings debt maturities december 31 2004 2005 2006 2007 948 million 1155 million 835 million respectively ability generate access capital becomes significantly restrained financial condition future results operations could significantly adversely affected see part ii item 8 financial statements supplementary data note 15 discussion debt may achieve objectives set forth longrange plan timely manner ability achieve objectives longrange plan well timing achievement subject part factors beyond control factors include 1 ability raise cash asset sales may impacted ability locate potential buyers timely fashion obtain reasonable price 2 ability manage working capital 3 ability generate additional cash improving performance pipeline production operations 4 ability exit power trading businesses manner within time period expect 5 ability significantly reduce debt 6 ability preserve sufficient cash flow service debt obligations fail achieve timely manner targets longrange plan liquidity financial position could materially adversely affected addition possible asset sales contemplated longrange plan could prices current book value assets could result losses could substantial breach covenants applicable debt financing obligations could affect ability borrow funds could accelerate debt financing obligations subsidiaries debt financing obligations contain restrictive covenants crossacceleration provisions become restrictive time breach covenants could preclude us subsidiaries issuing letters credit borrowing 3 billion credit agreement could accelerate longterm debt financing obligations subsidiaries occur may able repay debt financing obligations upon acceleration 3 billion credit agreement collateralized equity interests tgp anr epng cig wic southern gas storage company anr storage company breach covenants 3 billion agreement could permit lender exercise rights collateral could required liquidate interests ability access capital markets limited private placements filing new registration statements result restatement historical financial results 2004 restated historical financial statements result downward revision natural gas oil reserves manner applied accounting rules related hedges natural gas production certain derivatives result time required complete revisions 2003 form 10k 2004 forms 10q filed timely manner result january 2006 ability access approximately 926 million capacity existing shelf registration statement without filing additional disclosure information sec restricted additional disclosure requirements related review sec could expensive impede ability access capital timely fashion ability access capital becomes significantly restrained financial condition future results operations could significantly adversely affected subject financing interest rate exposure risks future success depends ability access capital markets obtain financing cost effective rates ability access financial markets obtain costeffective rates future dependent number factors many cannot control including changes • credit ratings • interest rates • structured commercial financial markets • market perceptions us natural gas energy industry • changes tax rates due new tax laws • stock price • changes market prices energy item 7ananitem 7 management’s discussion analysis financial condition results operations overview management’s discussion analysis mda read conjunction consolidated financial statements accompanying footnotes information adjusted periods reflect reclassification anr michigan storage assets 50 interest great lakes gas transmission well macae power facility discontinued operations mda includes forwardlooking statements subject risks uncertainties may result actual results differing statements make risks uncertainties discussed beginning page 22 listed general outline mda help understand operations business environment operate business summary business purpose description profitability drivers summary 2006 performance expect business 2007 update credit metrics results operations yearoveryear analysis beginning page 37 results business segments corporate activities income statement items capital resources liquidity general discussion beginning page 62 debt obligations available liquidity expected 2007 cash flows significant factors could impact liquidity well overview cash flow activity 2006 balance sheet arrangements contractual obligations commoditybased derivative contracts discussion beginning page 67 balance sheet arrangements including guarantees letters credit ii contractual obligations iii derivative contracts used manage price risks associated natural gas oil production critical accounting estimates discussion beginning page 70 accounting estimates involve use significant assumptions andor judgments preparation financial statements business primary business purpose description business purpose provide natural gas related energy products safe efficient dependable manner interests north america’s largest interstate natural gas pipeline systems large independent natural gas oil producer focused growing reserve base disciplined capital allocation portfolio management cost control marketing selling natural gas oil production optimal prices managing associated price risks drivers profitability pipeline operations rateregulated accordingly generate profit based ability earn return excess costs rates charge customers profitability exploration production operations dependent prices natural gas oil volumes able produce among factors future profitability operations primarily driven following factors pipelines expanding existing pipeline systems meet demand growth gain access new supply areas sources contracting recontracting pipeline capacity customers maintaining approval ferc acceptable rates terms service including successfully resolving rate cases improving operating efficiency exploration production marketing increasing natural gas oil proved reserve base production volumes successful drilling programs acquisitions finding producing natural gas oil reasonable cost addition factors future profitability also impacted debt level related interest costs successful resolution historical contingencies completing orderly exit remaining power assets historical derivative contracts remaining noncore assets summary overall performance 2006 financial performance relatively stable pipeline business experienced substantial earnings growth continued provide strong base earnings cash flow exploration production business experienced continued success drilling programs resulting higher production levels quarter year however lower planned production volumes 2006 lower expected commodity prices impacted ability attain operational financial targets year previously established table follows individual segment discussions provide analysis operating results area operations significant highlights pipelines announced sale anr michigan storage assets 50 percent interest great lakes gas transmission implemented ferc approved rate case settlement colorado interstate gas company filed rate case settlement approval ferc el paso natural gas company recontracted contracted available expiring capacity completed several expansion projects proceeded expansion projects pipeline systems elba island lng facility repaired significant damage sections gulf coast offshore pipeline facilities caused hurricanes katrina rita e p increased production volumes quarter year despite lower planned annual production result delays bringing certain production online delays recovering lost volumes due hurricanes katrina rita higher planned maintenance certain onshore fields entered additional derivative contracts 2006 manage price risk substantial portion 2007 natural gas production replaced production primarily capital drilling program achieving overall drilling success rate 98 percent marketing entered agreements assign terminate divest significant transportation contract certain historical natural gas power contracts resolved various legal contractual disputes including settlement pending shareholder derivative actions related brazilian power plants domestic legal matters divested majority remaining power operations total proceeds approximately 09 billion including macae power facility expect going forward 2007 expect current operating trends continue pipeline business february 2007 sold anr michigan storage assets 50 percent interest great lakes gas transmission continue lay foundation future growth establishing inventory expansion projects primary growth areas developing significant infrastructure opportunities anticipate remaining pipeline operations continue provide strong operating results based current levels contracted capacity continued success recontracting expansion plans market supply areas status rate regulatory actions recently announced pursue formation master limited partnership 2007 enhance value financial flexibility pipeline assets provide lowercost source capital new projects exploration production business continue seek create value disciplined balanced capital investment program active management increasing cost production services efficiency improvements drilling programs focus delivering reserves volumes reasonable finding operating costs future financial results primarily dependent continued successful execution drilling programs commodity prices extent anticipated natural gas oil production unhedged hedged substantial portion anticipated 2007 natural gas oil production update credit metrics 2006 strengthened credit metrics result several actions taken year including • reducing debt 28 billion primarily asset sales issuing common stock • restructuring revolving credit facilities improved terms • receiving upgraded senior unsecured debt ratings b2 positive outlook moody’s b positive outlook standard poor’s • entering contracts eliminate price risk portion historical marketing natural gas book net debt less cash 149 billion december 31 2006 including 07 billion anr debt reported discontinued operations closing anr sale provides us approximately 33 billion additional debt reduction february 2007 launched offer tender certain outstanding debt issues additional debt reductions based capital requirements pipeline exploration production businesses ability generate strong cash flow businesses completion sale remaining power assets resolution remaining historical issues liquidity capital resources discussions follow provide information events results operations overview december 31 2006 core operating business segments pipelines exploration production marketing also power segment interests international power plants brazil asia central america segments managed separately provide variety energy products services require different technology marketing strategies corporate activities include general administrative functions well miscellaneous businesses contracts assets immaterial management uses earnings interest expense income taxes ebit assess operating results effectiveness business segments consist consolidated operations well investments unconsolidated affiliates believe ebit useful investors allows effectively evaluate operating performance using performance measure analyzed internally management define ebit net income loss adjusted items impact income loss continuing operations extraordinary items discontinued operations cumulative effect accounting changes ii income taxes iii interest debt expense iv distributions preferred interests consolidated subsidiaries v preferred stock dividends exclude interest debt expense distributions preferred interests consolidated subsidiaries measure investors may evaluate operating results independently financing methods capital structure ebit may comparable measurements used companies additionally ebit considered conjunction net income performance measures operating income operating cash flow reconciliation ebit segment consolidated net income loss three years ended december 31 discussions follow provide additional analysis year results business segments corporate activities income statement items pipelines segment overview pipelines segment operates primarily united states consists interstate natural gas transmission storage lng terminalling related services face varying degrees competition segment existing proposed pipelines proposed lng facilities well alternative energy sources used generate electricity hydroelectric power nuclear power coal fuel oil revenues transportation storage lng terminalling related services consist two types total type description revenues reservation revenues customers referred firm customers reserve capacity pipeline system storage facilities lng terminalling facilities firm customers obligated pay monthly reservation demand charge regardless amount natural gas transport store term contracts usage revenues firm customers interruptible customers without reserved capacity pay usage charges based volume gas actually transported stored injected withdrawn also earn revenues processing sale natural gas liquids miscellaneous sources ferc regulates rates charge customers rates generally function cost providing services customers including reasonable return invested capital regulated nature high percentage revenues attributable reservation charges revenues historically relatively stable however financial results subject volatility due factors changes natural gas prices market conditions regulatory actions competition weather creditworthiness customers also experience earnings volatility amount natural gas utilized operations differs amounts receive purpose historically much business conducted longterm contracts customers however many customers shifted traditional dependence solely longterm contracts portfolio approach balances shortterm opportunities longterm commitments shift increase volatility revenues due changes market conditions competition driven state utility deregulation local distribution company mergers new supply sources volatility natural gas prices demand shortterm capacity new power plant markets continue manage recontracting process limit risk significant impacts revenues ability extend existing customer contracts remarket expiring contracted capacity dependent competitive alternatives regulatory environment federal state local levels market supply demand factors relevant dates contracts extended expire duration new renegotiated contracts affected current prices competitive conditions judgments concerning future market trends volatility subject regulatory requirements attempt recontract remarket capacity maximum rates allowed tariffs although times discount rates various levels pipeline systems remain competitive existing contracts mature various times varying amounts throughput capacity continue manage recontracting process limit risk significant impacts revenues weighted average remaining contract term active contracts approximately five years december 31 2006 expiration schedule firm transportation contracts executed december 31 2006 summary operational financial performance 2006 continued deliver excellent results strong performance across pipelines successfully resolved epng rate case restructured renewed certain customer contracts continued place several expansion projects service including elba island ii terminal expansion pipeline expansions rockies cheyenne plains piceance basin raton basin made significant progress several growth projects also benefited higher realized rates certain systems ii increased throughput 2006 iii various interruptible services iv sales gas used operations v favorable impacts upon revaluation gas imbalances however continue experience nonreimbursable hurricane related costs actual throughput levels relatively minor impact us since generally sell capacity pipeline level throughput provide evidence underlying value capacity 2006 increased throughput across system result broad based increases power demand mexico california northeast southeast based underlying growth electricity demand warmer summer lower availability hydroelectric power northwest also experienced higher supply related throughput result rockies related expansions 2007 intend build growth achieved 2006 among projects currently underway process filing ferc several growth projects transport lng georgia florida remainder southeastern united states see discussion operating results 1 volumes exclude intrasegment activities table discussion follows detail impact ebit significant events 2006 compared 2005 compared 2004 also provided outlook events may affect operations future 1 consists individually insignificant items several pipeline systems higher reservation services revenues year ended december 31 2006 reservation revenues increased primarily due termination effective december 31 2005 reduced tariff rates certain customers terms epng’s fercapproved systemwide capacity allocation proceeding increase epng’s tariff rates subject refund became effective january 1 2006 sales additional firm capacity higher realized rates several pipeline systems compared 2005 addition usage revenues increased due increased activity pipeline systems various interruptible services provided tariffs result favorable market conditions gas used operations revaluations processing revenues natural gas sales 2006 higher realized prices sales gas used operations resulted favorable impacts operating revenues partially offset lower sales volumes natural gas 2006 compared 2005 also experienced favorable impacts operating expenses 2006 due decreases index prices used value net imbalance position several pipeline systems 2005 higher gas prices caused increase obligation replace system gas settle gas imbalances future resulting unfavorable impact operating results addition pipelines also retained lower volumes gas used operations 2005 anticipate overall activity area continue vary based factors regulatory actions already implemented efficiency pipeline operations natural gas prices factors expansions discussion ferc approved expansion projects placed service ii ferc approved expansion projects yet completed various stages certification approval projects placed service 2005 2006 placed several significant expansion projects service including cheyenne plains elba island lng expansion raton basin project piceance basin project related compression wic system projects yet completed 1 estimate reflects anticipated payment approximately 15 million contributions third party 2 revenues projects based throughput levels natural gas reserves developed 3 amount shown net anticipated receipt approximately 12 million contributionsinaidof construction 4 project consist three phases anticipated completion date related phase 1 hurricanes katrina rita 2006 2005 recorded higher operation maintenance expenses result unreimbursed amounts expended repair damage caused hurricanes katrina rita 2005 discussion impact hurricanes capital expenditures see capital resources liquidity impairment pipeline development projects 2006 2005 impaired various pipeline development projects based changing market conditions 2006 recorded impairments 13 million 3 million due discontinuing continental connector pipeline project remainder seafarer project 2005 recorded impairments 18 million 28 million due discontinuing portion seafarer project entirety blue atlantic development project general administrative expenses year ended december 31 2006 general administrative costs lower 2005 primarily due decrease accrued benefit costs lower allocated costs el paso year ended december 31 2005 general administrative costs higher 2004 primarily due increase direct payroll related benefits employees higher legal insurance costs higher corporate overhead allocations el paso el paso’s allocation us increased 2005 based estimated level resources devoted segment’s operations relative size ebit gross property payroll compared consolidated totals higher depreciation expense depreciation expense higher 2006 compared 2005 primarily due higher depreciation rates applied epng’s property plant equipment following effective date rate case pipeline integrity costs january 1 2006 adopted accounting release issued ferc requires us expense certain costs interstate pipelines incur related pipeline integrity programs prior adoption capitalized costs part property plant equipment operating costs 2006 incurred higher costs primarily repairs maintenance 2005 2004 incurred higher costs compressor engine repair preventive maintenance lowering lines pipeline integrity testing well higher legal environmental reserves enron bankruptcy settlement 2006 recorded income approximately 18 million net amounts potentially owed certain customers associated receipt settlement proceeds related enron bankruptcy may receive additional amounts future settlement proceeds released bankruptcy court regulatory mattersrate cases pipeline systems periodically file changes rates subject approval ferc changes rates tariff provisions resulting regulatory proceedings potential positively negatively impact profitability currently certain pipelines requirements file new rate cases expect continue operating existing rates however certain pipelines listed currently rate proceedings upcoming rate actions • epng negotiated settlement rate case filed ferc december 2006 settlement provides benefits epng customers threeyear period ending december 31 2008 discussion settlement see item 8 financial statements supplementary data note 13 • cig august 2006 ferc approved settlement reached cig’s customers effective october 1 2006 settlement establishes systemwide base rates least september 2010 later september 2011 establishes sharing mechanism encourage additional fuel savings anticipate increase revenues approximately 6 million annually effective date settlement • mpc required previous rate case settlement file new rates effective march 2007 anticipate rate decrease resulting variety factors including decline rate base various changes rate design since last rate case although amount impact yet determinable exploration production segment overview strategy exploration production segment conducts natural gas oil exploration production activities operating results segment driven ability locate develop economic natural gas oil reserves extract reserves lowest possible production administrative costs accordingly manage business goal creating value disciplined capital allocation cost control portfolio management domestic natural gas oil reserve portfolio blends slower decline rate typically longer lived assets onshore region steeper decline rate shorter lived assets texas gulf coast gulf mexico shelf south louisiana regions believe combination assets regions provides significant nearterm cash flow providing consistent opportunities competitive investment returns addition international activities brazil egypt provide opportunity additional future reserve additions longer term cash flows part business strategy attempt create value drilling activities acquisitions assets companies 2007 expect growth occur principally drilling activities however believe strategic acquisitions support corporate objectives • reshaping portfolio provide greater optionality achieving long term performance goals • leveraging operational expertise already possess key operating areas geologies techniques • balancing exposure regions basins commodities • achieving riskadjusted returns competitive available within existing inventory • increasing reserves rapidly supplementing current drilling inventory addition executing strategy profitability performance exploration production operations substantially impacted changes commodity prices ii industrywide increases drilling oilfield service costs iii effect hurricanes weather impacts daily production operating capital costs extent possible attempt mitigate factors part risk management activities entered derivative contracts significant portion anticipated natural gas oil production 2007 reduce financial impact downward commodity price movements also actively managing increases operating capital costs significant operational factors affecting year ended december 31 production average daily production year 730 mmcfed excluding 68 mmcfed equity investment four star production levels grew every quarter 2006 however average daily production lower originally expected primarily due unexpected delays gulf mexico shelf onshore regions analysis 2006 production region mmcfed 1 2006 completed sale certain nonstrategic south texas properties production approximately 5 mmcfed january 2007 acquired certain properties net production acquisition date approximately 12 mmcfed 2 production volumes decreased due contractual reduction ownership interest pescadaarabaiana field 2006 3 amounts represent proportionate share production four star acquired third quarter 2005 onshore region increased 2006 production drilling programs acquisition medicine bow 2005 despite impact higher maintenance activity delivery delays two rigs contracted east texas reducing expected 2006 production texas gulf coast able stabilize 2006 production levels repositioning effort region 2004 gulf mexico shelfsouth louisiana region production 2005 2006 adversely affected hurricanes katrina rita 2005 construction delays certain new wells 2006 however successful developing projects west cameron area catapult project helped offset natural declines brazil contractual reduction ownership interest pescadaarabaiana fields early 2006 resulted decrease production drilling results onshore drilled 604 successful gross wells 606 gross wells drilled texas gulf coast experienced 88 percent success rate 49 gross wells drilled gulf mexico shelf south louisiana experienced 82 percent success rate 17 gross wells drilled placed 10 new wells production including five wells south louisiana five wells gulf mexico expect additional four wells drilled 2007 come production early 2007 brazil pinauna field camamu basin filed plan development signed rig contract began drill two exploratory wells february 2007 additionally es5 block espirito santo basin continue discuss possible exploration well petrobras egypt winning bidder south mariut block 3 million second quarter 2006 agreed 22 million firm working commitment three years block 12 million acres located onshore western part nile delta expect receive formal governmental approvals sign concession agreement first quarter 2007 cash operating costs monitor cash operating costs determine amount cash required produce natural gas oil volumes costs calculated per mmcfe basis calculated total operating expenses less depreciation depletion amortization expense noncash expense items cost products services income statement 2006 cash operating costs increased 186mmcfe 167mmcfe 2005 operating cost increases primarily result inflation cost fuel power services increases subsurface maintenance certain onshore fields unrecoverable hurricane repair costs among items expect significant amount costs segment 2007 related hurricanes katrina rita reserve replacement costs reserve replacement ratio calculate two primary metrics reserve replacement ratio ii reserve replacement cost measure ability establish longterm trend adding reserves reasonable cost core asset areas reserve replacement ratio indicator ability replenish annual production volumes grow reserves important us economically find develop new reserves offset produced volumes provide future production given inherent decline hydrocarbon reserves addition calculate reserve replacement cost assess cost adding reserves ultimately included depreciation depletion amortization expense believe ability develop competitive advantage natural gas oil companies dependent adding reserves core asset areas lower cost competition calculate ratios follows 1 reserve additions include proved reserves reflect reserve revisions extensions discoveries additions acquisitions include unproved reserve quantities proved reserve additions attributable investments accounted using equity method amounts derived directly table presented item 8 financial statements supplementary data supplemental natural gas oil operations 2 total oil gas capital costs include costs development exploration property acquisition activities conducted add reserves exclude asset retirement obligations amounts derived directly table presented item 8 financial statements supplementary data supplemental natural gas oil operations reserve replacement ratio reserve replacement cost per unit statistical indicators limitations including predictive comparative value annual measure reserve replacement ratio limited typically varies widely based extent timing new discoveries project sanctioning property acquisitions addition since reserve replacement ratio consider cost timing future production new reserves cannot used measure value creation exploration acquisition development natural gas oil reserves inherently uncertain discussed part item 1a risk factors risks related business one risks uncertainties ability spend sufficient capital increase reserves currently expect spend amounts future assurances timing magnitude expenditures classification proved reserves developed undeveloped december 31 2006 proved developed reserves represent approximately 71 percent total proved reserves proved developed reserves generally begin producing within year added whereas proved undeveloped reserves generally require major future expenditure table shows reserve replacement costs reserve replacement ratio years ended december 31 1 meaningful 2004 due downward revisions previous estimates reserves 2006 reserve replacement costs increased primarily due industry service cost inflation mechanical problems incurred executing drilling program downward revisions previous estimates reserves due lower commodity prices december 31 2006 international capital investments proved reserves yet recorded 2004 reserve replacement costs negatively impacted downward revisions previous estimates reserves typically cite reserve replacement costs context multiyear trend recognition limitation single year measure also demonstrate consistency stability essential business model three year period ending december 31 2006 average reserve replacement costs 399mcfe including acquisitions 520mcfe excluding acquisitions capital expenditures capital expenditures follows three years ended december 31 1 total oil gas capital costs include costs development exploration property acquisition activities conducted add reserves exclude asset retirement obligations amounts derived directly table presented item 8 financial statements supplementary data supplemental natural gas oil operations outlook 2007 anticipate following worldwide basis • average daily production volumes year approximately 740 mmcfed 795 mmcfed excludes approximately 60 mmcfed 65 mmcfed equity investment four star goal achieve three eight percent average annual production growth next several years • capital expenditures excluding acquisitions 14 billion 15 billion represents 20 percent increase 2006 85 company’s planned 2007 capital program allocated domestic program plan spend 215 million international capital 2007 primarily brazil exploration development program january 2007 acquired producing properties undeveloped acreage zapata county texas 249 million complement existing texas gulf coast operations provide reentry lobo trend assets acquired net production approximately 12 mmcfed acquisition date estimated proved reserves approximately 84 bcfe approximately 73 percent undeveloped • average cash operating costs include production costs general administrative expenses approximately 168mcfe 200mcfe year • depreciation depletion amortization rate 250mcfe 275mcfe first quarter 2007 compared 258mcfe fourth quarter 2006 price risk management activities part strategy enter derivative contracts natural gas oil production stabilize cash flows reduce risk financial impact downward commodity price movements commodity sales protect economic assumptions associated capital investment programs strategy partially reduces exposure downward movements commodity prices reported results operations financial position cash flows impacted significantly movements commodity prices period adjustments hedging strategy decision enter new positions alter existing positions made corporate level based goals overall company following table discussion follows shows december 31 2006 contracted volumes minimum maximum average prices receive contracts combined sale underlying hedged production 1 volumes presented tbtu natural gas mbbl oil prices presented per mmbtu natural gas per bbl oil 2 basis swaps effectively “lockin” locational price differences portion natural gas production texas oklahoma natural gas fixed price swap floor ceiling contracts table designated accounting hedges gains losses associated natural gas contracts deferred accumulated comprehensive income recognized earnings upon sale related production market prices resulting realized price approximately equal hedged price oil swaps approximately 51 tbtu natural gas basis swaps designated hedges accordingly changes fair value swaps deferred recognized earnings period table include derivative contracts terminated fourth quarter 2006 record additional 62 million gains income taxes 2007 currently deferred accumulated comprehensive income ii contracts entered marketing segment described page 53 consolidated impact entirety el paso’s productionrelated price risk management activities liquidity see discussion factors could impact liquidity beginning page 62 operating results variance analysis tables discussion follows provide operating results analysis significant variances results periods ended december 31 1 production costs include lease operating costs production related taxes including ad valorem severance taxes 2 includes equity earnings investment proportionate share volumes four star acquired third quarter 2005 3 prices stated transportation costs 4 see discussion page 44 year ended december 31 2006 compared year ended december 31 2005 ebit 2006 decreased 56 million compared 2005 table lists significant variances operating results 2006 compared 2005 operating revenues natural gas revenues decreased approximately 197 million natural gas prices strong 2006 compared 2005 however experienced lower hedging program losses 2006 58 million compared losses 260 million 2005 realized oil condensate ngl prices increased 2006 compared 2005 production volumes benefited acquisitions 2005 however overall production volumes decreased texas gulf coast gulf mexico shelf south louisiana regions due natural declines sale certain nonstrategic south texas properties average production 5 mmcfed 2006 also gulf mexico shelf south louisiana region production continued impacted 2006 hurricanes katrina rita occurred late 2005 production volumes brazil decreased due contractual reduction ownership interest pescadaarabaiana field 2006 depreciation depletion amortization expense 2006 experienced higher depletion rates compared 2005 primarily result higher finding development costs cost acquired reserves however lower production volumes 2006 partially offset impact higher depletion rates production costs 2006 lease operating costs increased compared 2005 regions result inflation fuel costs power services onshore region additional increases due increased subsurface maintenance acquisition medicine bow gulf mexico shelf region additional increases due hurricane repairs recoverable insurance additionally production taxes increased result lower tax credits texas taken 2006 compared 2005 general administrative expenses general administrative expenses decreased 2006 compared periods 2005 primarily due lower corporate overhead allocations 2006 recorded loss approximately 40 million fair value derivatives designated hedges compared 9 million loss 2005 2006 ebit also unfavorably impacted earnings four star due lower natural gas prices ebit favorably impacted operations processing plants insurance recoveries resulting hurricane ivan among items year ended december 31 2005 compared year ended december 31 2004 ebit 2005 decreased 38 million compared 2004 table lists significant variances operating results 2005 compared 2004 operating revenues 2005 benefited strong commodity pricing environment natural gas oil condensate ngl however losses hedging program year ended december 31 2005 260 million compared 18 million 2004 additionally experienced nine percent decrease production volumes versus period 2004 although production volumes benefited acquisitions 2005 acquisition consolidation remaining interest unopaso brazil july 2004 texas gulf coast gulf mexico shelf south louisiana regions experienced declines year production due normal declines lower capital spending program areas last several years addition gulf mexico shelf south louisiana region impacted hurricanes katrina rita texas gulf coast region impacted mechanical well failures depreciation depletion amortization expense 2005 experienced higher depletion rates compared 2004 result higher finding development costs cost acquired reserves resulting higher depreciation depletion amortization expense however 2005 impact lower production volumes partially offset impact higher depletion rates production costs experienced higher costs 2005 due implementation programs first half 2005 improve production texas gulf coast gulf mexico shelf south louisiana regions higher salt water disposal costs utility expenses marine transportation costs increased operating costs brazil due july 2004 unopaso acquisition consolidation production taxes also higher result higher commodity prices 2005 higher tax credits taken 2004 high cost natural gas wells general administrative expenses general administrative expenses higher 2005 2004 primarily due increase direct payroll related benefits employees higher legal insurance costs marketing segment marketing segment’s primary focus market exploration production segment’s natural gas oil production manage company’s overall price risks primarily use natural gas oil derivative contracts addition continue manage liquidate remaining natural gas supply transportation power natural gas contracts entered prior deterioration energy trading environment 2002 future liquidations may impact cash flows financial results however may liquidate certain remaining historical contracts expiration uneconomical sell terminate current environment due terms credit concerns counterparty lack liquidity market ii sale would require acceleration cash demands table follows provides summary events remaining contracts sensitivity changes commodity prices operating results overview past three years operating results yeartoyear comparability significantly impacted substantial commodity price fluctuations changes composition portfolio based actions taken reduce exposure commodity price fluctuations exit historical trading activities 2004 2005 rising natural gas prices significant negative impact natural gas power derivative contracts resulting significant losses years past two years entered transactions reduce exposure commodity prices including divestitures cordova tolling agreement majority contracts power portfolio 2005 divestiture significant portion natural gas portfolio 2006 also recorded losses 188 million upon paying third party assume alliance transportation capacity obligations effective november 1 2007 approximately 133 million third quarter 2006 midland cogeneration venture mcv supply agreement conjunction sale interest related power facility combination actions taken reduce exposure decreases natural gas prices improved operating results 2006 tables discussions follow provide information events overall operating results analysis significant contract type marketing segment three years ended december 31 1 amount 2006 includes 188 million loss operating revenues related alliance discussed 50 million gain 2004 related early termination lng contract 2 amounts 2006 include loss mcv contract described 3 gross margin consists revenues commodity trading origination activities less costs commodities sold including changes fair value derivative contracts 4 2006 2005 incurred lower corporate overhead allocation general administrative expenses based overall cost reduction efforts corporate level reduced level operations 2005 recorded 19 million legal settlements reserves resulted increased operating expenses 2005 productionrelated natural gas oil derivatives options swaps productionrelated natural gas oil derivative contracts designed provide protection el paso changes natural gas oil prices addition derivative contracts entered exploration production segment discussed beginning page 40 consolidated impact el paso’s productionrelated price risk management activities refer liquidity discussion beginning page 52 december 31 2006 productionrelated derivatives consisted various option contracts swap contracts expired fair value derivative contracts impacted changes commodity prices periodtoperiod markedtomarket results listed volumes average prices associated productionrelated derivative contracts december 31 2006 1 volumes presented tbtu natural gas mbbl oil prices presented per mmbtu natural gas per bbl oil 2006 decreases commodity prices favorably impacted value contracts ebit 2005 increases commodity prices negatively impacted value contracts ebit received approximately 59 million 2006 paid 40 million 2005 related contracts settled periods fourth quarter 2006 entered put contracts 89 tbtu natural gas production 2007 floor price 750 per mmbtu paid premium 82 million premium paid largely offset funds received exploration production segment 2006 upon termination 75 tbtu collars 2007 natural gas production natural gas oil prices remain floor prices option contracts option contracts expire without value expense premium paid natural gas oil prices increase ceiling prices option contracts losses occur since obligated contracts provide natural gas oil fixed prices lower market price productionrelated derivatives 2004 losses result increases natural gas prices relative fixed priced commodity contracts held time fourth quarter 2004 designated contracts accounting hedges transferred exploration production segment reflects contracts financial results contracts related historical trading operations natural gas transportationrelated contracts december 31 2006 transportation contracts provide us approximately 08 bcfd pipeline capacity require us pay approximately 115 million demand charges 2007 december 2006 paid third party 188 million assume obligations alliance capacity contract beginning november 1 2007 reduce demand charges average approximately 46 million annually 2008 2011 recovery demand charges related transportation contracts therefore profitability contracts dependent upon ability use remarket contracted pipeline capacity impacted number factors including differences natural gas prices contractual receipt delivery locations working capital needed use capacity required meet long term obligations transportation contracts accounted accrual basis impact gross margin delivery service contracts occurs following table summary demand charges millions percentage recovery charges three years ended december 31 1 2006 excluded amount 188 million paid conjunction sale contract described 2 2006 unable recover demand charges incurred 4 million losses excess demand charges related managing capacity contracts 3 includes demand charges related storage contracts 1 million 1 million 2 million 2006 2005 2004 natural gas derivative contracts addition transportationrelated natural gas contracts third parties require us purchase deliver natural gas primarily market prices exposure volatility gas prices relates natural gas derivative contracts varies period based whether purchase less natural gas sell contracts right purchase natural gas fixed prices obligation sell contracts natural gas prices increased 2004 2005 fair value contracts increased however natural gas prices decreased 2006 resulting decrease fair value contracts noted 2006 divested entered transactions divest substantial portion natural gas contracts substantially eliminated future cash earnings exposure price movements contracts ebit 2006 also impacted 49 million gain associated assignment contracts supply natural gas certain municipalities florida marktomarket loss third quarter approximately 133 million natural gas supply contracts associated sale power segment interest mcv power plant prior sale recognized cumulative marktomarket losses contracts extent ownership interest due affiliated nature power contracts end 2005 divested entered transactions divest substantial portion power contracts including cordova tolling agreement substantially eliminated cash earnings exposure power price movements contracts prior entering transactions eliminate price risk associated historical positions experienced significant net decreases fair value contracts based primarily changes natural gas power prices well differences locational power prices remaining exposure power portfolio related four contracts require us swap locational differences power prices several power plants pennsylvanianew jerseymaryland pjm eastern region pjm west hub provide installed capacity pjm power pool commodity risk associated contracts due positions put place 2005 2006 eliminate risk 2006 fair value contracts increased locational difference power prices pjm east west regions decreased 2005 bankruptcy court entered order allowing mohawk river funding iii’s mrf iii bankruptcy claims usgen new england received payment claims recognized gain 17 million 2005 related settlement 2004 recorded 25 million gain related termination power contract power segment eliminated el paso’s consolidated results power segment overview power segment consists assets brazil asia central america continue pursue sales remaining power investments including interest porto velho facility brazil december 31 2006 remaining investment guarantees letters credit related power projects segment totaled approximately 660 million consisted approximately 618 million equity investments notes receivable approximately 42 million financial guarantees letters credit prior 2006 financial results segment significantly impacted impairment losses net gains losses sales domestic restructured power contracts power facilities 2004 recorded significant impairment charges based decision exit domestic international power operations including approximately 590 million related restructured power contracts domestic power facilities approximately 365 million related international power facilities 2005 recorded additional impairments net gains losses sale related asian central american power facilities well losses mcv discussion events factors impacting results segment three years ended december 31 listed 1 ebit operations includes 17 million dividend investment fund recorded 2005 2 disposition shares 2005 2006 longer interest international commodity exchange 3 consists indirect expenses general administrative costs also includes impairments losses sales power turbines 27 million 1 million recorded 2005 2004 brazil december 31 2006 remaining investment guarantees letters credit related power projects brazil approximately 555 million amount approximately 315 million relates porto velho project sells power eletronorte two power sales agreements expire 2010 2023 eletronorte expressed interest acquiring interest power plant evaluate potential opportunity could required record loss based potential value may receive sell facility 2006 2005 2004 ebit porto velho operations 41 million 23 million 28 million remainder exposure brazil relates primarily manaus rio negro power plants interests boliviatobrazil argentinatochile pipelines see description part item 1 business part ii item 8 financial statements supplementary data note 18 2004 based new power contracts signed january 2005 impaired manaus rio negro facilities new contracts resulted decrease earnings projects addition provide transfer facilities power offtaker early 2008 manaus rio negro plants earnings plant operations 2006 2005 2004 17 million 19 million 30 million brazilian operations including interests boliviatobrazil argentinatochile pipelines generated ebit 6 million 13 million 6 million 2006 2005 2004 international power december 31 2006 remaining investments guarantees letters credit approximately 105 million related power projects asia central america expect complete sale substantially remaining international power assets first half 2007 changes regional political economic conditions could negatively impact anticipated proceeds could result additional impairments noted recorded impairments gains sales 2004 2005 based value received expected received upon closing sales asian central american assets results period also negatively impacted reduction earnings facility sold decision recognize earnings certain asian central american assets based inability realize earnings expected selling price recognize earnings approximately 26 million 30 million years ended 2006 2005 domestic power upon closing sales mcv capitol district energy center cogeneration associationcdecca berkshire facilities 2006 completed disposition domestic power business began 2003 recorded gain approximately 13 million upon sale mcv recorded 3 million loss sale cdecca berkshire facilities disposition mcv facility 2006 also impacted certain contracts financial results marketing segment noted 2004 2005 sold interests several domestic power facilities restructured power contracts resulting significant impairments substantially lower earnings operations addition recorded impairments investment mcv 2004 based decline value due increased fuel costs recorded proportionate share mcv’s losses based impairment plant assets 2005 field services segment 2004 2005 divestiture assets operations segment resulted significant gains losses operating results prior sale assets generated earnings primarily general limited partner interests gulfterra enterprise products partners gathering processing assets south texas south louisiana sales assets described part ii item 8 financial statements supplementary data note 18 tables discussion follows provide operating results additional analysis significant factors affecting ebit field services segment years ended december 31 1 gross margins consist operating revenues less cost products sold believe measurement meaningful understanding analyzing field services segment’s operating results 2005 2004 commodity costs historically significant factor determination profit midstream activities gathering processing activities decreases gross margin 2005 operation maintenance expenses primarily result asset sales including sales south texas north south louisiana midcontinent indian springs gathering processing plants gulfterraenterprise related items prior 2006 sold number assets gulfterra sales decreased gross margin operating expenses increased equity earnings general limited partner interests gulfterra however time overall equity earnings gulfterra declined sold interests investment effect significant transactions related gulfterra 2005 2004 follows • gain 507 million upon sale remaining 50 percent interest general partner gulfterra enterprise 2004 result sale also impaired goodwill recorded segment • gain 183 million sale remaining general partner limited partner interests enterprise 2005 corporate expenses net corporate activities include general administrative functions well number miscellaneous businesses qualify operating segments material current year results following summary significant items impacting ebit corporate operations three years ended december 31 litigation insurance reserves number pending litigation matters us matters evaluate lawsuit claim merits defenses adverse rulings unfavorable settlements us related matters impacted may impact future results 2005 2004 recorded significant charges operation maintenance expense increase litigation insurance reserves based ongoing assessments developments evaluations possible outcomes matters 2005 significant item charge connection ruling appellate court indemnify former subsidiary certain payments made retiree benefit plan additionally incurred charges 2005 final prepayment western energy settlement charges related increased premiums mutual insurance company participate based primarily impact several hurricanes 2004 2005 2004 also incurred charges associated western energy settlement obligation charges related decision withdraw another mutual insurance company member restructuring charges discussed part ii item 8 financial statements supplementary data note 13 consolidated houstonbased operations one location 2005 2004 recorded charges 27 million 80 million related vacating remaining leased space signing termination agreement lease interest debt expense total interest debt expense decreased past three years primarily due retirements debt financing obligations net issuances see part ii item 8 financial statements supplementary data note 12 discussion income taxes 2006 2005 overall effective tax rate continuing operations significantly different statutory rate due primarily recording 159 million 58 million tax benefits based primarily conclusion irs audits 2006 audits coastal corporation’s 19982000 tax years el paso’s 2001 2002 tax years concluded resulted reduction tax contingencies reinstatement certain tax credits 2005 finalized coastal corporation’s irs tax audits years prior 1998 2004 overall effective tax rate continuing operations significantly different statutory rate due primarily sales gulfterra investment impairments certain foreign investments sale gulfterra resulted significant net taxable gain compared lower book gain thus significant tax expense due nondeductibility goodwill written result transaction additionally received us federal income tax benefit impairment certain foreign investments discussion effective tax rates tax matters see part ii item 8 financial statements supplementary data note 5 discontinued operations discontinued operations include anr pipeline related assets gathering processing operations south louisiana certain international power operations petroleum markets operations international natural gas oil production operations outside brazil egypt years ended december 31 2006 2005 losses discontinued operations 56 million 96 million 2006 loss 56 million primarily result recording approximately 188 million deferred taxes upon agreeing sell stock anr michigan storage assets 50 percent interest great lakes gas transmission prior decision sell required record deferred taxes individual assets liabilities portion investment stock one companies february 2007 sold assets expect recognize aftertax gain approximately 07 billion first quarter 2007 2005 loss 96 million primarily result impairments discontinued international power operations partially offset income anr related assets gain sale south louisiana operations impairments international power assets gain sale south louisiana discussed part ii item 8 financial statements supplementary data note 2 2004 income discontinued operations 85 million related primarily operations anr related assets international power partially offset operational costs commitments contingencies discussion commitments contingencies see part ii item 8 financial statements supplementary data note 13 capital resources liquidity debt obligations 2006 continued reduce overall debt obligations using cash hand cash generated operations proceeds asset sales proceeds issuance common stock also restructured 3 billion credit agreement actions allowed us reduce debt obligations 147 billion excluding discontinued operations december 31 2006 february 2007 sold anr michigan storage assets 50 percent interest great lakes gas transmission transcanada tc pipelines lp approximately 41 billion including assumption approximately 475 million debt assumed buyer sale anr provides approximately 33 billion additional debt reductions following completion sale offered tender certain outstanding debt discussion debt obligations see part ii item 8 financial statements supplementary data note 12 available liquidity december 31 2006 available liquidity follows billions past years simplified capital structure businesses reduced amount liquidity needed normal course business however could required increase available liquidity based certain factors described expected 2007 cash flows noted repay significant amount debt using proceeds sale anr also expect generate positive operating cash flows 2007 supplemented expected proceeds remaining asset sales used working capital requirements grow maintain businesses capital expenditures currently anticipate following capital spending billions 1 includes approximately 250 million spent january 2007 acquisition natural gas oil properties december 31 2006 2007 contractual debt maturities approximately 08 billion first half 2007 also approximately 06 billion debt holders require us redeem subsequent year end holders 300 million obligations exercise redemption right debt mature 2027 additionally offered tender certain debt obligations extent necessary may also use cash hand cash flow generated operations borrowings revolvers new financing transactions additional debt retirement significant factors could impact liquidity cash margining requirements derivative contracts historically required post significant cash margin deposits letters credit counterparties value substantial portion natural gas fixed price swap contracts prices current market prices 2006 approximately 09 billion posted cash margin deposits returned us resulting combination decreases commodity prices settlement certain contracts assignment contracts power portfolio result substantial portion remaining margin consists letters credit 2007 based current prices expect approximately 02 billion total 11 billion collateral outstanding december 31 2006 returned us form cash margin deposits letters credit commodity prices increase could required post additional margin prices decrease entitled recover amount earlier anticipated based derivative positions december 31 2006 010mmbtu increase price natural gas would result increase margin requirements approximately 11 million consists 3 million transactions settle 2007 5 million transactions settle 2008 3 million transactions settle 2009 thereafter mitigate potential margin requirements natural gas prices increase level greater currently anticipate entered 250 million unsecured contingent letter credit facility january 2007 matures march 2008 letters credit available us average nymex gas price strip remaining calendar months march 2008 reaches 1175 per mmbtu hurricanes continue repair damages pipeline exploration production related facilities caused hurricanes katrina rita 2005 currently estimate total repair costs approximately 625 million mutual insurance company indicated receive insurance recoveries amounts due exceeding aggregate loss limits per event expect remaining repair costs incurred 2007 insurance reimbursements received 2007 2008 believe unrecovered costs materially impact overall liquidity financial results timing expenditures reimbursements may impact liquidity period table provides detail spent date estimated remaining costs insurance recoveries millions 1 includes capital expenditures approximately 275 million mutual insurance company also indicated effective june 1 2006 aggregate loss limits future events reduced 500 million 1 billion could limit recoveries future hurricanes insurable events price risk management activities exploration production marketing segments enter derivative contracts provide price protection portion anticipated natural gas oil production 2006 entered additional derivative contracts related significant portion 2007 natural gas production following table shows december 31 2006 contracted volumes minimum maximum average cash prices receive contracts combined sale underlying production cash prices may differ income impacts derivative contracts depending whether contracts designated hedges accounting purposes individual segment discussions provide additional information income impacts derivative contracts 1 volumes presented tbtu natural gas mbbl oil prices presented per mmbtu natural gas per bbl oil 2 basis swaps effectively “lockin” locational price differences portion natural gas production texas oklahoma overview cash flow activities 2006 compared 2005 1 amounts contributed discontinued operations net approximately 02 billion debt repayments associated macae power facility 2006 continued expand core pipeline exploration production businesses reduce debt obligations 2006 generated positive operating cash flow approximately 18 billion primarily result cash provided pipeline exploration production operations 04 billion received settlement derivative contracts return approximately 09 billion broker margins related derivative contracts utilized operating cash flow along proceeds asset sales issuance longterm debt common stock well available cash fund maintenance growth projects approximately 10 billion pipeline operations 11 billion exploration production operations ii repay debt noted ability utilize cash hand debt repayment based maintaining lower levels cash available liquidity ordinary course business due simplification business capital structure offbalance sheet arrangements course business activities enter variety financing arrangements contractual obligations certain arrangements often referred offbalance sheet arrangements include guarantees letters credit interests variable interest entities guarantees involved various joint ventures ownership arrangements sometimes require additional financial support results issuance financial performance guarantees financial guarantee obligated make payments guaranteed party fails make payments violates terms financial arrangement performance guarantee provide assurance guaranteed party execute terms contract required perform behalf example guaranteed party required purchase services third party fails would required either purchase services make payments third party compensate losses incurred nonperformance also periodically provide indemnification arrangements related assets businesses sold arrangements include limited indemnifications income taxes resolution existing disputes environmental matters necessary expenditures ensure safety integrity assets sold record accruals guaranty indemnification arrangements fair value issued subsequently adjust accruals believe probable pay amounts arrangements amounts estimated december 31 2006 liability 71 million related guarantees indemnification arrangements total stated exposure 376 million indemnified third parties 18 million amounts exclude guarantees issued related letters credit discussed included stated value 376 million approximately 120 million associated tax matters related interest indemnifications arising sale macae power facility 2006 addition exposures described received ruling trial court upheld appeal required indemnify third party benefits paid closed group retirees one former subsidiaries liability approximately 379 million associated estimated exposure matter december 31 2006 discussion matter see part ii item 8 financial statements supplementary data notes 13 14 letters credit enter letters credit ordinary course operations well periodically conjunction sales assets businesses december 31 2006 outstanding letters credit approximately 14 billion including 11 billion letters credit securing recorded obligations related price risk management activities interests variable interest entities interests several variable interest entities primarily investments held power segment variable interest entity legal entity whose equity owners sufficient equity risk controlling financial interest entity required consolidate entities allocated majority variable interest entity’s losses return including fees paid entity december 31 2006 consolidate seven variable interest entities since primary beneficiary variable interest entity’s operations additional information regarding interests entities see part ii item 8 financial statements supplementary data note 18 investments earnings transactions unconsolidated affiliates contractual obligations party various contractual obligations include offbalance sheet arrangements described portion obligations reflected financial statements longterm debt liabilities commoditybased derivative contracts accrued liabilities obligations demand charges transportation storage commitments operating leases capital commitments reflected balance sheet following table discussion follows summarizes contractual cash obligations december 31 2006 periods presented amounts undiscounted except liabilities commoditybased derivative contracts long term financing obligations principal interest debt obligations included represent stated maturities unless otherwise puttable us prior stated maturity date contractual interest payments shown stated maturity date related debt discussion debt obligations see item 8 financial statements supplementary data note 12 excluded amounts table 744 million principal 703 million interest related anr reported discontinued operations liabilities commoditybased derivative contracts amounts include fair value price risk management liabilities fair value price risk management assets 807 million december 31 2006 reflected amounts also excluded margin deposits held associated contracts amounts discussion commoditybased derivative contracts see discussion commoditybased derivative contracts contractual liabilities included amount contractual environmental obligations included current noncurrent liabilities balance sheet excluded amounts expected contributions pension postretirement benefit plans 144 million four year period ended december 31 2010 expected contributions contractually required also excluded potential amounts due indemnification former subsidiary benefits paid closed group retirees liability approximately 379 million related litigation associated matter december 31 2006 operating leases discussion obligations see part ii item 8 financial statements supplementary data note 13 contractual commitments purchase obligations contractual commitments purchase obligations defined legally enforceable agreements purchase goods services fixed minimum quantities fixed minimum variable price provisions detail approximate timing underlying obligations included following • transportation storage commitments included amounts commitments demand charges firm access natural gas transportation storage capacity • commitments included amounts commitments drilling seismic activities exploration production operations various maintenance engineering procurement construction contracts well service license agreements used operations excluded asset retirement obligations reserves litigation environmental remediation selfinsurance claims liabilities contractually fixed timing amount excluded amounts contractual commitments 223 million related anr reported discontinued operations commoditybased derivative contracts use derivative financial instruments exploration production marketing segments manage price risk commodities tables derivatives designated hedges primarily consist collars swaps used hedge natural gas production commoditybased derivative contracts relate derivative contracts designated hedges options swaps natural gas power purchase supply contracts following table details fair value commoditybased derivative contracts year maturity valuation methodology december 31 2006 1 positions traded active exchanges new york mercantile exchange international petroleum exchange london clearinghouse following reconciliation commoditybased derivatives years ended december 31 2006 2005 1 includes derivative contracts soldterminated 2 amounts net premiums received fair value contract settlements fair value contract settlements period represents estimated amounts derivative contracts settled physical delivery commodity claim cash accounts receivable payable fair value contract settlements also includes physical financial contract terminations due counterparty bankruptcies sale settlement derivative contracts early termination sale entities contracts including amounts received sale option contracts changes fair value contracts change fair value contracts year represents change value contracts beginning period date origination acquisition settlement early termination settled terminated end period 2006 change fair value also includes loss natural gas supply agreements related mcv upon sale interest facility assignment contracts 2005 entered agreement assign majority power derivative assets morgan stanley received total proceeds 442 million 2006 sold entered offsetting derivative transactions eliminate price risk associated substantial portion remaining historical natural gas derivatives paid proceeds approximately 32 million related transaction designation reclassifications hedges 2005 2006 removed hedging designation certain derivative contracts experienced decreases related anticipated hedged production volumes brazil also 2006 designated certain existing commoditybased derivatives hedges anticipated 2007 natural gas production critical accounting estimates significant accounting policies described note 1 consolidated financial statements included item 8 annual report form 10k preparation financial statements conformity generally accepted accounting principles requires management select appropriate accounting estimates make estimates assumptions affect reported amount assets liabilities revenue expenses disclosures contingent assets liabilities consider critical accounting estimates require difficult complex subjective judgment necessary accounting inherently uncertain matters changes facts circumstances may result revised estimates actual results may differ materially estimates discussed development selection following critical accounting estimates related disclosures audit committee board directors accounting natural gas oil producing activities estimates proved reserves reflect quantities natural gas oil ngls geological engineering data demonstrate reasonable certainty recoverable future years known reservoirs existing economic conditions natural gas oil reserves estimates underlie number accounting estimates financial statements process estimating natural gas oil reserves particularly proved undeveloped proved nonproducing reserves complex requiring significant judgment evaluation available geological geophysical engineering economic data reserve estimates developed internally reserve reporting group separate operations group reviewed internal committees internal auditors addition thirdparty reservoir engineering firm appointed reports audit committee board directors prepares independent estimate significant portion proved reserves december 31 2006 total proved reserves 29 percent undeveloped 11 percent developed nonproducing addition data given field may also change substantially time result numerous factors including additional development activity evolving production history continual reassessment viability production changing economic conditions result material revisions existing reserve estimates occur time addition subjective decisions variances available data various fields increase likelihood significant changes estimates proved natural gas oil reserves primarily impact property plant equipment amounts balance sheets depreciation depletion amortization amounts income statements among items use full cost method account natural gas oil producing activities accounting method capitalize substantially costs incurred connection acquisition exploration development natural gas oil reserves including salaries benefits internal costs directly related finding activities capitalized costs maintained full cost pools geographic areas regardless whether reserves actually discovered record depletion expense capitalized amounts life proved reserves based unit production method factors held constant 10 percent increase estimated proved reserves would decrease unit production depletion rate 9 percent 10 percent decrease estimated proved reserves would increase unit depletion rate 11 percent natural gas oil properties include unproved property costs excluded costs depleted unproved property costs include nonproducing leasehold geological geophysical costs associated leasehold drilling interests exploration drill costs investments unproved properties major development projects direct interest exclude costs countrybycountry basis proved reserves found determined costs impaired costs excluded reviewed least quarterly determine exclusion fullcost pool continues appropriate costs determined impaired amount impairment transferred full cost pool reserve base exists expensed reserve base yet created impairments transferred full cost pool increase depletion rate country full cost accounting method required conduct quarterly impairment tests capitalized costs full cost pools impairment test referred ceiling test total capitalized costs net related income tax effects limited ceiling based present value future net revenues proved reserves discounted 10 percent net related income tax effects plus lower cost fair market value unproved properties utilize end period spot prices calculating future net revenues unless prices result ceiling test charge case evaluate price recoveries subsequent end period discounted revenues greater equal total capitalized costs required writedown capitalized costs level ceiling test calculations include effect derivative instruments designated qualify hedges anticipated natural gas oil production higher proved reserves reduce likelihood ceiling test impairments ceiling test charges 2006 2005 recorded ceiling test charges 35 million 2004 ceiling test calculation assumes price effect last day quarter held constant life reserves even though actual prices natural gas oil volatile change period decline commodity prices impact results ceiling test may result writedown decrease commodity prices 10 percent price levels december 31 2006 would resulted ceiling test charge 2006 accounting legal environmental reserves accrue legal environmental reserves assessments indicate probable liability incurred asset recovered amount reasonably estimated estimates liabilities based evaluation potential outcomes currently available facts case environmental reserves existing technology presently enacted laws regulations taking consideration likely effects societal economic factors estimates associated onsite offsite groundwater technical studies legal costs actual results may differ estimates often revised future either negatively positively depending upon actual outcomes changes expectations based facts surrounding matter december 31 2006 accrued approximately 548 million legal matters includes approximately 379 million associated indemnity certain retiree benefit payments discussed accrued 314 million environmental matters environmental estimates range approximately 314 million approximately 532 million amounts accrued represent combination two estimation methodologies first likely outcome reasonably estimated cost accrued 27 million second likely outcome cannot estimated range costs established 287 million 505 million lower end expected range accrued accounting pension postretirement benefits fourth quarter 2006 adopted provisions sfas 158 employers’ accounting defined benefit pension postretirement plans amendment fasb statements 87 88 106 132r standard reflect asset liability pension postretirement benefit plans based funded status december 31 2006 combined pension plans funded 228 million combined postretirement benefit plans funded 209 million pension postretirement benefit assets liabilities primarily based actuarial calculations use various assumptions performing calculations including related return expect earn plan assets rate expect compensation employees increase plan term estimated cost health care benefits provided plans factors significant assumption utilize discount rates used calculating benefit obligations compare discount rates based average expected timing pension postretirement obligations maturity profiles moody’s corporate bond indices citigroup pension discount curve based comparisons select discount rates appropriately reflect yields included market sources adjusted estimated timing obligations actual results may differ assumptions included calculations result estimates associated pension postretirement benefits often revised future income statement impact changes assumptions related benefit obligations along changes plans items deferred accumulated comprehensive income amortized income either period expected future service active participants lives plan participants cumulative amount deferred accumulated comprehensive loss december 31 2006 approximately 435 million net income taxes following table shows impact one percent change primary assumptions used actuarial calculations associated pension postretirement benefits year ended december 31 2006 millions 1 actual return plan assets one percent lower expected return plan assets expected cash contributions pension postretirement benefit plans would significantly change estimates net benefit expense income partially based expected return pension plan assets use marketrelated value plan assets determine expected return pension plan assets determining marketrelated value plan assets differences expected actual asset returns deferred three years considered inclusion net benefit expense income used fair value plan assets instead marketrelated value plan assets determining expected return pension plan assets net benefit expense would 15 million lower year ended december 31 2006 stated financial statements supplementary data note 14 ordered indemnify third party certain benefit payments made closed group retirees pending outcome litigation related payments estimated initial liability associated indemnification obligation using actuarial methods similar used estimating obligations postretirement benefit plans involves using various assumptions including related discount rates health care trends one percent change discount rate assumption used calculation would changed liability related expense approximately 36 million one percent change health care cost trend assumption would changed liability related expense approximately 49 million year ended december 31 2006 price risk management activities record derivative instruments used price risk management activities fair values estimate fair value derivative instruments using exchange prices thirdparty pricing data valuation techniques incorporate specific contractual terms statistical simulation analysis present value concepts one primary assumptions used estimate fair value derivative instruments pricing assumptions based upon price curves derived actual prices observed market pricing information supplied thirdparty valuation specialist independent pricing sources models rely forward pricing information adjust price curves certain areas pennsylvanianew jerseymaryland region based outlook liquidity markets may differ derivative counterparties table presents hypothetical sensitivity commodity based price risk management activities changes fair values arising immediate selected potential changes quoted market prices december 31 2006 significant assumptions use determining fair value derivative instruments related time value anticipated market liquidity credit risk counterparties assumptions methodologies use determine fair values derivatives may differ used derivative counterparties differences significant result actual settlement price risk management activities could differ materially fair value recorded could impact future operating results asset investment impairments accounting rules asset investment impairments require us continually monitor businesses business environment determine event occurred indicates longlived asset investment may impaired event occurs determination involves judgment estimate fair value asset considers number factors including potential value would receive sold asset projected cash flows asset based current anticipated future market conditions assessment project level cash flows requires judgment make projections assumptions many years future pricing demand competition operating costs legal regulatory issues factors actual results often differ estimates carrying value asset exceeds future undiscounted cash flows expected asset impairment charge recorded excess carrying value asset fair value recorded impairments longlived assets 16 million 73 million 11 billion impairments investments unconsolidated affiliates 13 million 347 million 397 million years ended december 31 2006 2005 2004 also recorded asset investment impairments discontinued operations 13 million 502 million 40 million net minority interest years ended december 31 2006 2005 2004 future changes economic business environment impact assessments potential impairments new accounting pronouncements issued yet adopted see part ii item 8 financial statements supplementary data note 1 new accounting pronouncements issued yet adopted item 7aitem 7 management’s discussion analysis financial condition results operations overview management’s discussion analysis mda read conjunction consolidated financial statements accompanying footnotes mda includes forwardlooking statements subject risks uncertainties may result actual results differing statements make risks uncertainties discussed beginning page 27 listed general outline mda business includes summary business purpose description factors influencing profitability summary 2007 performance outlook 2008 update credit profile results operations includes yearoveryear analysis beginning page 44 results business segments corporate activities income statement items including trends may impact business future liquidity capital resources includes general discussion beginning page 65 debt obligations available liquidity expected 2008 cash flows significant factors could impact liquidity well overview cash flow activity 2007 balance sheet arrangements contractual obligations commoditybased derivative contracts includes discussion beginning page 68 balance sheet arrangements including guarantees letters credit ii contractual obligations iii derivative contracts used manage price risks associated natural gas oil production critical accounting estimates includes discussion beginning page 71 accounting estimates involve use significant assumptions andor judgments preparation financial statements business purpose provide natural gas related energy products safe efficient dependable manner interests north america’s largest interstate natural gas pipeline systems large independent natural gas oil producer focused growing reserve base disciplined capital investment portfolio management cost control marketing selling natural gas oil production optimal prices managing associated price risks factors influencing profitability pipeline operations rateregulated accordingly generate profit based ability earn return excess costs rates charge customers exploration production operations generate profits dependent prices natural gas oil volumes able produce among factors future profitability operating segments primarily influenced following factors pipelines • successfully executing backlog committed expansion projects developing new growth projects market supply areas • contracting recontracting pipeline capacity customers • maintaining obtaining approval ferc acceptable rates terms service • improving operating efficiency exploration production • increasing natural gas oil proved reserve base production volumes successful drilling programs andor acquisitions • finding producing natural gas oil reasonable cost • managing price risks optimize realized prices natural gas oil production addition factors future profitability also continue impacted debt level related interest costs successful resolution historical contingencies completing orderly exit remaining power assets historical derivative contracts remaining noncore assets summary overall performance 2007 year ended december 31 2007 marked fifth consecutive year improved profitability driven primarily strong base earnings cash flow pipeline exploration production businesses well interest expense reduction approximately 20 percent across pipeline system made progress backlog committed expansion projects created el paso pipeline partners lp master limited partnership exploration production business experienced continued success worldwide exploration drilling programs successes allowed us replace worldwide natural gas oil reserves move forward high grading portfolio improve cost structure following provides additional details items significant highlights core businesses 2007 area operations significant highlights pipelines completed entered new expansion projects resulting current backlog almost 4 billion completed sale anr michigan storage assets 50 percent interest great lakes gas transmission net cash proceeds approximately 37 billion implemented ferc approved rate case settlements el paso natural gas company mojave pipeline company completed 575 million initial public offering common units el paso pipeline partners lp newly formed master limited partnership enhance value financial flexibility pipeline assets provide lowercost source capital new pipeline growth projects reached agreement completed february 2008 acquire 50 percent interest gulf lng clean energy project constructing lng regasification terminal mississippi exploration production met production cost targets established 2007 increased production volumes quarter 2007 highgraded portfolio acquisition peoples 887 million adding proved reserves 298 bcfe progressed announced divestiture program replaced 129 worldwide natural gas oil reserves excluding acquisitions 252 including acquisitions achieved success exploration programs brazil managed price risk derivative contracts combined positions provided higher realized commodity prices 2007 gives us price protection approximately twothirds planned 2008 equivalent production addition 2007 performance impacted marketing power segments continued reduce size volatility operations corporate costs incurred conjunction simplifying strengthening balance sheet specifically incurred marktomarket losses marketing segment productionrelated option contracts legacy positions including pennsylvanianew jerseymaryland pjm power contracts ii incremental losses power segment brazilian power investments additionally 2007 incurred debt extinguishment costs approximately 291 million conjunction repurchasing refinancing 5 billion debt strengthen balance sheet ii resolved certain legal contractual disputes see item 8 financial statements supplementary data note 12 outlook 2008 expect current operating trends core pipeline exploration production businesses continue focus growing businesses business expect following pipelines anticipate pipeline operations continue provide strong operating results based expansion plans current levels contracted capacity status rate regulatory actions pipeline industry favorable macroeconomic environment supports continued industry growth expect spend significant pipeline growth capital 2008 expenditures lay foundation future growth advancement significant backlog committed expansion projects market supply areas development significant new infrastructure opportunities additionally continue pursue proposed joint venture development projects would use incumbent pipeline infrastructure connect supply areas high demand west northeast southeast finally expect grow mlp organic growth opportunities potential acquisitions future asset contributions currently excess 2 billion net operating losses available us offset potential tax gains future asset contributions mlp exploration production expect continue momentum established 2007 seek create value disciplined balanced capital investment program drilling programs focus growing reserves reasonable finding development costs growing production efficiently active cost management 2008 domestic programs constitute approximately 80 percent planned capital substantially expected production performance programs require successful integration execution 2007 acquisitions 2008 planned divestitures 2008 international capital expected increase approximately 50 percent 2007 program successful execution programs primarily brazil require effective project management partner relations successful negotiations regulatory agencies future financial results primarily dependent continued successful execution drilling programs favorable commodity prices extent anticipated natural gas oil production unhedged based current derivative positions anticipate 2008 hedging program provide protection price exposure substantial portion anticipated natural gas oil production previously described credit profile outstanding debt 128 billion december 31 2007 strengthened credit profile result several actions taken year including • reducing debt approximately 26 billion including debt discontinued anr operations primarily proceeds sale anr • refinancing approximately 20 billion debt subsidiaries sng epng epep • receiving upgraded senior unsecured debt ratings el paso ba3 positive outlook moody’s bb positive outlook standard poor’s bb fitch ratings receiving investment grade senior unsecured debt ratings pipeline subsidiaries baa3 positive outlook moody’s bb positive outlook standard poor’s investment grade rating bbb fitch ratings improvement provide us lower cost capital planned expansions pipeline business • restructuring el paso epep revolving credit facilities improved terms total capacities 15 billion 10 billion respectively • completing pipeline mlp initial public offering november 2007 providing us lower cost capital pipeline growth projects entering 750 million revolving credit facility available mlp nonrecourse el paso results operations overview december 31 2007 core operating business segments pipelines exploration production also marketing segment markets natural gas oil production manages legacy trading activities power segment interests several international power plants segments managed separately provide variety energy products services require different technology marketing strategies corporate activities include general administrative functions well miscellaneous businesses contracts assets immaterial management uses earnings interest expense income taxes ebit assess operating results effectiveness business segments consist consolidated businesses investments unconsolidated affiliates believe ebit useful investors allows evaluate operating performance using performance measure analyzed internally management define ebit net income loss adjusted items impact income loss continuing operations discontinued operations impact accounting changes ii income taxes iii interest debt expense exclude interest debt expense measure investors may evaluate operating results without regard financing methods capital structure ebit may comparable measurements used companies additionally ebit considered conjunction net income performance measures operating income operating cash flows reconciliation ebit segment consolidated net income loss three years ended december 31 discussions follow provide additional analysis year results business segments corporate activities income statement items pipelines segment overview pipelines segment operates primarily united states consists interstate natural gas transmission storage lng terminalling related services face varying degrees competition segment existing proposed pipelines proposed lng facilities well alternative energy sources used generate electricity hydroelectric power nuclear energy wind solar coal fuel oil revenues transportation storage lng terminalling related services consist two types percent total type description revenues reservation revenues customers referred firm customers reserve capacity pipeline systems storage facilities lng terminalling facilities firm customers obligated pay monthly reservation demand charge regardless amount natural gas transport store term contracts usage revenues firm customers interruptible customers without reserved capacity pay usage charges based volume gas actually transported stored injected withdrawn also earn revenues processing sale natural gas liquids miscellaneous sources ferc regulates rates charge customers rates generally function cost providing services customers including reasonable return invested capital regulated nature high percentage revenues attributable reservation charges revenues historically relatively stable however financial results subject volatility due factors changes natural gas prices market conditions regulatory actions competition weather declines creditworthiness customers also experience earnings volatility certain pipelines amount natural gas used operations differs amounts receive purpose historically much business conducted longterm contracts customers however many customers shifted traditional dependence longterm contracts portfolio approach balances shortterm opportunities longterm commitments shift increase volatility revenues due changes market conditions competition driven state utility deregulation local distribution company mergers new supply sources volatility natural gas prices demand shortterm capacity new power plant markets continue manage recontracting process limit risk significant impacts revenues expiring contracts ability extend existing customer contracts remarket expiring contracted capacity dependent competitive alternatives regulatory environment federal state local levels market supply demand factors relevant dates contracts extended expire duration new renegotiated contracts affected current prices competitive conditions judgments concerning future market trends volatility subject regulatory requirements attempt recontract remarket capacity rates allowed tariffs although discount rates various levels pipeline systems remain competitive existing contracts mature various times varying amounts throughput capacity weighted average remaining contract term active contracts approximately five years december 31 2007 contract expiration portfolio associated revenue expirations firm transportation contracts wholly majority owned systems december 31 2007 including terms beginning 2008 later november 2007 completed offering common units mlp contributed 100 percent wic wholly owned interstate pipeline transportation business located primarily wyoming colorado 10 percent equity interests cig sng mlp 2 percent general partner interest 648 percent limited partner interest mlp summary operational financial performance 2007 continued deliver strong financial performance across pipelines placed several expansion projects service including phase sng cypress project tgp louisiana deepwater link project tgp triplet extension project tgp northeast connexionnew england project mexico lpg burgos project continued make significant progress backlog expansion projects also successfully resolved epng mojave rate cases restructured renewed certain customer contracts 2007 benefited higher realized rates certain systems ii increased throughput iii increased activity various interruptible services level throughput systems provide evidence underlying longterm value system capacity 2007 increased throughput across system result broad based increases power demand mexico california northeast southeast based underlying growth electricity demand colder weather lower availability hydroelectric power northwest also experienced higher supply related throughput result rockiesrelated expansions 2008 currently plan spending 16 billion capital 12 billion targeted towards backlog expansion projects intend build growth achieved 2007 currently almost 4 billion committed expansion projects comprise backlog follows large projects development also two development projects underway recently announced ruby pipeline project northeast passage project combined projects estimated cost 4 billion 2 billion net interests estimated inservice dates 2011 projects various phases development including obtaining necessary customer commitments holding ownership discussions operating results 1 volumes exclude intrasegment activities 2 represents proportional share table discussion follows detail impact ebit significant events 2007 compared 2006 compared 2005 also provided outlook events may affect operations future 1 consists individually insignificant items several pipeline systems reservation usage revenues year ended december 31 2007 ebit favorably impacted • increase throughput pipeline systems primarily rocky mountains southern regions increased due new supply colder weather increased transportation services power plants • additional firm capacity sold south central region tgp system • increased rates cig system effective october 2006 result cig’s rate settlement partially offsetting favorable impacts 2007 expiration certain firm transportation contracts epng mpc sng systems increase reservation usage revenues 2006 compared 2005 primarily due • expiration reduced epng tariff rates effective december 31 2005 certain customers terms epng’s fercapproved system wide capacity allocation proceeding • increase epng’s tariff rates effective january 1 2006 result rate filing • sales additional firm capacity higher realized rates several pipeline systems 2006 • increased activity pipeline systems various interruptible services provided tariffs result favorable market conditions expansions 2007 2006 reservation revenues throughput volumes increased due projects placed service discussion expansion projects placed service projects placed service 2007 2006 2007 placed several expansion projects service including phase cypress project louisiana deepwater link project triplet extension project northeast connexionnew england project mexico lpg burgos project 2006 placed several expansion projects service including cheyenne plains yuma lateral project elba island lng expansion piceance basin project wic system projects placed service 2008 january 2008 completed wic kanda lateral project increase annual revenues approximately 25 million gas used operations revaluations processing revenues natural gas sales year ended december 31 2007 ebit unfavorably impacted revaluation net gas imbalances gas owed customers cig wic systems result increasing natural gas prices 2007 versus decreasing natural gas prices 2006 ii lower processing revenues operational gas costs cig system due decrease processing volumes natural gas liquids partially offsetting unfavorable impacts 2007 higher volumes gas used tgp’s operations 2006 higher realized prices sales gas used operations resulted favorable impacts operating revenues partially offset lower sales volumes natural gas used operations 2006 compared 2005 also experienced favorable impacts operating expenses 2006 due decreases index prices used value net imbalance position several pipeline systems 2005 higher gas prices caused increase obligation replace system gas settle gas imbalances future resulting unfavorable impact 2005 operating results addition pipelines also retained lower volumes gas used operations 2005 anticipate overall activity area continue vary based factors volatility natural gas prices efficiency pipeline operations regulatory actions factors hurricanes katrina rita 2007 incurred lower operation maintenance expenses repair damage caused hurricanes katrina rita compared 2006 recorded higher operation maintenance expenses compared 2005 result unreimbursed amounts expended repair hurricane damage anticipate expenditures related hurricanes net related reimbursements materially impact future financial results asset impairments 2007 recorded 10 million impairment certain pipeline assets originally purchased repair certain offshore hurricane damage following decision use assets addition recorded loss approximately 9 million pursuant ferc determination accounting treatment pending sale certain transmission facilities 2006 2005 impaired various pipeline development projects based changing market conditions 2006 impairments included 13 million 3 million due discontinuing continental connector pipeline project remainder seafarer project 2005 recorded impairments 18 million 28 million due discontinuing portion seafarer project entirety blue atlantic development project general administrative expenses year ended december 31 2007 general administrative expenses higher 2006 primarily due increased insurance costs wind damage pipeline assets located primarily gulf mexico region general administrative costs lower 2006 2005 primarily due decrease accrued benefit costs lower allocated costs el paso based estimated level resources devoted pipeline segment relative size ebit gross property payroll compared consolidated totals depreciation expense depreciation expense higher 2006 compared 2005 primarily due higher depreciation rates applied epng’s property plant equipment following 2006 rate case operating costs including pipeline integrity 2007 incurred higher operating costs 2006 primarily due increased repair maintenance costs allowances nontrade accounts receivable environmental reserves 2006 incurred higher costs 2005 primarily repairs maintenance 19 million pipeline integrity costs began expensing 2006 result adoption accounting release issued ferc bankruptcy settlements 2007 received 10 million settle bankruptcy claim usgen new england inc 2007 2006 recorded income approximately 5 million 18 million net amounts potentially owed certain customers related amounts recovered enron bankruptcy settlement february 2008 received portion bankruptcy settlement calpine corporation’s approved plan reorganization connection plan received calpine common stock market value approximately 29 million recognize gain first quarter 2008 equity earnings citrus year ended december 31 2007 equity earnings citrus investment increased primarily due favorable settlement approximately 8 million litigation brought spectra lng sales formerly duke energy lng sales inc wrongful termination gas supply contract ii citrus’ sale receivable approximately 3 million related bankruptcy enron north america iii favorable operating results approximately 8 million florida gas transmission company pipeline owned 100 percent citrus due higher system usage lower operating costs regulatory mattersrate cases pipeline systems periodically file changes rates subject approval ferc changes rates tariff provisions resulting regulatory proceedings potential positively negatively impact profitability currently certain pipelines requirements file new rate cases 2008 expect continue operating existing rates certain pipelines recently completed rate proceedings upcoming rate actions including following • cigwic august 2007 cig filed tariff change ferc modify fuel recovery mechanism recover cost impacts flow shippers revenue impacts fuel imbalance revaluations related gas balance items cig currently experiences variability cash flow earnings fuel recovery mechanism earnings variability price fluctuations substantially reduced ferc approves fuel tracker tariff filing protested certain shippers ferc suspended effective date march 1 2008 subject similar outcome technical conference proposed tariff change held november 2007 september 2007 wic filed tariff change ferc tariff filing protested certain shippers ferc suspended effective date april 1 2008 subject outcome technical conference proposed tariff change held november 2007 comments proposals filed various parties proceedings action yet taken ferc relative proceedings exploration production segment overview strategy exploration production segment conducts natural gas oil exploration production activities profitability performance segment driven ability locate develop economic natural gas oil reserves extract reserves lowest possible production administrative costs accordingly manage business goal creating value disciplined capital allocation cost control portfolio management domestic natural gas oil reserve portfolio blends slower decline rate typically longer lived assets onshore region steeper decline rate shorter lived assets texas gulf coast gulf mexico south louisiana regions believe combination assets domestic regions provides significant nearterm cash flow providing consistent opportunities competitive investment returns addition international activities brazil egypt provide opportunity additional future reserve additions longer term cash flows part business strategy attempt create value balance drilling activities exploration acquisitions assets companies 2008 expect growth occur principally drilling activities continue evaluate acquisition growth opportunities tightly focused around core competencies areas competitive advantage believe strategic acquisitions support corporate objectives • reshaping portfolio provide greater opportunities achieve long term performance goals • leveraging operational expertise already possess key operating areas geologies techniques • balancing exposure regions basins commodities • achieving riskadjusted returns competitive available within existing inventory • increasing reserves rapidly supplementing current drilling inventory september 2007 acquired peoples provided upgrade portfolio assets also upgrading portfolio selling selected properties january 2008 entered agreements sell 517 million certain noncore properties onshore texas gulf coast regions estimated proved reserves 191 bcfe december 31 2007 sales expected close first quarter 2008 expect upgrading portfolio extend reserve life assets reduce unit operation maintenance costs increase predictability improve capital efficiency expand depth inventory addition executing strategy profitability performance exploration production operations substantially impacted changes commodity prices ii industrywide increases drilling oilfield service costs iii effect hurricanes weather impacts daily production operating capital costs extent possible attempt mitigate factors part risk management activities entered derivative contracts significant portion anticipated 2008 natural gas oil production reduce financial impact downward commodity price movements significant operational factors affecting year ended december 31 2007 production average daily production year 792 mmcfed including 70 mmcfed share production equity investment four star production levels grew every quarter 2007 analysis 2007 production region mmcfed onshore region 2007 production continued increase capital projects maintained increased production major operating areas majority growth coming rockies arklatex areas peoples acquisition september 2007 also contributed production volume increases year texas gulf coast region acquisition properties zapata county first quarter 2007 success drilling program offset natural production declines sale certain nonstrategic south texas properties 2006 peoples acquisition september 2007 also contributed production volume increases year gulf mexico south louisiana region began producing development wells western gulf south louisiana several exploratory discoveries occurring prior 2007 also recovered volumes previously shutin hurricane damage coupled new production sources helped offset natural production declines brazil production volumes decreased 2007 due natural production declines contractual reduction ownership interest pescadaarabaiana fields early 2006 four star original ownership interest four star obtained medicine bow acquisition august 2005 january 2007 four star acquired properties added production approximately 5 mmcfed net interest acquisition date third quarter 2007 spent 27 million increase ownership interest four star 43 percent 49 percent 2007 drilling results onshore realized 99 percent success rate 502 gross wells drilled texas gulf coast experienced 92 percent success rate 84 gross wells drilled gulf mexico south louisiana drilled six successful wells seven unsuccessful wells brazil currently 100 percent bmcal4 concession camamu basin 2007 completed drilling two successful exploratory wells south pinauna field concession extends southern limits pinauna project currently assessing development options process underway potentially market 50 percent nonoperating interest concession addition completed drilling testing two exploratory wells petrobras es5 block espirito basin wells confirmed extension earlier discovery petrobras block south currently negotiations petrobras unitization agreement development discovery egypt 2007 received formal government approval signed concession agreement south mariut block approximately 12 million acres located onshore western part nile delta paid 3 million concession agreed 22 million firm working commitment three years currently performing seismic evaluations block expect drill first exploratory well late 2008 cash operating costs monitor cash operating costs required produce natural gas oil volumes costs calculated per mcfe basis include total operating expenses less depreciation depletion amortization expense noncash expense items cost products services income statement 2007 cash operating costs per unit increased 188mcfe compared 186mcfe 2006 operating costs increased primarily result higher production taxes increased due higher natural gas oil reserves lower severance tax credits higher marketing costs higher corporate overhead allocations reserve replacement costsreserve replacement ratio calculate two primary metrics reserve replacement ratio ii reserve replacement costs measure ability establish longterm trend adding reserves reasonable cost core asset areas reserve replacement ratio indicator ability replenish annual production volumes grow reserves important us economically find develop new reserves offset produced volumes provide future production given inherent decline hydrocarbon reserves addition calculate reserve replacement costs assess cost adding reserves ultimately included depreciation depletion amortization expense believe ability develop competitive advantage natural gas oil companies dependent adding reserves core asset areas lower cost competition calculate metrics follows reserve replacement ratio sum reserve additions1 actual production corresponding period 1 reserve additions include proved reserves reflect reserve revisions extensions discoveries additions acquisitions include unproved reserve quantities proved reserve additions attributable investments accounted using equity method amounts derived directly table presented item 8 financial statements supplementary data supplemental natural gas oil operations 2 total oil gas capital costs include costs development exploration property acquisition activities conducted add reserves exclude asset retirement obligations amounts derived directly table presented item 8 financial statements supplementary data supplemental natural gas oil operations reserve replacement ratio reserve replacement costs per unit statistical indicators limitations including predictive comparative value annual measure reserve replacement ratio limited typically varies widely based extent timing new discoveries project sanctioning property acquisitions addition since reserve replacement ratio consider cost timing future production new reserves cannot used measure value creation exploration acquisition development natural gas oil reserves inherently uncertain discussed part item 1a risk factors risks related business one risks uncertainties ability spend sufficient capital increase reserves currently expect spend amounts future assurances timing magnitude expenditures classification proved reserves developed undeveloped december 31 2007 proved developed reserves represent approximately 71 percent total proved reserves proved developed reserves generally begin producing within year added whereas proved undeveloped reserves generally require major future expenditure table shows reserve replacement costs reserve replacement ratio domestic worldwide operations years ended december 31 2007 domestic reserve replacement costs decreased primarily due favorable acquisitions finding development costs upward revisions previous estimates reserves due higher commodity prices december 31 2007 typically cite reserve replacement costs context multiyear trend recognition limitation single year measure also demonstrate consistency stability essential business model three year period ending december 31 2007 average reserve replacement costs domestic worldwide operations 331mcfe 340mcfe including acquisitions 364mcfe 375mcfe excluding acquisitions capital expenditures capital expenditures follows three years ended december 31 1 total oil gas capital costs include costs development exploration property acquisition activities conducted add reserves exclude asset retirement obligations amounts derived directly table presented item 8 financial statements supplementary data supplemental natural gas oil operations outlook 2008 anticipate following worldwide basis • average daily production volumes year approximately 805 mmcfed 860 mmcfed excludes approximately 65 mmcfed 70 mmcfed equity investment four star • capital expenditures excluding acquisitions approximately 17 billion approximately 80 company’s planned 2008 capital program allocated domestic program plan spend approximately 350 million international capital 2008 primarily brazil exploration development program part domestic capital program allocate greater percentage capital onshore texas gulf coast regions light announced divestiture plans • average cash operating costs include production costs general administrative expenses approximately 175mcfe 190mcfe year • depreciation depletion amortization rate 280mcfe 320mcfe price risk management activities part strategy enter derivative contracts natural gas oil production stabilize cash flows reduce risk financial impact downward commodity price movements commodity sales protect economic assumptions associated capital investment programs strategy partially reduces exposure downward movements commodity prices reported results operations financial position cash flows impacted significantly movements commodity prices period adjustments hedging strategy decision enter new positions alter existing positions made corporate level based goals overall company following table discussion follows shows december 31 2007 contracted volumes minimum maximum average prices receive contracts combined sale underlying hedged production 1 volumes presented tbtu natural gas mbbl oil prices presented per mmbtu natural gas per bbl oil 2 basis swaps effectively limit exposure differences nymex gas price location sell gas average prices listed amounts pay per mmbtu relative nymex price “lockin” locational differences oil fixed price swaps 86 percent natural gas fixed price swaps option contracts designated accounting hedges gains losses associated natural gas contracts deferred accumulated comprehensive income recognized earnings upon sale related production market prices resulting realized price approximately equal hedged price regard natural gas positions approximately 7 tbtu fixed price swaps 15 tbtu option contracts basis swaps designated accounting hedges accordingly changes fair value derivatives recognized earnings period january february 2008 entered 47 tbtu options anticipated 2008 natural gas production floor price 800 per mmbtu average ceiling price 1064 per mmbtu ii 7 tbtu options anticipated 2009 natural gas production floor price 800 per mmbtu ceiling price 1105 per mmbtu iii 292 mbbls fixed price swaps anticipated 2008 oil production price 9900 per barrel contracts designated accounting hedges except 19 tbtu 2008 natural gas option contracts total positions provides price protection approximately twothirds planned 2008 equivalent production additionally table include contracts entered marketing segment described segment consolidated impact entirety el paso’s productionrelated price risk management activities overall liquidity see discussion factors could impact liquidity capital resources operating results variance analysis tables discussion follows provide operating results analysis significant variances results periods ended december 31 1 includes equity earnings investment four star 1 production taxes include ad valorem severance taxes year ended december 31 2007 compared year ended december 31 2006 ebit 2007 increased 269 million compared 2006 table lists significant variances operating results 2007 compared 2006 operating revenues 2007 revenues increased compared 2006 due higher realized natural gas oil prices including effects hedging program realized gains hedging transactions 177 million 2007 compared losses 58 million 2006 2007 also benefited increase production volumes domestic regions 2006 revenue 2007 recognized marktomarket gains 7 million compared losses 40 million 2006 related change fair value derivatives designated hedges including portion oil natural gas fixed price swaps option contracts basis swaps depreciation depletion amortization expense 2007 depletion rate increased compared periods 2006 result peoples zapata county texas property acquisitions higher finding development costs production costs production taxes increased 2007 compared 2006 primarily due higher natural gas oil revenues lower severance tax credits 2007 general administrative expenses general administrative expenses increased 2007 compared 2006 primarily due higher marketing costs previously included marketing segment higher corporate overhead allocations year ended december 31 2006 compared year ended december 31 2005 ebit 2006 decreased 56 million compared 2005 table lists significant variances operating results 2006 compared 2005 operating revenues natural gas revenues decreased approximately 197 million natural gas prices strong 2006 compared 2005 however experienced lower hedging program losses 2006 58 million compared losses 260 million 2005 realized oil condensate ngl prices increased 2006 compared 2005 production volumes benefited 2006 acquisitions 2005 however overall production volumes decreased texas gulf coast gulf mexico south louisiana regions due natural declines sale certain nonstrategic south texas properties average production 5 mmcfed 2006 also gulf mexico south louisiana region production continued impacted 2006 hurricanes katrina rita occurred late 2005 production volumes brazil decreased due contractual reduction ownership interest pescadaarabaiana fields 2006 depreciation depletion amortization expense 2006 experienced higher depletion rates compared 2005 primarily result higher finding development costs cost acquired reserves however lower production volumes 2006 partially offset impact higher depletion rates production costs 2006 lease operating costs increased compared 2005 regions result inflation fuel costs power services onshore region additional increases due increased subsurface maintenance acquisition medicine bow gulf mexico region additional increases due hurricane repairs recoverable insurance additionally production taxes increased result lower tax credits texas taken 2006 compared 2005 general administrative expenses general administrative expenses decreased 2006 compared period 2005 primarily due lower corporate overhead allocations 2006 recorded loss approximately 40 million fair value derivatives designated hedges compared 9 million loss 2005 2006 ebit also unfavorably impacted earnings four star due lower natural gas prices ebit favorably impacted operations processing plants insurance recoveries resulting hurricane ivan among items marketing segment marketing segment’s primary focus market exploration production segment’s natural gas oil production manage company’s overall price risks primarily use natural gas oil derivative contracts addition continue manage liquidate remaining legacy natural gas supply transportation power natural gas contracts entered prior deterioration energy trading environment 2002 future liquidations may impact cash flows financial results however may liquidate certain remaining legacy contracts expiration uneconomical sell terminate current environment due terms credit concerns counterparty lack liquidity market ii sale would require acceleration cash demands table follows provides description remaining contracts remaining exposure contracts marktomarket contracts subject interest rate exposure interest rates used determining fair market values subject change period contract type description remaining exposure marktomarket productionrelated natural gas oil derivatives option contracts various floor ceiling prices changes natural gas oil prices power contracts pennsylvanianew jerseymaryland pjm basis installed capacity positions changes regional power prices installed capacity prices pjm commodity contracts counterparty credit commodity positions hedged pjm west hub natural gas contracts fixedprice indexpriced physical delivery contracts fixedforfloat swaps counterparty credit commodity positions flattened result transactions entered 2006 2007 accrual transportationrelated natural gas contracts pipeline capacity contracts locational differences natural gas prices could affect ability use capacity recover demand charges exposure future losses reduced significantly due releasing assigning capacity related alliance pipelines 2006 2007 longterm gas supply obligations primarily four contracts delivery obligations 03 bcfd expiration dates ranging 2011 2028 indexpriced contracts exposed locational changes natural gas prices operating results overview past three years operating results yeartoyear comparability impacted significant commodity market fluctuations changes composition portfolio related effort manage portfolio based actions taken reduce exposure exit legacy trading activities tables discussions follow provide information events overall operating results analysis significant contract type marketing segment three years ended december 31 2007 results primarily driven marktomarket losses productionrelated option contracts legacy natural gas power positions including pjm contracts losses partially offset 23 million income recognized upon sale investment nymex 28 million ebit 23 million revenues 5 million income related settlement outstanding california power price disputes 2006 2005 financial results significantly impacted • marktomarket gains losses productionrelated natural gas oil derivative contracts • divestiture 2006 significant portion natural gas portfolio • termination payment 2006 188 million third party assume alliance transportation capacity obligations effective november 1 2007 • losses 2006 based changes fair value natural gas derivative contracts including approximately 133 million previously unrecorded losses midland cogeneration venture mcv supply agreement conjunction sale interest facility • divestitures 2005 cordova tolling agreement majority contracts power portfolio productionrelated natural gas oil derivative contracts options contracts productionrelated natural gas oil derivative contracts designed provide protection el paso changes natural gas oil prices addition derivative contracts entered exploration production segment described discussion segment consolidated impact el paso’s productionrelated price risk management activities refer liquidity capital resources discussion fair value derivative contracts impacted changes commodity prices periodtoperiod markedtomarket results listed volumes average prices associated productionrelated derivative contracts december 31 2007 1 volumes presented tbtu natural gas mbbl oil prices presented per mmbtu natural gas per bbl oil experience volatility financial results based changes fair value option contracts generally move opposite direction changes forward commodity prices 2007 2005 increases forward commodity prices reduced fair value option contracts resulting loss 2006 decreases forward commodity prices increased fair value option contracts resulting gain received approximately 45 million 59 million 2007 2006 paid 40 million 2005 contracts settled periods contracts related legacy trading operations natural gas transportationrelated contracts december 31 2007 transportation contracts provide us approximately 06 bcfd pipeline capacity recovery demand charges related transportation contracts therefore profitability contracts dependent upon ability use remarket contracted pipeline capacity impacted number factors including differences natural gas prices contractual receipt delivery locations working capital needed use capacity required meet long term obligations november 2007 future earnings exposure relating transportation contracts reduced transfer alliance capacity third party december 31 2007 contracts require us pay demand charges approximately 41 million 2008 average 24 million 2009 2012 transportation contracts accounted accrual basis impact revenues delivery service contracts occurs following table summary demand charges millions percentage recovery charges three years ended december 31 natural gas derivative contracts 2006 divested entered transactions divest substantial portion natural gas contracts substantially reduced exposure price movements contracts however maintain contracts third parties require us purchase deliver natural gas primarily market prices including gas supply contract mcv power facility additionally recognized 49 million gain 2006 associated assignment certain natural gas derivative contracts supply natural gas southeastern us 2006 conjunction sale mcv facility power segment recorded cumulative mark market loss approximately 133 million previously recognized due affiliated ownership interest power contracts end 2005 substantially eliminated exposure power price movements legacy power contracts prior eliminating price risk experienced significant net decreases fair value contracts based primarily changes natural gas power prices well differences locational power prices remaining exposure power portfolio related several contracts require us swap locational differences power prices power plants pennsylvanianew jerseymaryland pjm eastern region pjm west hub provide installed capacity pjm power pool 2016 fair value contracts decreased approximately 100 million 2007 increased approximately 70 million 2006 losses 2007 primarily result increasing installed capacity prices pjm region gains 2006 primarily related locational price differences regions end 2006 eliminated commodity price risk associated contracts 2007 pjm independent system operator began conducting periodic auctions set prices providing installed capacity customers pjm power pool fair value power contracts impacted changes installed capacity prices based part result auctions results future auctions potential developments contracts pjm marketplace may result future volatility operating results estimate ten percent change auction prices recent capacity price 174mwday would change fair value contracts approximately 5 million 2005 bankruptcy court entered order allowing mohawk river funding iii’s subsidiary’s bankruptcy claims usgen new england received payment claims recognized gain 17 million 2005 income related settlement power segment overview power segment consists assets brazil asia central america continue pursue sales remaining power investments december 31 2007 remaining investment guarantees letters credit related projects segment totaled approximately 548 million consisted approximately 514 million equity investments notes receivable approximately 34 million financial guarantees letters credit follows operating results 2007 results primarily negatively impacted impairment losses brazil related porto velho manaus rio negro projects prior 2006 financial results segment significantly impacted impairments net gains losses sale domestic international power facilities discussion events factors impacting results segment three years ended december 31 listed brazil 2007 porto velho project manaus rio negro projects brazilian operations including interests boliviatobrazil argentinatochile pipelines generated ebit losses 27 million ebit losses 6 million ebit 12 million respectively 2007 results included charges 57 million porto velho 15 million manaus rio negro based adverse developments projects 2006 2005 ebit 41 million 23 million porto velho 17 million 19 million manaus rio negro 6 million 13 million brazilian operations discussion matters impacted could impact brazilian investments see item 8 financial statements note 17 international power 2005 recorded impairments 176 million significantly offset gains sales assets 131 million based value received expected received upon closing sales assets asia central america results also impacted decision recognize earnings assets planned sell based inability realize earnings expected selling price recognize earnings approximately 10 million 26 million 30 million years ended 2007 2006 2005 continue pursue sale remaining investments asia central america sales completed changes regional political economic conditions could negatively impact anticipated proceeds may receive could result additional impairments investments domestic power 2006 completed disposition domestic power business recorded gain segment approximately 10 million primarily related sale investment mcv disposition investment mcv 2006 also impacted certain contracts financial results marketing segment prior 2006 sold interests several domestic power facilities restructured power contracts resulting significant impairments substantially lower earnings operations addition recorded proportionate share mcv’s losses based impairment plant assets 2005 field services prior january 1 2006 field services segment 2005 generated ebit 285 million among items primarily due gain 183 million sale general partner limited partner interests enterprise products partners lp gain 111 million sale javelina processing operations corporate expenses net corporate activities include general administrative functions well number miscellaneous businesses qualify operating segments material current year results following summary significant items impacting ebit corporate activities three years ended december 31 extinguishment debt 2007 incurred losses 291 million conjunction repurchasing refinancing 5 billion debt amount included 86 million related repurchasing epep’s 12 billion notes information debt see item 8 financial statements note 11 litigation insurance reserves 2007 recorded gain approximately 77 million reversal liability related coastal corporation’s legacy crude oil marketing trading business discussion matter see item 8 financial statements note 12 also number pending litigation matters us matters evaluate lawsuit claim merits defenses adverse rulings unfavorable settlements us related matters impacted results 2007 2006 may impact future results 2005 recorded significant charges operation maintenance expense increase litigation insurance reserves based ongoing assessments developments evaluations possible outcomes matters 2005 significant item charge connection ruling appellate court indemnify former subsidiary certain payments made retiree benefit plan additionally 2005 incurred charges 72 million primarily related final prepayment western energy settlement additional charges related increased premiums mutual insurance company participate based primarily impact several hurricanes 2005 interest debt expense interest debt expense approximately 10 billion 12 billion 13 billion years ended december 31 2007 2006 2005 total interest debt expense decreased past three years primarily due retirements debt financing obligations net issuances see part ii item 8 financial statements supplementary data note 11 discussion income taxes 2007 overall effective tax rate continuing operations period differed statutory rate due primarily earnings unconsolidated affiliates anticipate receiving dividends qualify dividend received deduction 2006 2005 recorded 159 million 58 million tax benefits based primarily conclusion irs audits 2006 audits coastal corporation’s 19982000 tax years el paso’s 2001 2002 tax years concluded resulted reduction tax contingencies reinstatement certain tax credits 2005 finalized coastal corporation’s irs tax audits years prior 1998 discussion effective tax rates tax matters see part ii item 8 financial statements supplementary data note 4 discontinued operations discontinued operations years presented primarily include anr pipeline related assets gathering processing operations south louisiana certain international power operations year ended december 31 2007 income discontinued operations 674 million primarily result gain sale anr related operations 648 million net income taxes 354 million years ended december 31 2006 2005 losses discontinued operations 56 million 96 million 2006 loss 56 million primarily result recording approximately 188 million deferred taxes upon agreeing sell stock anr michigan storage assets 50 percent interest great lakes gas transmission prior decision sell required record deferred taxes individual assets liabilities portion investment stock one companies 2005 loss 96 million primarily result impairments discontinued international power operations partially offset income anr related assets gain sale south louisiana operations items discussed part ii item 8 financial statements supplementary data note 2 commitments contingencies discussion commitments contingencies see part ii item 8 financial statements supplementary data note 12 liquidity capital resources sources uses cash primary sources cash flow operations amounts available us revolving credit facilities occasion conditions warrant may also generate funds capital market activities proceeds asset sales primary uses cash funding capital expenditure programs pipeline exploration production operations meeting operating needs repaying debt due repurchasing certain debt obligations conditions warrant overview cash flow activities 2007 generated positive operating cash flow approximately 18 billion primarily result cash provided pipeline exploration production operations also sold anr pipeline related assets generated 37 billion net proceeds utilized operating cash flow cash sale anr fund maintenance growth projects pipeline exploration production operations reduce debt obligations see item 8 financial statements note 11 november 2007 issued units master limited partnership generating gross proceeds 575 million initial public offering year ended december 31 2007 2006 cash flows continuing operations summarized follows contribution cash generated discontinued operations reflected consists following year ended december 31 2007 credit profile substantial repayment debt obligations 2007 improved credit profile credit ratings march 2007 moody’s investor services upgraded pipeline subsidiaries’ senior unsecured debt rating investment grade rating baa3 upgraded el paso’s senior unsecured debt rating ba3 maintaining positive outlook additionally march 2007 standard poor’s upgraded pipeline subsidiaries’ senior unsecured debt rating bb upgraded el paso’s senior unsecured debt rating bb maintaining positive outlook ii fitch ratings initiated coverage el paso assigning rating bb senior unsecured debt investment grade rating bbb pipeline subsidiaries’ senior unsecured debt improvement provide us lower cost capital planned expansion projects pipeline business addition 2007 restructured el paso el paso exploration production revolving credit agreements improved terms pricing refinanced approximately 20 billion epep sng epng debt providing us lower cost debt less restrictive covenants also established pipeline mlp provides us lower cost capital allows us better compete expansion projects pipeline business expect grow mlp organic growth accretive acquisitions third parties el paso liquiditycash flow outlook 2008 expect continue generate positive operating cash flows also anticipate generating 1 billion upon completion asset divestitures conjunction high grading exploration production asset portfolio completing remaining international power asset sales anticipate using cash proceeds exploration production divestitures repay debt first quarter 2008 expect use cash operations remaining sales proceeds primarily working capital requirements expected capital expenditures approximately 03 billion debt matures december 31 2008 currently intend refinancing additionally previously announced intention repurchase debt approximately 05 billion cig sng december 2007 repurchased approximately 02 billion anticipate completing remaining 03 billion repurchases first half 2008 planned cash capital expenditures 2008 follows 1 relates primarily building renovations corporate facilities factors could impact future liquidity based simplification capital structure businesses reduced amount liquidity needed normal course business however liquidity needs could increase decrease based certain factors described others listed part 1 item 1a risk factors include limited completion planned asset sales effect debt level investment grade credit ratings could cost capital ability access capital markets operating costs primarily margining requirements related derivative positions adverse changes domestic economic conditions including recession economic slowdown could also impact demand natural gas transportation services ultimately impact planned growth capital price risk management activities cash margining requirements exploration production marketing segments derivative contracts provide price protection portion anticipated natural gas oil production following table shows contracted volumes minimum maximum average cash prices receive derivative contracts combined sale underlying production december 31 2007 cash prices may differ income impacts derivative contracts depending whether contracts designated hedges accounting purposes individual segment discussions provide additional information income impacts derivative contracts 1 volumes presented tbtu natural gas mbbl oil prices presented per mmbtu natural gas per bbl oil 2 basis swaps effectively limit exposure differences nymex gas price location sell gas average prices listed amounts pay per mmbtu relative nymex price “lockin” locational price differences january february 2008 entered 47 tbtu options anticipated 2008 natural gas production floor price 800 per mmbtu average ceiling price 1064 per mmbtu ii 7 tbtu options anticipated 2009 natural gas production floor price 800 per mmbtu ceiling price 1105 per mmbtu iii 292 mbbls fixed price swaps anticipated 2008 oil production price 9900 per barrel currently post letters credit required margin derivative contracts historically required post cash margin deposits amounts 2007 approximately 90 million posted cash margin deposits returned us resulting settlement related contracts changes commodity prices 2008 based current prices expect approximately 02 billion total 10 billion collateral outstanding december 31 2007 returned us primarily form letters credit depending changes commodity prices could required post additional margin may recover margin earlier anticipated based derivative positions december 31 2007 010mmbtu increase price natural gas would result increase margin requirements approximately 14 million consists 5 million transactions settle 2008 3 million transactions settle 2009 6 million transactions settle 2010 thereafter 250 million unsecured contingent letter credit facility available us average nymex gas price strip remaining calendar months march 2008 reaches 1175 per mmbtu described item 8 financial statements note 11 offbalance sheet arrangements enter variety financing arrangements contractual obligations referred offbalance sheet arrangements include guarantees letters credit interests variable interest entities guarantees involved joint ventures ownership arrangements sometimes require additional financial support form financial performance guarantees financial guarantee obligated make payments guaranteed party fails make payments violates terms financial arrangement performance guarantee provide assurance guaranteed party execute terms contract required perform behalf example guaranteed party required purchase services third party fails would required either purchase services make payments third party compensate losses incurred nonperformance also periodically provide indemnification arrangements related assets businesses sold arrangements include limited indemnifications income taxes resolution existing disputes environmental matters necessary expenditures ensure safety integrity assets sold potential exposure guarantee indemnification agreements range specified amount unlimited dollar amount depending nature claim particular transaction arrangements specified dollar amount maximum stated value approximately 785 million indemnified third parties 15 million amounts exclude guarantees issued related letters credit discussed note 11 included maximum stated value approximately 438 million related indemnification arrangements associated sale anr related operations approximately 119 million related tax matters related interest indemnifications guarantees arising sale macae power facility december 31 2007 recorded obligations 51 million related guarantees indemnification arrangements 8 million related anr related assets macae unable estimate maximum exposure guarantee indemnification agreements limit amount future payments due uncertainty exposures addition exposures described trial court ruled upheld appeal required indemnify third party benefits paid closed group retirees one former subsidiaries liability approximately 379 million associated estimated exposure matter december 31 2007 discussion matter see part ii item 8 financial statements supplementary data notes 12 13 letters credit enter letters credit ordinary course operations well periodically conjunction sales assets businesses december 31 2007 outstanding letters credit approximately 13 billion including 10 billion letters credit securing recorded obligations related price risk management activities interests variable interest entities interests several variable interest entities primarily investments held power segment variable interest entity legal entity whose equity owners sufficient equity risk controlling financial interest entity required consolidate entities allocated majority variable interest entity’s losses return including fees paid entity december 31 2007 consolidate six variable interest entities since primary beneficiary variable interest entity’s operations additional information regarding interests entities see part ii item 8 financial statements supplementary data note 17 investments earnings transactions unconsolidated affiliates contractual obligations party various contractual obligations include offbalance sheet arrangements described portion obligations reflected financial statements longterm debt liabilities commoditybased derivative contracts accrued liabilities obligations demand charges transportation storage commitments operating leases capital commitments reflected balance sheet following table discussion follows summarizes contractual cash obligations december 31 2007 periods presented amounts undiscounted except liabilities commoditybased derivative contracts long term financing obligations principal interest debt obligations included represent stated maturities unless otherwise puttable us prior stated maturity date contractual interest payments shown stated maturity date related debt discussion debt obligations see item 8 financial statements supplementary data note 11 liabilities commoditybased derivative contracts amounts include fair value price risk management liabilities fair value commoditybased price risk management assets 303 million december 31 2007 reflected amounts also excluded margin deposits held associated contracts amounts discussion commoditybased derivative contracts see discussion commoditybased derivative contracts contractual liabilities included amount contractual environmental obligations included current noncurrent liabilities balance sheet excluded amounts expected contributions pension postretirement benefit plans expected contributions contractually required information expected contributions pension post retirement benefit plans see part ii item 8 financial statements supplementary data note 13 also excluded potential amounts due indemnification former subsidiary benefits paid closed group retirees liability approximately 379 million related litigation associated matter december 31 2007 also excluded amounts liabilities unrecognized tax benefits 157 million december 31 2007 since cannot reasonably estimate time frame amounts may resolved operating leases discussion obligations see part ii item 8 financial statements supplementary data note 12 contractual commitments purchase obligations contractual commitments purchase obligations defined legally enforceable agreements purchase goods services fixed minimum quantities fixed minimum variable price provisions detail approximate timing underlying obligations included following • transportation storage commitments included amounts commitments demand charges firm access natural gas transportation storage capacity • commitments included amounts commitments drilling seismic activities exploration production operations various maintenance engineering procurement construction contracts well service license agreements used operations excluded asset retirement obligations reserves litigation environmental remediation selfinsurance claims liabilities contractually fixed timing amount commoditybased derivative contracts use derivative financial instruments exploration production marketing segments manage price risk commodities tables derivatives designated hedges primarily consist options swaps used hedge natural gas production commoditybased derivative contracts relate derivative contracts designated hedges options swaps natural gas power purchase supply contracts following table details fair value commoditybased derivative contracts year maturity valuation methodology december 31 2007 1 positions traded active exchanges new york mercantile exchange international petroleum exchange london clearinghouse following reconciliation commoditybased derivatives years ended december 31 2007 2006 fair value contract settlements fair value contract settlements period represents estimated amounts derivative contracts settled physical delivery commodity claim cash accounts receivable payable fair value contract settlements also includes physical financial contract terminations due counterparty bankruptcies sale settlement derivative contracts early termination sale entities contracts including amounts received sale option contracts changes fair value contracts change fair value contracts year represents change value contracts beginning period date origination acquisition settlement early termination settled terminated end period 2006 change fair value also includes loss natural gas supply agreements related mcv upon sale interest facility assignment contracts 2006 sold entered offsetting derivative transactions eliminate price risk associated substantial portion remaining historical natural gas derivatives paid proceeds approximately 32 million related transaction designation reclassifications hedges 2006 removed hedging designation certain derivative contracts experienced decreases related anticipated hedged production volumes brazil also 2006 designated certain existing commoditybased derivatives hedges anticipated 2007 natural gas production critical accounting estimates significant accounting policies described note 1 consolidated financial statements included item 8 annual report form 10k preparation financial statements conformity generally accepted accounting principles requires management select appropriate accounting estimates make estimates assumptions affect reported amount assets liabilities revenue expenses disclosures contingent assets liabilities consider critical accounting estimates require difficult complex subjective judgment necessary accounting inherently uncertain matters could significantly influence financial results based changes judgments changes facts circumstances may result revised estimates actual results may differ materially estimates discussed development selection following critical accounting estimates related disclosures audit committee board directors accounting natural gas oil producing activities estimates proved reserves reflect quantities natural gas oil ngl geological engineering data demonstrate reasonable certainty recoverable future years known reservoirs existing economic conditions natural gas oil reserves estimates underlie number accounting estimates financial statements process estimating natural gas oil reserves particularly proved undeveloped proved nonproducing reserves complex requiring significant judgment evaluation available geological geophysical engineering economic data reserve estimates developed internally reserve reporting group separate operations group reviewed internal committees internal auditors addition thirdparty reservoir engineering firm appointed reports audit committee board directors conducted audit estimates significant portion proved reserves scope audit performed ryder scott included preparation independent estimate proved natural gas oil reserves estimates fields comprising greater 80 percent total worldwide present value future cash flows pretax specific fields included ryder scott’s audit represented largest fields based value december 31 2007 total proved reserves 29 percent undeveloped 13 percent developed nonproducing data given field may change substantially time result numerous factors including additional development activity evolving production history continual reassessment viability production changing economic conditions result material revisions existing reserve estimates occur time addition subjective decisions variances available data various fields increase likelihood significant changes estimates proved natural gas oil reserves primarily impact property plant equipment amounts balance sheets depreciation depletion amortization amounts income statements among items use full cost method account natural gas oil producing activities accounting method capitalize substantially costs incurred connection acquisition exploration development natural gas oil reserves including salaries benefits internal costs directly related finding activities capitalized costs maintained full cost pools geographic areas regardless whether reserves actually discovered record depletion expense capitalized amounts life proved reserves based unit production method factors held constant 10 percent increase estimated proved reserves would decrease unit production depletion rate 9 percent 10 percent decrease estimated proved reserves would increase unit depletion rate 11 percent natural gas oil properties include unproved property costs excluded costs depleted unproved property costs include nonproducing leasehold geological geophysical costs associated leasehold drilling interests exploration drilling costs investments unproved properties major development projects direct interest exclude costs countrybycountry basis proved reserves found determined costs impaired costs excluded reviewed least quarterly determine exclusion fullcost pool continues appropriate costs determined impaired amount impairment transferred full cost pool reserve base exists expensed reserve base yet created impairments transferred full cost pool increase depletion rate country full cost accounting method required conduct quarterly impairment tests capitalized costs full cost pools impairment test referred ceiling test total capitalized costs net related income tax effects limited ceiling based present value future net revenues proved reserves discounted 10 percent net related income tax effects plus lower cost fair market value unproved properties utilize end period spot prices calculating future net revenues unless prices result ceiling test charge case evaluate price recoveries subsequent end period discounted revenues greater equal total capitalized costs required writedown capitalized costs level ceiling test calculations include effect derivative instruments designated qualify hedges anticipated natural gas oil production higher proved reserves reduce likelihood ceiling test impairments ceiling test charges 2007 2006 2005 price used ceiling test calculation held constant life reserves even though actual prices natural gas oil volatile change period decline commodity prices impact results ceiling test may result writedown decrease commodity prices 10 percent price levels december 31 2007 would resulted ceiling test charge 2007 accounting legal environmental reserves guarantees indemnifications accrue legal environmental reserves assessments indicate probable liability incurred asset recovered amount reasonably estimated estimates liabilities based evaluation potential outcomes currently available facts case environmental reserves existing technology presently enacted laws regulations taking consideration likely effects societal economic factors estimates associated onsite offsite groundwater technical studies legal costs actual results may differ estimates often revised future either negatively positively depending upon actual outcomes changes expectations based facts surrounding matter december 31 2007 accrued approximately 460 million legal matters net related insurance receivables includes approximately 379 million associated indemnity certain retiree benefit payments discussed accrued 260 million environmental matters environmental estimates range approximately 260 million approximately 470 million amounts accrued represent combination two estimation methodologies first likely outcome reasonably estimated cost accrued 18 million second likely outcome cannot estimated range costs established 242 million 452 million lower end expected range accrued also guarantee indemnification agreements related various joint ventures ownership arrangements require us assess potential exposure range specified amount unlimited dollar amount depending nature claim particular transaction arrangements specified dollar amount maximum stated value approximately 785 million indemnified third parties 15 million december 31 2007 recorded obligations 51 million related guarantees indemnification arrangements unable estimate maximum exposure guarantee indemnification agreements provide limits amount future payments agreement due uncertainty exposures information see balance sheet arrangements accounting pension postretirement benefits reflect asset liability pension postretirement benefit plans based funded status december 31 2007 combined pension plans funded 513 million combined postretirement benefit plans funded 110 million pension postretirement benefit assets liabilities primarily based actuarial calculations use various assumptions performing calculations including related return expect earn plan assets rate expect compensation employees increase plan term estimated cost health care benefits provided plans factors significant assumption utilize discount rates used calculating benefit obligations select discount rates matching timing amount expected future benefit payments pension postretirement benefit obligations average yields various highquality bonds corresponding maturities also compare discount rates citigroup pension discount curve yields several highquality bond indices maturity profiles similar average duration benefit obligations including moody’s aa average corporate bond rate actual results may differ assumptions included calculations result estimates associated pension postretirement benefits often revised future income statement impact changes assumptions related benefit obligations along changes plans items deferred amortized income either period expected future service active participants lives plan participants record deferred amounts accumulated comprehensive income nonregulated operations either regulatory asset liability regulated operations december 31 2007 deferred losses approximately 237 million net income taxes accumulated comprehensive income following table shows impact one percent change primary assumptions used actuarial calculations associated pension postretirement benefits year ended december 31 2007 millions 1 actual return plan assets one percent lower expected return plan assets expected cash contributions pension postretirement benefit plans would significantly change estimates net benefit expense income partially based expected return pension plan assets use marketrelated value plan assets determine expected return pension plan assets determining marketrelated value plan assets differences expected actual asset returns deferred three years considered inclusion net benefit expense income used fair value plan assets instead marketrelated value plan assets determining expected return pension plan assets net benefit expense would 6 million lower year ended december 31 2007 stated financial statements supplementary data note 12 ordered indemnify third party certain benefit payments made closed group retirees pending outcome litigation related payments estimated initial liability associated indemnification obligation using actuarial methods similar used estimating obligations postretirement benefit plans involves using various assumptions including related discount rates health care trends following table shows impact one percent change primary assumptions used calculation liability year ended december 31 2007 millions price risk management activities record derivative instruments used price risk management activities fair values estimate fair value derivative instruments using exchange prices thirdparty pricing data valuation techniques incorporate specific contractual terms statistical simulation analysis present value concepts one primary assumptions used estimate fair value derivative instruments pricing assumptions based upon price curves derived actual prices observed market pricing information supplied thirdparty valuation specialist independent pricing sources models rely forward pricing information table presents hypothetical sensitivity commoditybased price risk management activities changes fair values arising immediate selected potential changes quoted market prices december 31 2007 another significant assumption discount rates use determining fair value derivative instruments table presents hypothetical sensitivity commodity based price risk management activities changes fair values arising changes discount rates used determine fair value derivatives december 31 2007 significant assumptions use determining fair value derivative instruments related anticipated market liquidity credit risk counterparties believe application assumptions derive fair value representative proceeds would receive disposed derivative instruments currently consider impact credit risk determining fair value derivative liabilities begin considering upon adoption sfas 157 fair value measurements january 1 2008 assumptions methodologies use determine fair values derivatives may differ used derivative counterparties differences significant result actual settlement price risk management activities could differ materially fair value recorded could impact future operating results deferred taxes uncertain income tax positions record deferred income tax assets liabilities reflecting tax consequences deferred future periods based differences financial statement carrying value assets liabilities tax basis assets liabilities additionally deferred tax assets liabilities also reflect assessment tax positions taken resulting tax basis likely sustained audited taxing authorities significant judgments tax related matters include limited items noted matters involve exercise significant judgment could change materially impact financial condition results operations discussion items income tax matters see item 8 financial statements supplementary data note 4 valuation allowance realization deferred tax assets depends recognition sufficient future taxable income specific tax jurisdictions periods temporary differences deductible valuation allowances established necessary reduce deferred income tax assets amounts believe likely recovered evaluating valuation allowance consider reversal existing temporary differences existence taxable income prior carryback years tax planning strategies future taxable income taxable jurisdictions latter two involve exercise significant judgment changes valuation allowance could materially impact results operations uncertain tax positions liabilities unrecognized tax benefits related uncertain tax positions connected ongoing examinations open tax years changes assessment liabilities may require us increase liability record additional tax expense reverse liability recognize tax benefit would positively negatively impact effective tax rate undistributed earnings foreign investees certain unconsolidated affiliates record deferred tax liabilities undistributed earnings foreign investments anticipate earnings repatriated plan repatriate foreign undistributed earnings provision made us taxes foreign withholding taxes additionally recorded provision us income taxes foreign currency translation adjustments recorded accumulated comprehensive income changes repatriation assumptions including repatriation proceeds sales investments could require us record additional deferred taxes additionally believe certain unconsolidated affiliates’ undistributed earnings ultimately distributed us dividends would eligible dividends received deduction joint venture partners intent ability recover cumulative undistributed earnings time dividends however subsequently determine unconsolidated affiliates would unable pay dividends would required record additional deferred income tax liabilities asset investment impairments accounting rules asset investment impairments require us continually monitor businesses business environment determine event occurred indicates longlived asset investment may impaired event occurs determination involves judgment estimate fair value asset considers number factors including potential value would receive sold asset projected cash flows asset based current anticipated future market conditions assessment project level cash flows requires judgment make projections assumptions many years future pricing demand competition operating costs legal regulatory issues factors actual results often differ estimates utilizing cash flow projections assess ability recover carrying value assets investments based either longlived assets’ ability generate future cash flows undiscounted basis ii fair value investments unconsolidated affiliates impairment indicated record impairment charge excess carrying value asset fair value recorded impairments longlived assets 20 million 16 million 73 million impairments losses investments advances unconsolidated affiliates 75 million 13 million 347 million years ended december 31 2007 2006 2005 also recorded asset investment impairments discontinued operations 13 million 502 million net minority interest years ended december 31 2006 2005 future changes economic business environment impact assessments potential impairments new accounting pronouncements issued yet adopted see part ii item 8 financial statements supplementary data note 1 new accounting pronouncements issued yet adopted item 7aitem 7 management’s discussion analysis financial condition results operations overview management’s discussion analysis mda read conjunction consolidated financial statements accompanying footnotes mda includes forwardlooking statements subject risks uncertainties may result actual results differing statements make risks uncertainties discussed item 1a risk factors listed general outline mda business includes summary business purpose description factors influencing profitability summary 2008 performance outlook 2009 results operations includes yearoveryear analysis results business segments corporate activities income statement items including trends may impact business future liquidity capital resources includes general discussion sources uses cash available liquidity outlook 2009 overview cash flow activity 2008 additional factors could impact liquidity balance sheet arrangements contractual obligations commoditybased derivative contracts includes discussion balance sheet arrangements including guarantees letters credit ii contractual obligations iii derivative contracts used manage price risks associated natural gas oil production critical accounting estimates includes discussion accounting estimates involve use significant assumptions andor judgments preparation financial statements business purpose provide natural gas related energy products safe efficient dependable manner interests north america’s largest interstate natural gas pipeline systems provides stable base earnings cash flow significant backlog committed expansion projects also large independent natural gas oil producer focused generating competitive financial returns disciplined capital allocation portfolio management cost control marketing selling natural gas oil production optimal prices managing associated price risks factors influencing profitability pipeline operations rateregulated accordingly generate profit based ability earn return excess costs rates charge customers exploration production operations generate profits dependent prices natural gas oil costs explore develop produce natural gas oil volumes able produce among factors current volatility financial markets described could influence nearterm profitability longterm profitability operating segments primarily influenced following factors pipelines • continuing successfully execute backlog committed expansion projects develop new growth projects market supply areas • contracting recontracting pipeline capacity customers • maintaining obtaining approval ferc acceptable rates terms service expansion projects • improving operating efficiency exploration production • longterm growth natural gas oil proved reserve base production volumes successful drilling programs andor acquisitions • finding producing natural gas oil reasonable cost • managing price risks optimize realized prices natural gas oil production addition factors future profitability also affected impacts volatility current financial commodity markets debt level related interest costs successful resolution historical contingencies completing orderly exit remaining power assets historical derivative contracts remaining noncore assets summary 2008 financial operational performance 2008 pipeline operations continued provide strong base earnings cash flow first half 2008 exploration production business benefited favorable commodity price environment however second half 2008 earnings exploration production business negatively affected adverse impacts production volumes hurricanes ike gustav decline commodity prices fourth quarter 2008 recorded noncash full cost ceiling test charges 27 billion domestic brazilian full cost pools result decline commodity prices 2008 financial performance also impacted favorable resolution certain litigation matters largely offset losses marketing segment changes natural gas oil prices decline interest rates following table provides significant operational highlights core businesses 2008 area operations significant highlights pipelines completed several pipeline projects entered new expansion projects including ruby pipeline project tgp 300 line project fgt phase viii project resulting current backlog committed growth projects approximately 8 billion placed several expansion projects service including wic kanda lateral phase ii cypress pipeline project cheyenne plains compression expansion southeast supply header phase expansion medicine bow expansion high plains pipeline bluewater reconfiguration project exploration production achieved overall drilling success rate 98 percent advanced growth opportunities domestically niobrara shale raton basin haynesville shale arklatex altamont field rockies internationally exploration programs brazil egypt 2008 early 2009 executed unitization agreement gas condensate sales agreements petrobras develop camarupim field brazil high graded asset portfolio sale certain noncore properties primarily texas gulf coast gulf mexico regions acquired interests domestic natural gas oil properties western region complement existing asset portfolio managed price risk derivative contracts combined positions provided higher realized commodity prices 2008 gives us price protection significant portion planned 2009 equivalent production noncore power segment sold transferred several international power investments february 2009 completed sale interest porto velho power generation facility partner see item 8 financial statements supplementary data note 18 discussion sale investment outlook 2009 expect pipeline operations continue provide strong base earnings operating cash flow 2009 anticipate spending approximately 17 billion capital expenditures business pipeline business approximately threefourths revenues collected form demand reservation charges dependent upon commodity prices throughput levels also expect relatively stable rates within pipeline group majority pipelines outstanding rate cases pending ferc expect two pipelines epng sng involved major rate cases 2009 expect rate cases result increased revenues finally remain focused implementing approximate 8 billion backlog new committed pipeline growth projects several projects expected commence service 2009 exploration production business expect generate significant operating cash flow earnings although additional noncash ceiling test charges could impact earnings future result declines natural gas oil prices since december 31 2008 reductions oilfield service costs could partially mitigate impacts commodity price declines business reduced capital expenditure program 2009 range 09 billion 13 billion 17 billion 2008 additionally current commodity prices remain volatile lower levels experienced last several years however financial derivative contracts place 2009 providing average floor price 902 per mmbtu 176 tbtu natural gas greatly mitigate natural gas price risk 2009 also expect reductions oilfield service costs 2009 extent commodity prices drilling activities remain lower levels although also impact nearterm growth profile objective capital program retain substantially existing inventory future exploration production commodity prices return favorable levels response anticipated 2009 capital requirements debt maturities since november 2008 successfully generated additional liquidity approximately 19 billion time completed various debt offerings including 12 billion raised three separate capital market transactions entered new credit facilities completed noncore asset sales described liquidity capital resources result available liquidity february 27 2009 33 billion carry us 2010 see liquidity capital resources additional detail based completion activities expect access capital markets remainder 2009 regardless whether successful obtaining equity partners capital projects however continue opportunistic building liquidity prudent meet longterm capital needs also implemented various cost saving measures reduce capital operating well general administrative costs measures include reducing drilling activity exploration production business first half 2009 expect obtain reductions oilfield service costs later 2009 measures also include obtaining supply chain management savings regard capital maintenance programs renegotiating contracts contractors suppliers service providers well deferring eliminating various discretionary costs extreme volatility financial markets energy industry global economy likely continue impact outlook 2009 first global financial markets continue remain extremely volatile uncertain whether recent us foreign government actions successfully restore confidence liquidity global financial markets could impact longerterm access capital future growth projects well cost capital may require us adjust current financing business plans second commodity prices natural gas oil remain volatile levels substantially experienced prior fourth quarter 2008 may required record additional ceiling test charges future unless commodity prices significantly increase oilfield service costs significantly decrease current levels approximately threefourths domestic natural gas production 2009 hedged therefore subject commodity price exposure however currently substantial hedges place 2010 beyond third impacts difficult quantify point downward trend global economy could adverse impacts natural gas consumption demand although sectors could impacted likely industrial demand energy would impacted first prolonged downturn economy based conditions plans 2009 include • capital expenditures planned 2009 capital expenditures approximately 26 billion 31 billion 17 billion capital spent pipeline business 09 billion 13 billion exploration production business 17 billion planned pipeline capital reflects equity partnering one expansion projects • asset sales sold evaluating sale several noncore assets generating cash proceeds approximately 04 billion 2009 approximately 02 billion already completed • liquidity sources continue opportunistic generating additional liquidity february 2009 settled 2009 crude oil production hedges generating 186 million cash additionally extent asset sales partnering opportunities expansion projects delayed cannot completed decline commodity prices experience major disruptions financial markets could also pursue alternatives including additional reductions discretionary capital program additional secured financing arrangements seeking additional partners one growth projects selling additional noncore assets 2009 plans determined based number factors significant noted • debt capital structure debt capital structure 80 percent fixed interest rates 20 percent floating interest rates accordingly believe lessened exposure market changes interest rates existing debt impact interest costs • revenue price sensitivities pipeline business approximately threefourths pipeline revenues collected form demand reservation charges result nearterm declines demand natural gas due recessionary pressures declines natural gas prices significantly impact pipeline revenues exploration production business however impacted fluctuations commodity prices although mitigated somewhat derivative contracts place 2009 representing approximately 75 percent domestic natural gas production additionally event lower oil natural gas prices currently unencumbered exploration production properties reserves could pledge collateral maintain current available borrowing base revolving credit facilities exploration production subsidiary • counterparty risk continually monitor financial situation major lenders trading counterparties customers joint interest partners vendors suppliers enforce contractual rights regard providing collateral credit certain contractual arrangements parties include requirements provide letters credit performance bonds assurances performance mitigate part risk nonperformance parties however natural gas oil hedges executed exploration production business contractually require posting margin • lending institutions part determination available capacity credit agreements completed assessment available lenders facilities diverse group based assessment determined potential exposure loss available capacity approximately 28 million el paso’s 15 billion revolving credit facility approximately 2 million epep’s 10 billion revolving credit facility approximately 15 million epb’s 750 million credit facility assessment based upon fact one lenders failed fund previous requests facilities filed bankruptcy 2009 plans designed address impacts current volatility global financial markets maintain sufficient liquidity meet 2009 debt maturities fund 2009 capital program additionally designed retain longterm growth potential including committed pipeline project backlog core domestic international drilling programs well natural gas oil resource inventory positions light current volatility financial markets energy industry global economy possible additional adjustments plan outlook required could impact financial operating performance results operations overview december 31 2008 core operating business segments pipelines exploration production also marketing segment markets natural gas oil production manages legacy trading activities power segment interests assets south america asia segments managed separately provide variety energy products services require different technology marketing strategies corporate activities include general administrative functions well miscellaneous businesses contracts assets immaterial management uses earnings interest expense income taxes ebit measure assess operating results effectiveness business segments consist consolidated businesses investments unconsolidated affiliates believe ebit useful investors allows evaluate effectively operating performance using performance measure analyzed internally management define ebit net income loss adjusted items impact income loss continuing operations discontinued operations ii income taxes iii interest debt expense exclude interest debt expense measure investors may evaluate operating results without regard financing methods capital structure ebit may comparable measurements used companies additionally ebit considered conjunction net income performance measures operating income operating cash flows reconciliation ebit segment consolidated net income loss three years ended december 31 discussions follow provide additional analysis year results business segments corporate activities income statement items pipelines segment overview pipelines segment operates primarily united states consists interstate natural gas transmission storage lng terminalling related services face varying degrees competition segment existing proposed pipelines proposed lng facilities well alternative energy sources used generate electricity hydroelectric power nuclear energy wind solar coal fuel oil revenues transportation storage lng terminalling related services consist two types percent total type description revenues reservation revenues customers referred firm customers reserve capacity pipeline systems storage facilities lng terminalling facilities firm customers obligated pay monthly reservation demand charge regardless amount natural gas transport store term contracts usage revenues firm customers interruptible customers without reserved capacity pay usage charges based volume gas actually transported stored injected withdrawn also earn revenues processing sale natural gas liquids miscellaneous sources ferc regulates rates charge customers rates generally function cost providing services customers including reasonable return invested capital regulated nature high percentage revenues attributable reservation charges revenues historically relatively stable however financial results subject volatility due factors changes natural gas prices changes supply demand regulatory actions competition weather declines creditworthiness customers also experience earnings volatility certain pipelines amount natural gas used operations differs amounts receive purpose historically much business conducted longterm contracts customers however many customers shifted traditional dependence longterm contracts portfolio approach balances shortterm opportunities longterm commitments shift increase volatility revenues due changes market conditions competition driven state utility deregulation local distribution company mergers new supply sources volatility natural gas prices demand shortterm capacity new power plant markets continue manage recontracting process limit risk significant impacts revenues expiring contracts ability extend existing customer contracts remarket expiring contracted capacity dependent competitive alternatives regulatory environment federal state local levels market supply demand factors relevant dates contracts extended expire duration new renegotiated contracts affected current prices competitive conditions judgments concerning future market trends volatility subject regulatory requirements attempt recontract remarket capacity maximum allowable rates allowed tariffs although times enter contracts less maximum allowable rates remain competitive refer difference maximum rates allowed tariff contractual rate charge “discounts” existing contracts mature various times varying amounts throughput capacity weighted average remaining contract term active contracts approximately six years december 31 2008 contract expiration portfolio associated revenue expirations firm transportation contracts wholly majority owned systems december 31 2008 including terms beginning 2009 later summary operational financial performance 2008 continued deliver strong operational financial performance across pipelines placed several expansion projects service including wic kanda lateral project january phase ii cypress project may cheyenne plains compression expansion project august phase southeast supply header project september medicine bow expansion october high plains pipeline november continued make significant progress backlog expansion projects september 2008 contributed additional interests cig sng el paso pipeline partners lp epb master limited partnership discussed part item 1 business december 31 2008 ownership interest epb consists two percent general partner interest 72 percent limited partner interest 2008 benefited higher realized rates demand certain systems ii increased throughput iii increased activity various interruptible services level throughput systems provide evidence underlying longterm value system capacity 2008 increased throughput certain systems primarily result increased demand california deliveries higher production activities rockiesrelated expansions however expect growth natural gas market adversely affected current economic recession us global economies decline economic activity reduce industrial demand natural gas electricity cause lower natural gas demand directly enduse markets indirectly lower power generation demand natural gas demand natural gas electricity residential commercial segments market likely less affected economy lower demand credit restrictions investments current environment may also slow development supply projects result pipelines may experience lower throughput lower revenues slower development new expansion projects pipeline systems could experience level reduced throughput revenues slower development expansion projects result factors generates significant portion revenues monthly reservation demand charges longterm contracts rates stipulated tariffs additionally expect production us rocky mountain region significantly decrease current levels due need replace diminishing exports canada declining production traditional domestic sources 2009 plan spend 17 billion capital 13 billion designated backlog expansion projects 17 billion planned pipeline capital expenditures anticipates obtaining approximately 05 billion capital equity partners one expansion projects intend build growth achieved 2008 currently approximately 8 billion committed expansion projects comprise backlog el paso’s committed backlog new pipeline growth projects substantially fully contracted customers placed service next five years listed projects comprise backlog grouped anticipated inservice dates december 31 2008 1 amounts represent share estimated costs 2 expansion consists two projects separate inservice dates november 2010 march 2011 3 construction cypress phase iii option bg lng services 4 includes approximately 295 million paid acquire 50 percent interest project 5 although projects substantial contractual commitments customers fully contracted listed additional updates significant backlog projects significant projects added backlog 2008 • south system iii south system iii expansion project completed three phases second quarter 2008 changed scope project request customer increased total estimated cost 352 million filed application ferc december 2008 certificate authorization construct operate facilities • southeast supply header undivided interest northern portion southeast supply header project jointly owned spectra energy corp spectra centerpoint energy construction project managed spectra share estimated cost project 241 million project expected completed two phases phase project completed september 2008 december 2008 filed application ferc certificate authorization construct phase ii anticipated complete june 2011 • florida gas transmission phase viii 50 percent interest project equity investment citrus proportional share estimated cost project increased 2008 12 billion due higher expected pipe costs • cig raton 2010 expansion july 2008 announced expansion cig raton basin pipeline extending raton basin wet canyon lateral south end valley line tentative ferc filing date project march 2009 • ruby pipeline project 2008 obtained sufficient longterm capacity commitments customers committed move forward 3 billion ruby pipeline project filed certificate application ferc january 2009 ordered pipe ruby pipeline project fixed price basis recoverable future rates project placed service • tgp 300 line expansion august 2008 announced 300 line expansion project estimated total capital cost approximately 750 million ordered pipe tgp 300 line expansion project fixed price basis recoverable future rates project placed service • gulf lng clean energy february 2008 completed acquisition 50 percent interest gulf lng clean energy project constructing ferc approved liquefied natural gas terminal pascagoula mississippi successful execution 8 billion committed pipeline backlog require effective project management addition effective supply chain sourcing also important control costs also seek cost reductions light downturn demand certain supplies services see liquidity capital resources description pipeline backlog operating results 1 volumes exclude intrasegment activities 2 represents proportional share table discussion follows detail impact ebit significant events 2008 compared 2007 compared 2006 also provided outlook events may affect operations future 1 consists individually insignificant items several pipeline systems expansions 2008 2007 reservation revenues throughput volumes increased due projects placed service 2008 placed several expansion projects service including wic kanda lateral project january phase ii cypress project may cheyenne plains compression expansion project august phase southeast supply header project september medicine bow expansion october high plains pipeline november 2007 placed several expansion projects service including phase cypress project louisiana deepwater link project triplet extension project northeast connexionnew england project mexico lpg burgos project reservation usage revenues year ended december 31 2008 ebit favorably impacted • increased demand offsystem mainline capacity rocky mountain region systems primarily due lower natural gas prices rocky mountains compared regions united states • additional firm capacity sold northern southern regions tgp system partially offset lower surcharges certain firm customers system • increased reservation usage revenues epng system due higher amounts charged recontracted capacity arizona california • additional interruptible firm commodity services provided several pipeline systems increase reservation usage revenues 2007 compared 2006 primarily due • increase throughput pipeline systems primarily rocky mountains southern regions increased due new supply colder weather increased transportation services power plants • additional firm capacity sold south central region tgp system • increased rates cig system effective october 2006 result cig’s rate settlement gas used operations revaluations year ended december 31 2008 ebit favorably impacted higher volumes gas used tgp operations compared period 2007 2008 cig wic implemented fercapproved fuel related gas cost recovery mechanisms designed recover cost impacts flow shippers revenue impacts certain fuel imbalance revaluations related gas balance items reduce earnings volatility resulting items time anticipate overall activity area continue vary based factors volatility natural gas prices efficiency pipeline operations regulatory actions factors year ended december 31 2007 ebit unfavorably impacted revaluation net gas imbalances gas owed customers cig wic systems result increasing natural gas prices 2007 versus decreasing natural gas prices 2006 lower processing revenues operational gas costs cig system due decrease processing volumes natural gas liquids partially offsetting unfavorable impacts 2007 higher volumes gas used tgp’s operations bankruptcy settlements 2008 revenue increased 33 million related distributions received calpine corporation’s calpine approved plan reorganization settlement related calpine’s rejection transportation contracts us 2008 2007 2006 recorded income approximately 10 million 5 million 18 million net amounts potentially owed certain customers related amounts recovered enron bankruptcy settlement 2007 received 10 million settle bankruptcy claim usgen new england inc operating general administrative expenses year ended december 31 2008 operating general administrative expenses higher 2007 primarily due increased labor costs support growth customer activities additional maintenance work required several pipeline systems year ended december 31 2007 operating general administrative expenses higher 2006 primarily due increased insurance costs wind damage pipeline assets located primarily gulf mexico region increased repair maintenance costs allowances nontrade accounts receivable environmental reserves gainloss longlived assets 2008 recorded impairments 41 million including impairment related essexmiddlesex lateral project due prolonged permitting process impairment epng arizona gas storage projects longer developing due declining real estate values 2007 recorded 10 million impairment certain pipeline assets originally purchased repair certain offshore hurricane damage following decision use assets ii loss approximately 9 million epng’s east valley line lateral pursuant ferc determination accounting treatment pending sale certain transmission facilities iii 7 million pretax gain sale pipeline lateral 2006 recorded impairments 16 million due discontinuing continental connector pipeline project remainder seafarer project hurricanes 2008 incurred damage sections gulf coast offshore pipeline facilities due hurricanes ike gustav ebit unfavorably impacted 31 million 2008 related hurricanes due gas loss various damaged pipelines lower volume gas used operations repair costs recoverable insurance due losses exceeding selfretention levels see liquidity capital resources discussion hurricanes 2007 incurred lower operation maintenance expenses repair damage caused hurricanes katrina rita compared 2006 equity earnings citrus 2008 equity earnings citrus investment decreased compared 2007 due citrus’s favorable settlement 2007 approximately 8 million litigation brought spectra lng sales formerly duke energy lng sales inc wrongful termination gas supply contract citrus’ sale receivable 2007 approximately 3 million related bankruptcy enron north america addition 2007 benefited 8 million compared 2006 due primarily higher system usage lower operating costs florida gas transmission company pipeline owned citrus minority interests year ended december 31 2008 2007 recorded approximately 35 million 3 million minority interest expense related epb formed november 2007 minority interest expense increased 2008 due additional contribution interests cig sng el paso epb regulatory matters pipeline systems periodically file changes rates subject approval ferc changes rates tariff provisions resulting regulatory proceedings potential positively negatively impact profitability currently certain pipelines expected continue operating existing rates pipelines projected upcoming rate actions anticipated effective dates 2009 2011 june 2008 epng filed rate case ferc required settlement previous rate case filing proposed increase epng’s base tariff rates subject refund outcome hearing technical conference became effective january 1 2009 ferc issued order december 2008 generally accepted epng’s proposals technical conference proceeding discussion rate case see item 8 financial statements supplementary data note 13 terms sng’s last rate settlement sng obligated file proposed new rates effective later october 1 2010 sng anticipates filing new rate case later march 2009 revised rates expected become effective september 1 2009 exploration production segment overview strategy exploration production segment conducts natural gas oil exploration production activities profitability performance segment driven ability locate develop economic natural gas oil reserves extract reserves lowest possible production administrative costs accordingly manage business goal creating value disciplined capital allocation cost control portfolio management also enter financial derivative contracts mitigate significant downward price movements strategy focuses building applying competencies assets repeatable programs executing improve capital expense efficiency maximizing returns adding assets inventory match competencies divesting assets domestic natural gas oil reserve portfolio blends lower decline rate typically longer lived assets central western regions steeper decline rate shorter lived assets texas gulf coast gulf mexico south louisiana regions approximately 88 percent 2008 capital spent domestic projects internationally portfolio consists producing fields along growth projects several areas interest offshore brazil exploration projects egypt 2008 international capital primarily brazil constituted approximately 12 percent total capital program ongoing success international programs brazil egypt require effective project management strong partner relations obtaining approvals regulatory agencies although current economic conditions may dictate timing spending part business strategy allocate capital development exploration programs acquisition opportunities 2008 acquired interests domestic natural gas oil properties approximately 61 million including producing properties 51 million primarily western region assets acquired mainly incremental interests properties already operated additionally part efforts high grade asset portfolio 2008 completed sale certain noncore properties net cash proceeds approximately 637 million primarily texas gulf coast gulf mexico regions properties estimated proved reserves approximately 309 bcfe asset retirement liabilities 109 million december 31 2007 transactions together 2007 acquisition peoples increased onshore us weighting inventory future capital projects reduced perunit lease operating expenses january 2009 completed sale two noncore natural gas producing properties western central regions approximately 74 million properties 40 bcfe proved reserves approximately 15 mmcfed production december 31 2008 fourth quarter 2008 along industry participants experienced significant reductions market price natural gas oil furthermore service equipment costs declined commensurate reduction natural gas oil prices factors challenged economic assumptions development exploration enter 2009 coupled unprecedented challenges credit markets events resulted us reducing capital spending fourth quarter 2008 reducing anticipated capital program 2009 based reduced spending levels expect 2009 production volumes range flat approximately 10 percent compared 2008 continue evaluate acquisition growth opportunities focused around core competencies areas competitive advantage although current market conditions present challenges strategic acquisitions support corporate objectives providing us greater opportunities achieve long term performance goals leveraging operational expertise already possessed key operating areas balancing exposure regions basins commodities achieving riskadjusted returns competitive available within existing inventory increasing reserves supplementing current drilling inventory addition effectively executing strategy profitability performance impacted changes commodity prices ii industrywide changes cost drilling oilfield services iii effect hurricanes weather impacts daily production operating capital costs extent possible attempt mitigate factors part risk management activities entered derivative contracts approximately 75 percent anticipated 2009 domestic natural gas production reduce financial impact downward commodity price movements significant operational factors affecting year ended december 31 2008 production average daily production year 742 mmcfed include 74 mmcfed share production equity investment four star analysis 2008 production region mmcfed central region 2008 central region production volumes continued increase result successful arklatex drilling programs peoples acquisition september 2007 also contributed increase 2008 western region 2008 western region production volumes continued increase result increased production major operating areas majority growth coming rockies texas gulf coast region 2008 texas gulf coast region production volumes grew result peoples zapata acquisitions 2007 along production growth coming south texas wilcox area partially offset impact hurricanes asset sales gulf mexico south louisiana region 2008 gulf mexico south louisiana region production volumes decreased due impacts asset sales hurricanes ike gustav third quarter 2008 natural production declines hurricanes ike gustav negatively impacted production volumes 23 mmcfed year continuing impact production volumes first quarter 2009 brazil 2008 production volumes decreased primarily due natural production declines four star increased ownership interest four star 43 percent 49 percent third quarter 2007 favorably impacted share production volumes 2008 drilling results central achieved 100 percent success rate 324 gross wells drilled western achieved 100 percent success rate 107 gross wells drilled texas gulf coast achieved 93 percent success rate 108 gross wells drilled gulf mexico south louisiana achieved 77 percent success rate 13 gross wells drilled brazil achieved 50 percent success rate two gross wells drilled egypt participated drilling exploratory well south feiran block unsuccessful discussion activities brazil egypt see part item 1 business exploration production segment international cash operating costs monitor cash operating costs required produce natural gas oil production volumes costs calculated per mcfe basis include total operating expenses less depreciation depletion amortization expense ceiling test impairment charges transportation costs cost products year ended december 31 2008 cash operating costs per unit increased 197mcfe compared 188mcfe 2007 increase 2008 primarily due higher production taxes resulting higher natural gas oil revenues impact lower production volumes partially offset lower lease operating expenses lower general administrative expenses lease operating expenses decreased 2008 primarily due divestiture higher cost properties gulf mexico south louisiana region general administrative expenses decreased 2008 primarily due reversal accrual result favorable ruling legal matter 2008 legal accrual reversal 007mcfe positive impact lost volumes incremental repair costs result hurricanes 008mcfe adverse effect cash operating costs reserve replacement ratioreserve replacement costs calculate two primary metrics reserve replacement ratio ii reserve replacement costs measure ability establish longterm trend adding reserves reasonable cost core asset areas reserve replacement ratio indicator ability replenish annual production volumes grow reserves important us economically find develop new reserves offset produced volumes provide future production given inherent decline hydrocarbon reserves addition calculate reserve replacement costs assess cost adding reserves ultimately included depreciation depletion amortization expense believe ability develop competitive advantage natural gas oil companies dependent adding reserves core asset areas lower costs competition calculate metrics follows reserve replacement ratio sum reserve additions1 actual production corresponding period reserve replacement costsmcfe total oil gas capital costs2 sum reserve additions 1 reserve additions include proved reserves reflect reserve revisions prices performance extensions discoveries additions acquisitions include unproved reserve quantities proved reserve additions attributable investments accounted using equity method presented metrics separately including excluding impact price revisions reserves demonstrate effectiveness drilling program exclusive economic factors price outside control amounts derived directly table presented item 8 financial statements supplementary data supplemental natural gas oil operations 2 total oil gas capital costs include costs development exploration property acquisition activities conducted add reserves exclude asset retirement obligations amounts derived directly table presented item 8 financial statements supplementary data supplemental natural gas oil operations reserve replacement ratio reserve replacement costs per unit statistical indicators limitations including predictive comparative value annual measure reserve replacement ratio limited typically varies widely based extent timing new discoveries project sanctioning property acquisitions addition since reserve replacement ratio consider cost timing future production new reserves cannot used measure value creation exploration acquisition development natural gas oil reserves inherently uncertain discussed part item 1a risk factors risks related business one risks uncertainties ability spend sufficient capital increase reserves currently expect spend amounts future assurances timing magnitude expenditures classification proved reserves developed undeveloped december 31 2008 proved developed reserves represent approximately 74 percent total proved reserves proved developed reserves generally begin producing within year added whereas proved undeveloped reserves generally require major future expenditure table shows reserve replacement costs reserve replacement ratio domestic worldwide operations including excluding effect price revisions reserves years ended december 31 typically cite reserve replacement costs context multiyear trend recognition limitation single year measure also demonstrate consistency stability essential business model table shows reserve replacement costs domestic worldwide operations three years ended december 31 2008 capital expenditures oil gas capital expenditures follows three years ended december 31 1 total oil gas capital costs include costs development exploration property acquisition activities conducted add reserves exclude asset retirement obligations amounts derived directly table presented item 8 financial statements supplementary data supplemental natural gas oil operations outlook 2009 anticipate continued volatility commodity markets general economic climate exercise flexibility allocating capital response changing conditions result estimated capital spending production volumes wider ranges previous years expect following worldwide basis price risk management activities part strategy enter derivative contracts natural gas oil production stabilize cash flows reduce risk financial impact downward commodity price movements commodity sales protect economic assumptions associated capital investment programs strategy partially reduces exposure downward movements commodity prices reported results operations financial position cash flows impacted significantly movements commodity prices period adjustments hedging strategy decision enter new positions alter existing positions made based goals overall company fourth quarter 2008 discontinued hedge accounting commoditybased derivative contracts prior fourth quarter 2008 commoditybased derivative contracts treated accounting hedges others result decision discontinue hedge accounting reflect changes fair value commoditybased derivative instruments earnings period discussion impact results operations see operating results variance analysis following table reflects contracted volumes minimum maximum average prices receive derivative contracts december 31 2008 discussion related el paso’s productionrelated price risk management activities see liquidity capital resources 1 volumes presented tbtu natural gas mbbl oil prices presented per mmbtu natural gas per bbl oil 2 basis swaps effectively limit exposure differences nymex gas price location sell gas average prices listed amounts pay per mmbtu relative nymex price “lockin” locational price differences first two months 2009 settled remaining 2009 fixed price oil swaps approximately 186 million cash entering new contracts approximately 1500 mbbls fixed price oil swaps anticipated 2009 oil production average price 4500 per barrel also entered 22 tbtu natural gas floor contracts average price 700 per mmbtu well 23 tbtu natural gas basis swap contracts average price 060 per mmbtu related anticipated 2009 natural gas production related anticipated 2010 natural gas production paid approximately 35 million premiums add 22 tbtu 700 per mmbtu floor contracts entered 20 tbtu fixed price swap contracts average price 728 per mmbtu 57 tbtu basis swap contracts average price 072 per mmbtu operating results variance analysis information provides financial results analysis significant variances results periods ended december 31 1 production taxes include ad valorem severance taxes year ended december 31 2008 compared year ended december 31 2007 ebit 2008 decreased 2357 million compared 2007 table shows significant variances financial results 2008 compared 2007 natural gas oil condensate ngl revenues 2008 revenues increased compared 2007 due primarily higher commodity prices including effects derivatives designated accounting hedges losses recognized hedging settlements totaled 109 million 2008 compared gains 177 million 2007 resulted higher commodity prices 2008 versus 2007 relative derivative contract prices years settlements include premiums paid derivative option contracts year ended december 31 2008 also benefited increase production volumes central western texas gulf coast regions compared 2007 primarily result successful drilling programs peoples acquisition third quarter 2007 gulf mexico south louisiana region production volumes decreased 2008 versus 2007 primarily due asset sales production shut result hurricanes ike gustav natural production declines revenue 2008 recognized marktomarket gains 305 million compared gains 7 million 2007 related changes fair value derivatives designated accounting hedges year ended december 31 2008 received 18 million contracts settled period compared payments 31 million contracts settled 2007 fourth quarter 2008we discontinued use hedge accounting result decision value derivatives date discontinued hedge accounting amortized revenue month contracts settled amount recognized revenue 2009 related derivatives approximately 409 million subsequent changes fair value derivatives also recognized revenue occur depreciation depletion amortization expense 2008 depletion rate increased compared period 2007 result peoples zapata county texas acquisitions 2007 higher finding development costs depreciation depletion amortization rate includes 005 per mcfe 2008 compared 007 per mcfe 2007 related accretion expense asset retirement obligations result ceiling test charges discussed depreciation depletion amortization rate decrease 2009 current rate production costs production costs increased 2008 compared period 2007 primarily due higher production taxes increased due higher natural gas oil revenues increase production taxes partially offset reduction lease operating expenses year ended december 31 2008 primarily result impact divested properties gulf mexico south louisiana region general administrative expenses general administrative expenses decreased 2008 compared periods 2007 primarily due reversal 20 million accrual result favorable ruling legal matter ceiling test charges fourth quarter 2008 recorded noncash full cost ceiling test charges 27 billion capitalized costs exceeded ceiling limit 22 billion domestic full cost pool 05 billion brazilian full cost pool calculation charges based december 31 2008 spot natural gas price 571 per mmbtu oil price 4460 per barrel calculating ceiling test charges required hold prices constant life reserves even though actual prices natural gas oil volatile change period first two months 2009 natural gas oil prices declined levels december 31 2008 may required record additional ceiling test charges future unless commodity prices significantly increase oilfield service costs significantly decrease current levels historically included derivatives designated accounting hedges determination future net revenues purposes calculating ceiling tests fourth quarter 2008 removed hedging designation commoditybased derivative contracts related hedged natural gas oil production volumes estimate chosen dedesignate hedges ceiling test charges december 31 2008 would lower approximately 400 million equity earnings four star 2008 decreased compared 2007 due primarily impairment carrying value investment 125 million based decline fair value investment result lower forecasted commodity prices year ended december 31 2007 compared year ended december 31 2006 ebit 2007 increased 269 million compared 2006 table shows significant variances financial results 2007 compared 2006 natural gas oil condensate ngl revenues 2007 revenues increased compared 2006 due higher realized natural gas oil prices including effects derivatives account hedges realized gains accounting hedges 177 million 2007 compared realized losses 58 million 2006 2007 also benefited increase production volumes domestic regions 2006 revenue 2007 recognized marktomarket gains 7 million compared losses 40 million 2006 related changes fair value derivatives designated accounting hedges year ended december 31 2007 2006 made payments 31 million 16 million contracts settled periods depreciation depletion amortization expense 2007 depletion rate increased compared period 2006 result peoples zapata county texas property acquisitions higher finding development costs depreciation depletion amortization rate includes 007 per mcfe years 2007 2006 related accretion expense asset retirement obligations production costs production taxes increased 2007 compared 2006 primarily due higher natural gas oil revenues lower severance tax credits 2007 general administrative expenses general administrative expenses increased 2007 compared 2006 primarily due higher marketing costs previously included marketing segment higher corporate overhead allocations marketing segment marketing segment’s primary focus market exploration production segment’s natural gas oil production manage el paso’s overall price risk manage remaining legacy contracts entered prior deterioration energy trading environment 2002 extent economical prudent continue seek opportunities reduce impact remaining legacy contracts future operating results contract liquidations december 31 2008 productionrelated natural gas oil derivative contracts held marketing segment terminated expired accordingly exploration production segment holds el paso’s remaining productionrelated derivative contracts primary remaining exposure operating results relates changes fair value legacy pjm power contracts primarily related changes power prices locations within pjm region past years entered several transactions reduce volatility legacy contracts impact operating results addition pjm power contracts legacy contracts include natural gas derivative contracts markedtomarket operating results well transportationrelated natural gas longterm natural gas supply contracts accrualbased contracts impact revenues delivery service contracts occurs remaining contracts subject counterparty credit nonperformance risk marktomarket contracts also subject interest rate exposure discussion remaining contracts see item 1 business marketing segment operating results overview past three years operating results yeartoyear comparability impacted significant commodity market fluctuations changes composition portfolio related effort manage portfolio based actions taken reduce exposure exit legacy trading activities tables discussions follow provide information events overall operating results analysis significant contract type marketing segment three years ended december 31 2008 2007 results primarily driven marktomarket losses productionrelated natural gas oil derivative contracts changes fair market value pjm power contracts 2008 also recognized 19 million revenue reflected changes fair value natural gas derivative contracts related bankruptcy settlements 2007 also impacting results marktomarket losses legacy natural gas derivative contracts 23 million income recognized upon sale investment nymex 28 million ebit 23 million revenues 5 million income related settlement outstanding california power price disputes 2006 results primarily driven losses divestiture significant portion natural gas portfolio 188 million termination payment related alliance transportation capacity obligations changes fair value natural gas derivative contracts including approximately 133 million related mcv supply agreement losses partially offset significant marktomarket gains 2006 productionrelated natural gas oil derivative contracts productionrelated natural gas oil derivative contracts prior expiration termination 2008 held productionrelated natural gas oil derivative contracts addition derivative contracts entered exploration production segment 2008 remaining oil option contracts expired terminated remaining 17 tbtu 2009 natural gas option contracts floor price 600 per mmbtu ceiling price 875 per mmbtu paying approximately 57 million changes fair value contracts markedtomarket financial results impacted volatility commodity prices periodtoperiod 2008 2007 increases forward commodity prices reduced fair value option contracts resulting loss contracts 2006 decreases forward commodity prices increased fair value derivative contracts resulting gain 2008 paid approximately 40 million contracts settled period exclusive termination payment described received approximately 45 million 59 million 2007 2006 contracts settled periods contracts related legacy trading operations power contracts primary remaining exposure power portfolio consists changes locational power price differences pjm region changes interest rates prior agreements entered 2006 2008 also exposed changes installed capacity prices commodity prices power prices pjm region highly volatile due changes fuel prices transmission congestion certain locations region future changes locational prices could continue significantly impact fair value power contracts changes fair value pjm contracts resulted marktomarket losses approximately 46 million 2008 100 million 2007 marktomarket gains approximately 71 million 2006 year ended december 31 2008 decrease fair value contracts primarily related significant reductions interest rates used estimate contracts’ fair value also impacting results 2008 capacity purchase agreement executed counterparty combined capacity prices established auctions held pjm independent system operator periods prior june 2011 economically hedged exposure supplying capacity pjm region remainder contract term prior time recorded significant losses 2007 based installed capacity price changes gains 2006 primarily related changing locational price differences pjm region years ended december 31 2008 2007 2006 total cash settlements paid power contracts approximately 66 million 50 million 41 million natural gas transportationrelated contracts december 31 2008 transportation contracts provide us approximately 06 bcfd pipeline capacity recovery demand charges related transportation contracts therefore profitability contracts dependent upon ability use remarket contracted pipeline capacity impacted number factors including differences natural gas prices contractual receipt delivery locations working capital needed use capacity required meet long term obligations december 31 2008 contracts require us pay demand charges 41 million 2009 average 22 million 2010 2013 following table summary demand charges millions percentage recovery charges three years ended december 31 natural gas derivative contracts also contracts third parties require us purchase deliver natural gas primarily market prices however substantially offset fixed price exposure contracts 2006 conjunction sale mcv facility power segment recorded cumulative marktomarket losses approximately 133 million mcv gas supply contract associated facility previously recognized due affiliated ownership interest additionally recognized 49 million gain 2006 associated assignment certain natural gas derivative contracts supply natural gas southeastern us power segment overview december 31 2008 remaining investment guarantees letters credit related projects power segment totaled approximately 396 million consisted approximately 380 million equity investments notes receivable approximately 16 million financial guarantees letters credit following projects 2008 sold remaining central american power investment asian power investment transferred ownership manaus rio negro power plants brazil plants’ power purchaser longer manaus rio negro power plants still exposure relating outstanding receivables due power purchaser february 2009 completed sale investment porto velho see part ii item 8 financial statements supplementary data note 18 discussion sale investment sale investment argentina chile pipeline also expected completed first half 2009 reduce exposure pipeline projects 131 million sale remaining international investments completed changes regional political economic conditions could negatively impact anticipated proceeds may receive could result impairments remaining investments discussion events factors impacting results segment three years ended december 31 listed 1 relates disposition remaining shares international commodity exchange 2006 2 consists indirect expenses general administrative costs brazil 2008 remaining brazilian operations primarily interests boliviatobrazil argentinatochile pipelines generated ebit 7 million net 17 million foreign exchange loss related brazil reaisdenominated receivables related formerly owned manaus rio negro projects also process resolving several outstanding claims related manaus rio negro projects denominated brazilian reais ultimate resolution matters could impact results future first half 2007 generated ebit operations 30 million porto velho project 9 million manaus rio negro project however second half 2007 recorded impairments 57 million porto velho 15 million manaus rio negro project based adverse developments projects beginning second half 2007 ceased recognizing earnings porto velho project based inability realize earnings expected sales price investment 2007 brazilian operations generated ebit 12 million 2006 ebit 41 million porto velho 17 million manaus rio negro 6 million brazilian operations discussion matters impacted could impact remaining brazil investments see item 8 financial statements note 18 international power 2008 earnings relate primarily gains recognized sale investments central america asia results period impacted decision recognize earnings assets planned sell based inability realize earnings expected selling price recognize earnings approximately 3 million 10 million 26 million years ended december 31 2008 2007 2006 corporate expenses net corporate activities include general administrative functions well number miscellaneous businesses qualify operating segments material current year results following summary significant items impacting ebit corporate activities three years ended december 31 litigation insurance reserves 2008 recorded net favorable adjustment related certain legacy litigation matters including developments case corporation indemnification dispute see item 8 financial statements supplementary data note 13 partially offsetting adjustment marktomarket losses indemnification conjunction sale legacy ammonia facility marktomarket losses based significant changes ammonia prices 2008 uncertain whether current ammonia prices continue longterm based illiquid nature forward market ammonia changes ammonia prices may continue impact liability could impact results future 2007 recorded gain approximately 77 million reversal liability related coastal corporation’s legacy crude oil marketing trading business number pending litigation matters reserves related historical business operations also affect corporate results adverse rulings unfavorable outcomes settlements us related matters impacted results 2008 2007 2006 may impact future results extinguishment debt 2007 incurred losses 291 million conjunction repurchasing refinancing 5 billion debt amount included 86 million related repurchasing epep’s 12 billion notes information debt see item 8 financial statements note 12 interest debt expense interest debt expense approximately 09 billion 10 billion 12 billion years ended december 31 2008 2007 2006 decreased past three years primarily due retirements debt financing obligations net issuances see part ii item 8 financial statements supplementary data note 12 discussion income taxes 2008 overall effective tax rate continuing operations differed statutory rate due primarily brazilian ceiling test charge exploration production operations corresponding us brazilian tax benefit ii establishment valuation allowance deferred tax assets associated brazilian net operating losses based uncertainties ability realize assets 2007 overall effective tax rate continuing operations impacted earnings unconsolidated affiliates anticipate receiving dividends qualify dividend received deduction 2006 recorded 159 million tax benefits based primarily conclusion irs audits coastal corporation’s 19982000 tax years el paso’s 2001 2002 tax years resulted reduction tax contingencies reinstatement certain tax credits discussion items affecting effective tax rates year tax matters see part ii item 8 financial statements supplementary data note 5 discontinued operations discontinued operations 2007 2006 primarily include anr pipeline related assets years ended december 31 2007 2006 discontinued operations generated income 674 million losses 56 million 2007 recorded gain sale anr related operations 648 million net income taxes 354 million 2006 losses primarily result recording approximately 188 million deferred taxes upon agreeing sell stock anr related assets prior decision sell required record deferred taxes individual assets liabilities portion investment stock one companies items discussed part ii item 8 financial statements supplementary data note 2 commitments contingencies discussion commitments contingencies see part ii item 8 financial statements supplementary data note 13 liquidity capital resources past several years focus expanding core pipeline exploration production businesses provide longterm growth value period also strengthened balance sheet primarily significant debt reductions primary sources cash flow operations amounts available us revolving credit facilities conditions warrant may also generate funds capital market activities asset sales primary uses cash funding capital expenditure programs pipeline exploration production operations meeting operating needs repaying debt due repurchasing debt conditions warrant 2008 generated significant positive operating cash flows core pipeline production operations expect continue 2009 however second half 2008 global financial markets experienced significant volatility instability november 2008 announced certain actions would take including reduction capital program 2009 partnering certain expansion projects selling certain noncore assets primarily exploration production power segments since announcement taken several steps address liquidity needs discussed available liquidity outlook 2009 well ii overview cash flow activities 2008 available liquidity outlook 2009 december 31 2008 approximately 10 billion cash approximately 12 billion capacity available us various credit facilities exclusive 150 million available epb revolving credit facility traditionally pursued additional bank financings project financings debt capital markets transactions supplement available cash credit facilities used fund capital expenditure programs core businesses meet operating needs repay debt maturities planned cash capital expenditures pipeline exploration production operations 2009 follows november 2008 announced projected liquidity needs include 2009 capital program debt maturities may 2009 required us raise 500 million 800 million capital second half 2009 since time successfully generated additional liquidity approximately 19 billion primarily several debt offerings new credit facilities completing certain noncore asset sales since november 2008 completed three separate capital markets transactions totaling 12 billion included 500 million senior unsecured el paso notes december 2008 ii 250 million senior unsecured tgp notes january 2009 iii 500 million additional el paso senior unsecured notes february 2009 also obtained 364day 300 million secured revolving credit facility collateralized certain proved oil gas reserves production subsidiary entered additional 100 million letter credit facility issued 135 million debt subsidiary owns elba island lng facility transactions increased available liquidity approximately 33 billion february 27 2009 sold evaluating sale approximately 04 billion noncore assets primarily consist exploration production properties international power assets 02 billion already completed prior november 2008 also completed several financing transactions increased cash hand enhanced available liquidity including securing approximately 870 million project financing related equity investment gulf lng clean energy project ii entering new agreements provide us approximately 450 million additional letters credit support obligations purchase pipe associated constructing ruby pipeline project iii issuing 600 million unsecured el paso notes june 2008 iv contributing additional 30 interest cig 15 interest sng epb provided cash us 254 million currently 72 limited partner interest 2 general partner interest epb believe actions taken 2008 last several months provide sufficient liquidity carry us 2010 meeting operating needs repaying 11 billion 2009 debt maturities funding 2009 capital program accordingly expect access capital markets 2009 regardless whether successful obtaining equity partners capital projects however continue opportunistic building liquidity prudent meet longterm capital needs extent financial markets restricted decline commodity prices current levels announced actions sufficient possible additional adjustments plan outlook required could impact financial operating performance alternatives adjustments plan could include additional reductions discretionary capital program secured financing arrangements seeking partners one growth projects sale additional noncore assets could impact financial operating performance additional factors could impact future liquidity listed two additional factors could impact liquidity price risk management activities margining requirements exploration production segment derivative contracts provide price protection portion anticipated natural gas oil production following table shows contracted volumes minimum maximum average cash prices receive derivative contracts combined sale underlying production december 31 2008 additional information income impacts derivative contracts see exploration production segment’s results discussion 1 volumes presented tbtu natural gas mbbl oil prices presented per mmbtu natural gas per bbl oil 2 basis swaps effectively limit exposure differences nymex gas price location sell gas average prices listed amounts pay per mmbtu relative nymex price “lockin” locational price differences first two months 2009 settled remaining 2009 fixed price oil swaps receiving approximately 186 million cash entering new contracts approximately 1500 mbbls fixed price oil swaps anticipated 2009 oil production average price 4500 per barrel also entered 22 tbtu natural gas floor contracts average price 700 per mmbtu well 23 tbtu natural gas basis swap contracts average price 060 per mmbtu related anticipated 2009 natural gas production related anticipated 2010 natural gas production paid approximately 35 million premiums add 22 tbtu 700 per mmbtu floor contracts entered 20 tbtu fixed price swap contracts average price 728mmbtu 57 tbtu basis swap contracts average price 072 per mmbtu currently post letters credit required margin certain derivative contracts depending changes commodity prices interest rates could required post additional margin may recover margin earlier anticipated based derivative positions december 31 2008 010mmbtu increase price curve natural gas next several years would increase margin requirements approximately 2 million aggregate life contracts exposed adjusted fair value contracts risk counterparties derivative contracts may able perform post necessary collateral us assessed counterparty credit nonperformance risk given recent instability credit markets determined exposure primarily limited five financial institutions current standard poor’s credit rating better hurricanes ike gustav 2008 pipeline exploration production facilities damaged hurricanes ike gustav assessed damages resulting hurricanes corresponding impact estimated costs repair abandon impacted facilities although estimates may change future currently estimate total repair abandonment costs approximately 115 million pipelines 30 million 35 million exploration production business majority also expect capital expenditures 2009 2010 none amounts recoverable insurance due losses exceeding selfretention levels events overview cash flow activities 2008 generated positive operating cash flow core pipeline exploration production businesses 24 billion however earnings cash flow exploration production business adversely impacted decline commodity prices fourth quarter 2008 effects production volumes recent hurricanes addition generated approximately 07 billion proceeds primarily sale oil gas properties 12 billion proceeds conjunction issuance unsecured notes utilized amounts fund maintenance growth projects pipeline exploration production operations including acquisition 50 percent interest gulf lng clean energy project pay repurchase debt pay dividends among items year ended december 31 2008 2007 cash flows continuing operations summarized follows 1 includes activity revolving credit facilities offbalance sheet arrangements enter variety financing arrangements contractual obligations referred offbalance sheet arrangements include guarantees letters credit interests variable interest entities guarantees indemnifications involved various joint ventures ownership arrangements sometimes require financial performance guarantees financial guarantee obligated make payments guaranteed party fails make payments violates terms financial arrangement performance guarantee provide assurance guaranteed party execute terms contract required perform behalf also periodically provide indemnification arrangements related assets businesses sold arrangements include limited indemnifications income taxes resolution existing disputes environmental matters potential exposure guarantee indemnification agreements range specified amount unlimited dollar amount depending nature claim particular transaction many agreements may specify maximum potential exposure specified duration indemnification obligation circumstances amount duration unlimited arrangements specified dollar amount maximum stated value approximately 797 million primarily relates indemnification arrangements associated sale anr macae power facility brazil legacy assets amounts exclude guarantees issued related letters credit discussed note 12 included maximum stated value certain indemnification agreements expired however claims made prior expiration related claim periods unable estimate maximum exposure guarantee indemnification agreements provide limits amount future payments due uncertainty exposures december 31 2008 recorded obligations 62 million related indemnification arrangements liability consists primarily indemnification one subsidiaries provided related sale ammonia facility reflected financial statements fair value provided partial parental guarantee subsidiary’s obligations indemnification letters credit enter letters credit ordinary course operations well periodically conjunction sales assets businesses december 31 2008 outstanding letters credit approximately 16 billion including 08 billion letters credit securing recorded obligations related price risk management activities interests variable interest entities interests several variable interest entities primarily investments held power segment variable interest entity legal entity whose equity owners sufficient equity risk controlling financial interest entity required consolidate entities allocated majority variable interest entity’s losses return including fees paid entity december 31 2008 significant variable interest entity consolidate porto velho since primary beneficiary variable interest entity’s operations additional information regarding interests porto velho see part ii item 8 financial statements supplementary data note 18 investments earnings transactions unconsolidated affiliates contractual obligations party various contractual obligations include offbalance sheet arrangements described portion obligations reflected financial statements longterm debt liabilities commoditybased derivative contracts accrued liabilities obligations demand charges transportation storage commitments operating leases capital commitments reflected balance sheet following table discussion follows summarizes contractual cash obligations december 31 2008 periods presented long term financing obligations principal interest debt obligations included represent stated maturities unless otherwise puttable us prior stated maturity date interest payments shown stated maturity date related debt based contractual interest rate fixed rate debt ii current market interest rates contractual credit spread variable rate debt discussion debt obligations see item 8 financial statements supplementary data note 12 liabilities commoditybased derivative contracts amounts include fair value price risk management liabilities fair value commoditybased price risk management assets 971 million december 31 2008 reflected amounts also excluded margin deposits held associated contracts amounts discussion commoditybased derivative contracts see discussion commoditybased derivative contracts contractual liabilities included amount contractual environmental obligations included current noncurrent liabilities balance sheet excluded amounts expected contributions pension postretirement benefit plans expected contributions contractually required information expected contributions pension post retirement benefit plans see part ii item 8 financial statements supplementary data note 14 also excluded amounts liabilities unrecognized tax benefits 173 million december 31 2008 since cannot reasonably estimate time frame amounts may resolved operating leases discussion obligations see part ii item 8 financial statements supplementary data note 13 contractual commitments purchase obligations contractual commitments purchase obligations defined legally enforceable agreements purchase goods services fixed minimum quantities fixed minimum variable price provisions detail approximate timing underlying obligations included following • transportation storage commitments included amounts commitments demand charges firm access natural gas transportation storage capacity • commitments included amounts commitments purchasing pipe related assets pipeline operations commitments drilling seismic activities exploration production operations various maintenance engineering procurement construction contracts well service license agreements used operations excluded asset retirement obligations reserves litigation environmental remediation selfinsurance claims liabilities contractually fixed timing amount commoditybased derivative contracts use derivative financial instruments exploration production marketing segments manage price risk commodities commoditybased derivative contracts currently designated accounting hedges include options swaps natural gas oil power purchase supply contracts traded active exchanges following table details fair value commoditybased derivative contracts year maturity december 31 2008 following reconciliation commoditybased derivatives years ended december 31 2008 2007 fair value contract settlements fair value contract settlements period represents estimated amounts derivative contracts settled physical delivery commodity claim cash accounts receivable payable fair value contract settlements also includes physical financial contract terminations due counterparty bankruptcies sale settlement derivative contracts early termination sale entities contracts including amounts received sale option contracts changes fair value contracts change fair value contracts year represents change value contracts beginning period date origination acquisition settlement early termination settled terminated end period reclassifications dedesignated hedges fourth quarter 2008 removed hedging designation commoditybased derivative contracts related hedged natural gas oil production volumes critical accounting estimates significant accounting policies described note 1 consolidated financial statements included item 8 annual report form 10k preparation financial statements conformity generally accepted accounting principles requires management select appropriate accounting estimates make estimates assumptions affect reported amount assets liabilities revenue expenses disclosures contingent assets liabilities consider critical accounting estimates require difficult complex subjective judgment necessary accounting inherently uncertain matters could significantly influence financial results based changes judgments changes facts circumstances may result revised estimates actual results may differ materially estimates discussed development selection following critical accounting estimates related disclosures audit committee board directors accounting natural gas oil producing activities estimates proved reserves reflect quantities natural gas oil ngl geological engineering data demonstrate reasonable certainty recoverable future years known reservoirs existing economic conditions natural gas oil reserves estimates underlie number accounting estimates financial statements process estimating natural gas oil reserves particularly proved undeveloped proved nonproducing reserves complex requiring significant judgment evaluation available geological geophysical engineering economic data reserve estimates developed internally reserve reporting group separate operations group reviewed internal committees internal auditors addition thirdparty reservoir engineering firm appointed reports audit committee board directors conducted audit estimates significant portion proved reserves scope audit performed ryder scott included preparation independent estimate proved natural gas oil reserves estimates fields comprising approximately 80 percent total worldwide present value future cash flows pretax basis specific fields included ryder scott’s audit represented largest fields based value december 31 2008 total proved reserves 26 percent undeveloped 13 percent developed nonproducing data given field may change substantially time result numerous factors including additional development activity evolving production history continual reassessment viability production changing economic conditions result material revisions existing reserve estimates occur time addition subjective decisions variances available data various fields increase likelihood significant changes estimates proved natural gas oil reserves primarily impact property plant equipment amounts balance sheets depreciation depletion amortization amounts ceiling test charges income statements among items use full cost method account natural gas oil producing activities accounting method capitalize substantially costs incurred connection acquisition exploration development natural gas oil reserves including salaries benefits internal costs directly related finding activities asset retirement costs capitalized interest capitalized costs maintained full cost pools geographic area regardless whether reserves actually discovered record depletion expense capitalized amounts plus estimated finding development costs life proved reserves based unit production method factors held constant 10 percent increase estimated proved reserves would decrease unit production depletion rate 9 percent 10 percent decrease estimated proved reserves would increase unit depletion rate 11 percent natural gas oil properties include unproved property costs excluded costs depleted unproved property costs include nonproducing leasehold geological geophysical costs associated unevaluated leasehold drilling interests exploration drilling costs investments unproved properties major development projects direct interest exclude costs countrybycountry basis proved reserves found determined costs impaired costs excluded reviewed least quarterly determine exclusion fullcost pool continues appropriate costs determined impaired amount impairment transferred full cost pool reserve base exists expensed reserve base yet created impairments transferred full cost pool increase depletion rate country full cost accounting method natural gas oil properties required conduct quarterly impairment tests capitalized costs full cost pools impairment test referred ceiling test total capitalized costs net related income tax effects limited ceiling based present value future net revenues proved reserves discounted 10 percent net related income tax effects plus lower cost fair market value unproved properties utilize end period spot prices calculating future net revenues unless prices result ceiling test charge case may evaluate price recoveries subsequent end period discounted revenues greater equal total capitalized costs required writedown capitalized costs level discounted revenues fourth quarter 2008 recorded ceiling test charges 27 billion result decline commodity prices calculation charges based december 31 2008 spot natural gas price 571 per mmbtu oil price 4460 per barrel calculating ceiling test charges required hold prices constant life reserves even though actual prices natural gas oil volatile change period first two months 2009 natural gas oil prices declined levels december 31 2008 may required record additional ceiling test charges future unless commodity prices significantly increase oilfield service costs significantly decrease current levels december 2008 securities exchange commission sec issued final rule adopting revisions oil gas reporting requirements december 31 2009 adopt provisions sec’s final rule among things final rule revise definition proved reserves require companies use twelve month average commodity price determining future net revenues rather period end price currently required changes along proposed changes impact manner perform full cost ceiling test calculation determine related charge provisions final rule effective december 31 2009 cannot applied earlier date costbased regulation account regulated operations provisions statement financial accounting standards sfas 71 accounting effects certain types regulation economic effects regulation result regulated company recording assets costs expected approved recovery customers recording liabilities amounts expected returned customers ratesetting process period different period amounts would recorded unregulated enterprise accordingly record assets liabilities result regulated ratemaking process would recorded gaap nonregulated entities management regularly assesses whether regulatory assets probable future recovery considering factors applicable regulatory changes recent rate orders applicable regulated entities based continual assessment management believes existing regulatory assets probable recovery periodically evaluate applicability sfas 71 consider factors regulatory changes impact competition costbased regulation ends competition increases may reduce certain asset balances reflect market basis lower cost writeoff associated regulatory assets accounting legal environmental reserves guarantees indemnifications accrue legal environmental reserves assessments indicate probable liability incurred asset recovered amount reasonably estimated estimates liabilities based evaluation potential outcomes currently available facts case environmental reserves existing technology presently enacted laws regulations taking consideration likely effects societal economic factors estimates associated onsite offsite groundwater technical studies legal costs actual results may differ estimates often revised future either negatively positively depending upon actual outcomes changes expectations based facts surrounding matter december 31 2008 accrued approximately 87 million legal matters reduced 14 million related insurance receivables accrued 204 million environmental matters environmental estimates range approximately 204 million approximately 388 million amounts accrued represent combination two estimation methodologies first likely outcome reasonably estimated cost accrued 12 million second likely outcome cannot estimated range costs established 192 million 376 million lower end expected range accrued also guarantee indemnification agreements related various joint ventures ownership arrangements require us assess potential exposure range specified amount unlimited dollar amount depending nature claim particular transaction arrangements specified dollar amount maximum stated value approximately 797 million december 31 2008 recorded obligations 62 million related guarantees indemnification arrangements unable estimate maximum exposure guarantee indemnification agreements provide limits amount future payments agreement due uncertainty exposures information see balance sheet arrangements accounting pension postretirement benefits reflect asset liability pension postretirement benefit plans based funded status december 31 2008 pension plans funded 216 million postretirement benefit plans funded 463 million pension postretirement benefit obligations net benefit costs primarily based actuarial calculations use various assumptions performing calculations including related return expect earn plan assets rate expect compensation employees increase plan term estimated cost health care benefits provided plans factors significant assumption utilize discount rates used calculating benefit obligations select discount rates matching timing amount expected future benefit payments pension postretirement benefit obligations average yields various highquality bonds corresponding maturities actual results may differ assumptions included calculations result estimates associated pension postretirement benefits often revised future income statement impact changes assumptions related benefit obligations along changes plans items deferred amortized income either period expected future service active participants lives plan participants record deferred amounts accumulated comprehensive income nonregulated operations either regulatory asset liability regulated operations december 31 2008 deferred net losses approximately 745 million net income taxes accumulated comprehensive income following table shows impact one percent change primary assumptions used actuarial calculations associated pension postretirement benefits year ended december 31 2008 millions 1 actual return plan assets one percent lower expected return plan assets expected cash contributions pension postretirement benefit plans would significantly change estimates net benefit expense income partially based expected return pension plan assets use marketrelated value plan assets determine expected return pension plan assets determining marketrelated value plan assets differences expected actual asset returns deferred three years considered inclusion net benefit expense income used fair value plan assets instead marketrelated value plan assets determining expected return pension plan assets net benefit expense would 18 million lower year ended december 31 2008 price risk management activities record derivative instruments used price risk management activities fair values estimate fair value derivative instruments using exchange prices thirdparty pricing data valuation techniques incorporate specific contractual terms statistical simulation analysis present value concepts one primary assumptions used estimate fair value derivative instruments pricing assumptions based upon price curves derived actual prices observed market pricing information supplied thirdparty valuation specialist independent pricing sources models rely forward pricing information extent rely pricing information received third parties developing assumptions based part whether information considers availability observable data marketplace example relatively illiquid markets pjm forward power market may make adjustments pricing information receive third parties based evaluation whether third party market participants would use pricing assumptions consistent sources table presents hypothetical sensitivity commoditybased price risk management activities changes fair values arising immediate selected potential changes natural gas oil power prices december 31 2008 another significant assumption discount rates use determining fair value derivative instruments table presents hypothetical sensitivity commoditybased price risk management activities changes fair values arising changes discount rates used determine fair value derivatives december 31 2008 significant assumptions use determining fair value derivative instruments related anticipated market liquidity credit nonperformance risk counterparties adjust fair value derivative assets risk nonperformance counterparties considering collateral posted derivative changes counterparties’ creditworthiness measured part based changes bond yields changes actively traded credit default swap prices available information credit standing adjust fair value derivative liabilities creditworthiness utilizing similar inputs including consideration noncash collateral posted counterparties january 1 2009 adopt provisions emerging issues task force issue 085 require us determine fair value derivative liabilities without consideration noncash collateral description standard see item 8 financial statements supplementary data note 1 believe application assumptions derive fair value representative proceeds would receive pay disposed derivative instruments assumptions methodologies use determine fair values derivatives may differ used derivative counterparties differences significant actual settlement price risk management activities could also differ materially fair value recorded could impact future operating results deferred taxes uncertain income tax positions record deferred income tax assets liabilities reflecting tax consequences deferred future periods based differences financial statement carrying value assets liabilities tax basis assets liabilities additionally deferred tax assets liabilities also reflect assessment tax positions taken resulting tax basis likely sustained audited taxing authorities significant judgments tax related matters include limited items noted matters involve exercise significant judgment could change materially impact financial condition results operations discussion items income tax matters see item 8 financial statements supplementary data note 5 valuation allowance realization deferred tax assets depends recognition sufficient future taxable income specific tax jurisdictions periods temporary differences deductible valuation allowances established necessary reduce deferred income tax assets amounts believe likely recovered evaluating valuation allowance consider reversal existing temporary differences existence taxable income prior carryback years tax planning strategies future taxable income taxable jurisdictions latter two involve exercise significant judgment changes valuation allowance could materially impact results operations uncertain tax positions liabilities unrecognized tax benefits related uncertain tax positions connected ongoing examinations open tax years changes assessment liabilities may require us increase liability record additional tax expense reverse liability recognize tax benefit would positively negatively impact effective tax rate undistributed earnings foreign investees certain unconsolidated affiliates record deferred tax liabilities undistributed earnings foreign investments anticipate earnings repatriated plan repatriate foreign undistributed earnings provision made us taxes foreign withholding taxes changes repatriation assumptions including repatriation proceeds sales investments could require us record additional deferred taxes additionally believe certain unconsolidated affiliates’ undistributed earnings ultimately distributed us dividends would eligible dividends received deduction joint venture partners intent ability recover cumulative undistributed earnings time dividends however subsequently determine unconsolidated affiliates would unable pay dividends would required record additional deferred income tax liabilities asset investment impairments accounting rules asset investment impairments require us continually monitor businesses business environment performance investments determine event occurred indicates longlived asset investment may impaired event occurs determination involves judgment estimate fair value asset considers number factors including potential value would receive sold asset projected cash flows asset based current anticipated future market conditions discount rates assessment project level cash flows requires significant judgment make projections assumptions many years future pricing demand competition operating costs legal regulatory issues factors often outside control due imprecise nature projections assumptions actual results often differ estimates utilize cash flow projections assess ability recover carrying value assets investments based either longlived assets’ ability generate future cash flows undiscounted basis ii fair value investments unconsolidated affiliates whether decline fair value carrying amount considered temporary impairment indicated record impairment charge excess carrying value asset fair value recorded impairments longlived assets 41 million 20 million 16 million impairments losses investments advances unconsolidated affiliates 127 million 75 million 13 million years ended december 31 2008 2007 2006 also recorded asset investment impairments discontinued operations 13 million net minority interest year ended december 31 2006 future changes economic business environment impact assessments potential impairments new accounting pronouncements issued yet adopted see part ii item 8 financial statements supplementary data note 1 new accounting pronouncements issued yet adopted item 7aitem 7 management’s discussion analysis financial condition results operations overview management’s discussion analysis mda read conjunction consolidated financial statements accompanying footnotes mda includes forwardlooking statements subject risks uncertainties may result actual results differing statements make risks uncertainties discussed item 1a risk factors listed general outline mda business includes summary business purpose description factors influencing profitability summary 2009 performance outlook 2010 results operations includes yearoveryear analysis results business segments corporate activities income statement items including trends may impact business future liquidity capital resources includes general discussion sources uses cash available liquidity outlook 2010 overview cash flow activity 2009 additional factors could impact liquidity balance sheet arrangements contractual obligations commoditybased derivative contracts includes discussion balance sheet arrangements including guarantees letters credit ii contractual obligations iii derivative contracts used manage price risks associated natural gas oil production critical accounting estimates includes discussion accounting estimates involve use significant assumptions andor judgments preparation financial statements business purpose provide natural gas related energy products safe efficient dependable manner interests north america’s largest interstate natural gas pipeline systems provide stable base earnings cash flow significant backlog committed expansion projects also large independent natural gas oil producer focused generating competitive financial returns disciplined capital allocation portfolio management cost control marketing selling natural gas oil production optimal prices managing associated price risks factors influencing profitability pipeline operations rateregulated accordingly generate profit based ability earn return excess costs rates charge customers exploration production operations generate profits dependent prices natural gas oil costs explore develop produce natural gas oil volumes able produce among factors longterm profitability operating segments primarily influenced following factors • successfully executing remaining backlog committed expansion projects time budget developing new growth projects market supply areas • contracting recontracting pipeline capacity customers • maintaining obtaining approval ferc acceptable rates terms service expansion projects • improving operating efficiency exploration production • growing natural gas oil proved reserve base production volumes successful drilling programs • finding producing natural gas oil reasonable cost • managing price risks optimize realized prices natural gas oil production addition factors future profitability also affected impacts volatility financial commodity markets debt level related interest costs successful resolution historical contingencies completing orderly exit remaining power assets historical derivative contracts remaining noncore assets summary 2009 financial operational performance 2009 generated significant operating cash flows core pipeline exploration production businesses executing plan outlined late 2008 respond volatility financial markets energy industry global economy 2009 placed several pipeline expansion projects service obtained partner ruby project secured financing portion remaining pipeline backlog exploration production business despite lower level drilling activity lower natural gas prices lower capital spending 2009 expanded resource inventory lowrisk onshore reserves lowered operating costs managed exposure volatile commodity price environment expanded hedging program 2011 however due lower natural gas prices end first quarter 2009 recorded approximately 21 billion noncash ceiling test charges primarily domestic full cost pool significantly impacted overall financial results believe stability pipeline earnings coupled hedging program exploration production business continue protect earnings base cash flows operations additionally believe managed capital program provide pipeline backlog retaining substantially existing natural gas oil resource positions future exploration production activities following table provides 2009 operational highlights core businesses area operations significant highlights pipelines continued make progress backlog expansion projects placing four growth projects service budget including carthage expansion totem gas storage project wic piceance lateral expansion concord lateral expansion obtained 50 percent partner ruby pipeline project completed 21 billion financings partially fund pipeline backlog successfully settled sng rate case contract extensions august 2013 rate moratorium september 2012 exploration production achieved overall domestic drilling success rate 96 percent shifted focus unconventional resource plays domestically including haynesville shale northwest louisiana east texas eagle ford shale south texas altamontbluebellcedar rim field fractured tight sands utah brought camarupim project line brazil found hydrocarbons two wells drilled egypt managed price risk derivative contracts 2009 2010 2011 natural gas production well 2009 2010 oil production noncore power segment completed sale interests porto velho power generation facility argentinatochile pipeline partners projects october 2009 also announced reentry midstream business believe movement unconventional supply basins present future opportunities outlook 2010 expect pipeline operations continue provide strong base earnings operating cash flow 2010 expect relatively stable rates within pipeline group majority pipelines outstanding rate cases pending ferc also increased 2010 capital expenditure program business approximately 29 billion backlog growth projects remain focused implementing time budget currently plan place three projects service end 2010 however largest portion capital program related anticipated construction ruby pipeline project finally consider additional opportunities master limited partnership mlp epb markets permit exploration production business also expect generate significant operating cash flow earnings although additional noncash ceiling test charges could impact earnings future result future declines natural gas oil prices anticipate spending approximately 11 billion capital expenditures business 2010 approximately onehalf domestic capital program targeted haynesville altamont eagle ford areas 175 million planned brazil egypt programs planned average daily production 2010 expected range 740 mmcfed 780 mmcfed including approximately 60 mmcfed 65 mmcfed ownership interest production four star although commodity prices remain lower levels expanded financial derivative contracts place 2010 providing 641 average floors approximately 85 percent estimated consolidated natural gas production 75 average floors approximately 90 percent estimated consolidated oil production contracts also allow potential upside december 31 2009 approximately 18 billion available liquidity 2010 estimated 41 billion capital program provides funding pipeline backlog well exploration production reserves growth 2010 capital program consists 29 billion related pipeline business including 100 ruby pipeline capital approximately 11 billion related exploration production business 2010 pipeline capital requirements significant 2011 requirements decline significantly end 2011 backlog placed service accordingly 2012 expect benefit earnings generated substantially completed pipeline backlog greater exploration production volumes 2010 debt maturities nominal believe well positioned meet obligations based anticipated performance core businesses financing actions taken date planned 2010 additional steps noted enhance liquidity discussion see liquidity capital resources november 2009 announced additional steps would take improve financial flexibility fund core businesses additional steps designed provide incremental funding 2010 capital programs focused industryleading pipeline backlog growth opportunities growing unconventional natural gas drilling inventory exploration production business ii improve overall cost structure iii protect credit profile iv manage commodity risk v enhance overall shareholder returns steps continue assess take actions prudent meet longterm objectives capital requirements well address changes financial commodity markets results operations overview december 31 2009 core operating business segments pipelines exploration production also marketing segment markets natural gas oil production manages legacy trading activities power segment interests power pipeline assets south america asia segments managed separately provide variety energy products services require different technology marketing strategies corporate activities include general administrative functions well miscellaneous businesses contracts assets immaterial management uses earnings interest expense income taxes ebit measure assess operating results effectiveness business segments consist consolidated businesses investments unconsolidated affiliates believe ebit useful investors allows evaluate effectively operating performance using performance measure analyzed internally management define ebit net income loss adjusted items interest debt expense ii income taxes iii net income attributable noncontrolling interests investors may evaluate operating results without regard financing methods capital structure ebit may comparable measures used companies additionally ebit considered conjunction net income loss income loss income taxes performance measures operating income operating cash flows reconciliation ebit segment consolidated net income loss three years ended december 31 discussions follow provide additional analysis year results business segments corporate activities income statement items pipelines segment overview pipelines segment operates primarily united states consists interstate natural gas transmission storage lng terminalling related services face varying degrees competition segment existing proposed pipelines proposed lng facilities well alternative energy sources used generate electricity hydroelectric power nuclear energy wind solar coal fuel oil revenues transportation storage lng terminalling related services consist two types percent 2009 type description revenues reservation revenues customers referred firm customers reserve capacity pipeline systems storage facilities lng terminalling facilities firm customers obligated pay monthly reservation demand charge regardless amount natural gas transport store term contracts usage revenues firm customers interruptible customers without reserved capacity pay usage charges based volume gas actually transported stored injected withdrawn also earn revenues processing sale natural gas liquids miscellaneous sources ferc regulates rates charge customers rates generally function cost providing services customers including reasonable return invested capital regulated nature high percentage revenues attributable reservation charges revenues historically relatively stable however financial results subject volatility due factors changes natural gas prices changes supply demand regulatory actions competition weather declines creditworthiness customers also experience earnings volatility certain pipelines amount natural gas used operations differs amounts receive purpose historically much business conducted longterm contracts customers however many customers shifted traditional dependence longterm contracts portfolio approach balances shortterm opportunities longterm commitments shift increase volatility revenues due changes market conditions competition driven state utility deregulation local distribution company mergers new supply sources volatility natural gas prices demand shortterm capacity new power plant markets continue manage process renewing expiring contracts limit risk significant impacts revenues ability extend existing customer contracts remarket expiring contracted capacity dependent competitive alternatives regulatory environment federal state local levels market supply demand factors relevant dates contracts extended expire duration new renegotiated contracts affected current prices competitive conditions judgments concerning future market trends volatility subject regulatory requirements attempt recontract remarket capacity maximum rates allowed tariffs although times enter firm transportation contracts amounts less maximum rates remain competitive refer difference maximum rates allowed tariff contractual rate charge “discounts” existing contracts mature various times varying amounts throughput capacity weighted average remaining contract term active contracts approximately five years december 31 2009 contract expiration portfolio associated revenue expirations firm transportation contracts wholly majority owned systems december 31 2009 including terms beginning 2010 later summary operational financial performance 2009 continued deliver strong operational financial performance across pipelines benefitting several expansion projects placed service projects included carthage expansion may totem gas storage june wic piceance lateral expansion september concord lateral expansion october continue make significant progress remaining backlog expansion projects 2009 epb issued additional public common units used proceeds primarily acquire additional interests cig december 31 2009 ownership interest epb consisted two percent general partner interest 65 percent limited partner interest 2010 plan spend 29 billion capital pipeline business including 25 billion backlog expansion projects significant projects listed grouped anticipated inservice dates listed additional information related significant backlog projects • elba expansion iii elba express cypress phase iii second quarter 2009 bg lng services llc bg sng elba express southern lng inc entered agreements delay inservice date elba expansion iii phase b project bg’s option late december 31 2014 event certain conditions unable met bg terminate elba expansion iii phase b project exchange delaytermination option bg committed subscribe certain firm phase b capacity elba express pipeline provide certain rate considerations existing transportation contract sng pipeline addition bg given right proceed phase iii cypress expansion project sng phase elba expansion iii vaporization facilities elba express project expected commence commercial operations march 2010 • wic expansion wic expanded scope project add second compressor unit kanda lateral due increased shipper commitments portion project add 12400 horsepower compressor station kanda lateral increase capacity lateral 595 mdthd wic also plans install three miles pipeline reconfigure one compressor wamsutter station provide 155 mdthd natural gas deliveries wic mainline third party pipeline onto opal hub proposed ruby pipeline • ruby pipeline project expect ruby pipeline project consist approximately 680 miles 42” pipeline multiple compressor stations total horsepower approximately 157000 however final sizing based market support september 2009 received preliminary determination ferc nonenvironmental issues related project january 2010 ferc issued final environmental impact statement eis related ruby project subject ferc approvals project expected commence construction first half 2010 anticipated placed service first quarter 2011 • fgt phase viii project september 2009 ferc issued final eis also received pipeline hazardous materials safety administration special permit department transportation order operate pipeline higher operating pressures november 2009 ferc approved project • gulf lng february 2008 completed acquisition 50 percent interest gulf lng clean energy project constructing ferc approved lng terminal pascagoula mississippi designed sendout capacity 15 bcfd expected placed service october 2011 • tgp 300 line expansion firm transportation capacity resulting project northeast us market area fully subscribed one shipper based precedent agreement executed third quarter 2009 environmental assessment expected issued ferc first quarter 2010 • south system ii southeast supply header south system ii expansion project expand sng’s pipeline system mississippi alabama georgia adding approximately 81 miles pipeline looping replacement sng’s south system 17310 horsepower compression serve existing power generation facility atlanta georgia area project completed three phases phase expected add additional 122 mmcfd capacity southeast supply header expected provide access pipeline interconnects several supply basins including barnett shale bossier sands arkoma fayetteville shale basins expected provide sng additional 350 mmcfd supply capacity • tgp northeast upgrade project february 2010 tgp entered precedent agreements two shippers provide 636000 mmbtud additional firm transportation service receipt points marcellus shale basin interconnect new jersey order accommodate additional service pursue northeast upgrade project includes approximately 37 miles 30” pipeline looping approximately 20600 horsepower additional compression expected cost project 416 million construction anticipated placed service november 2013 successful execution committed pipeline backlog continue require effective project management addition securing partner ruby pipeline project 2009 significantly mitigated risk associated remaining backlog subscribing approximately 90 percent capacity aggregate backlog contract terms 10 30 years primarily investmentgrade customers purchasing committing purchase steel fixed prices largest projects well contracting significant portion construction costs addition current backlog contracted organic growth projects potential projects various phases commercial development many projects involve expansion capacity serve increased natural gasfired generation loads well new supply projects potential expansion projects would inservice dates 2014 beyond successful contracting new projects capital requirements could substantial would incremental current projects although pursue development potential projects time assurance successful negotiating definitive binding contracts necessary projects • potential power plant loads similar sng’s south system iii project pursuing various expansion projects particularly southeastern portion united states us serve increased natural gasfired generation loads addition along front range cig’s system utilities various projects development involve constructing new natural gasfired generation part provide backup capacity required renewable generation available certain daily seasonal periods operating results 1 volumes exclude intrasegment activities 2 represents proportional share unconsolidated affiliates 3 2007 ebit represents ebit continuing operations discussion details impact ebit significant events 2009 compared 2008 compared 2007 also provided outlook events may affect operations future 1 consists individually insignificant items several pipeline systems expansions 2009 2008 reservation revenues throughput volumes increased due projects placed service 2009 2008 placed carthage expansion project totem gas storage facility concord lateral expansion wic piceance lateral expansion wic kanda lateral project phase ii cypress project cheyenne plains compression expansion project phase southeast supply header project medicine bow expansion high plains pipeline projects service reservation usage revenues year ended december 31 2009 compared 2008 reservation usage revenues also impacted • increased revenues mainline lateral capacity rocky mountain region systems primarily due new contracts restructured contract terms • additional capacity sales approximately 8 million primarily marcellus basin northeast market area tgp system • increased reservation services revenues approximately 24 million primarily sng system due higher tariff rates effective september 1 2009 pursuant sng’s rate case settlement discussed • higher reservation charges approximately 11 million capacity epng system resulting increased contracted capacity primary delivery points california increase epng’s tariff rates effective january 1 2009 subject refund • unfavorable usage revenue approximately 20 million due decreased activity various interruptible services lower demand southeast interconnects resulting increased competition tgp system year ended december 31 2009 throughput volumes tgp epng systems decreased compared 2008 due part general weakness natural gas demand united states including northeast southwest although fluctuations throughput pipeline systems limited effect shortterm results since material portion revenues derived firm reservation charges indication risks may face seeking recontract renew existing firm transportation contracts continuing negative economic impacts demand well adverse shifting sources supply could negatively impact basis differentials ability renew firm transportation contracts expiring system ability renew contracts current rates determine significant change costs billing determinants pipeline systems option file rate cases certain pipelines ferc recover prudently incurred costs year ended december 31 2008 compared 2007 increase reservation usage revenues primarily due • approximately 22 million related increased demand offsystem mainline capacity rocky mountain region systems primarily due lower natural gas prices rocky mountains compared regions united states • approximately 15 million related additional firm capacity sold northern southern regions tgp system partially offset lower surcharges certain firm customers system • approximately 29 million related increased reservation usage revenues epng system due higher amounts charged recontracted capacity arizona california • approximately 1 million related additional interruptible firm commodity services provided several pipeline systems gas used operations revaluations year ended december 31 2009 overall ebit 32 million favorable compared 2008 primarily due retained fuel volumes excess fuel used operations higher realized prices operational sales lower electric compression utilization lower index prices related fuel imbalance revaluations settlement gas balance related items addition 2008 cig wic recorded cost revenue tracker adjustments associated implementation fuel related gas cost recovery mechanisms ferc approved subject outcome technical conferences implementation mechanisms protested limited number shippers july 31 2009 october 1 2009 ferc issued orders cig wic respectively directing remove cost revenue components fuel recovery mechanisms additionally october 1 2009 epng received order ferc directing epng remove cost revenue component fuel recovery mechanism epng’s compliance filing remove cost revenue component approved fourth quarter 2009 future earnings may impacted positively negatively depending fluctuations gas prices related revaluation epng’s recoveries imbalances system encroachments epng’s tariff continues provide difference quantity fuel retained fuel used operations lost unaccounted flowed charged shippers continue explore options minimize price volatility associated operational pipeline activities year ended december 31 2008 compared period 2007 ebit favorably impacted 20 million due higher volumes gas used tgp operations bankruptcy proceeds 2008 revenue increased 39 million related calpine corporation’s calpine’s rejection transportation contracts us primarily associated distributions received calpine’s approved plan reorganization 2008 2007 recorded income approximately 10 million 5 million net amounts potentially owed certain customers related amounts recovered enron bankruptcy settlement 2007 received 10 million settle bankruptcy claim usgen new england inc operating general administrative expenses year ended december 31 2009 operating general administrative expenses lower 2008 primarily due 18 million decreased field repair maintenance expense several pipeline systems partially offsetting cost reductions severance costs approximately 14 million year ended december 31 2008 operating general administrative expenses higher 2007 primarily due increased labor costs approximately 43 million support growth customer activities approximately 29 million additional maintenance work required several pipeline systems gainloss longlived assets 2009 recorded gain 8 million related sale cig’s natural buttes compressor station gas processing plant 2008 recorded impairments 41 million including impairment related essexmiddlesex lateral project due prolonged permitting process impairment epng arizona gas storage projects longer developing due declining real estate values 2007 recorded 10 million impairment certain pipeline assets originally purchased repair certain offshore hurricane damage following decision use assets ii loss approximately 9 million epng’s east valley line lateral pursuant ferc determination accounting treatment pending sale certain transmission facilities iii 7 million pretax gain sale pipeline lateral hurricanes 2008 incurred damage sections gulf coast offshore pipeline facilities due hurricanes ike gustav ebit unfavorably impacted 8 million 2009 due repair costs 31 million 2008 related hurricanes due gas loss various damaged pipelines lower volume gas used operations repair costs exceed selfretention levels equity earnings citrus 2008 equity earnings citrus investment decreased compared 2007 primarily due citrus’s favorable settlement 2007 approximately 8 million litigation brought spectra lng sales formerly duke energy lng sales inc wrongful termination gas supply contract citrus’ sale receivable 2007 approximately 3 million related bankruptcy enron north america net income attributable noncontrolling interests net income attributable noncontrolling interests increased 2009 2008 due additional public common units issued majorityowned mlp july 2009 ii contribution mlp additional interests cig 18 percent july 2009 20 percent september 2008 sng 15 percent september 2008 december 31 2009 mlp owned 58 percent cig 25 percent sng 100 percent wic owned 67 percent mlp regulatory matters pipeline systems periodically file changes rates subject approval ferc changes rates tariff provisions resulting regulatory proceedings potential positively negatively impact profitability currently certain pipelines expected continue operating existing rates pipelines projected upcoming rate actions anticipated effective dates 2011 2013 january 2010 ferc approved sng’s settlement sng increased base tariff rates ii implemented volume tracker gas used operations iii agreed file next general rate case effective august 31 2012 later september 1 2013 iv extended vast majority sng’s firm transportation contracts august 31 2013 june 2008 epng filed rate case ferc required settlement previous rate case filing proposed increase epng’s base tariff rates august 2008 ferc issued order accepting proposed rates effective january 1 2009 subject refund outcome hearing technical conference ferc issued order december 2008 generally accepted epng’s proposals technical conference proceeding ferc appointed administrative law judge preside hearing epng unable reach negotiated settlement customers remaining issues settlement negotiations continuing however hearing postponed may 2010 outcome settlement discussions hearing currently determinable exploration production segment overview strategy exploration production segment conducts natural gas oil exploration production activities profitability performance segment driven ability locate develop economic natural gas oil reserves extract reserves lowest possible production administrative costs accordingly manage business goal creating value disciplined capital allocation cost control portfolio management strategy focuses building applying competencies assets repeatable programs executing improve capital expense efficiency maximizing returns adding assets inventory match competencies divesting assets 2009 us shifted focus unconventional resource plays including haynesville shale northwest louisiana east texas eagle ford shale south texas altamontbluebellcedar rim field fractured tight sands utah domestic natural gas oil reserve portfolio blends lower decline rate typically longer lived assets central western divisions steeper decline rate shorter lived assets gulf coast division approximately 79 percent 2009 capital spent domestic projects internationally portfolio consists producing fields along several exploration development projects offshore brazil exploration projects egypt 2009 international capital primarily brazil constituted approximately 21 percent total capital program success international programs brazil egypt require effective project management strong partner relations obtaining approvals regulatory agencies 2009 challenging commodity price environment resulted ceiling test charges totaling 21 billion coupled unprecedented challenges credit markets also reduced capital spending 2009 continue evaluate acquisition growth opportunities focused core competencies areas competitive advantage strategic acquisitions like one completed december 2009 natural gas oil properties altamontbluebellcedar rim field utah support corporate objectives providing us greater opportunities achieve long term performance goals leveraging operational expertise already possessed key operating areas balancing exposure regions basins commodities achieving riskadjusted returns competitive available within existing inventory increasing reserves supplementing current drilling inventory addition effectively executing strategy profitability performance impacted changes commodity prices ii industrywide changes cost drilling oilfield services iii effect hurricanes weather impacts daily production operating capital costs extent possible attempt mitigate factors part risk management activities maintain derivative contracts reduce financial impact downward commodity price movements significant operational factors affecting year ended december 31 2009 production average daily production year 763 mmcfed including 72 mmcfed equity interest production four star analysis 2009 production division mmcfed 2009 drilling results western achieved 100 percent success rate seven gross wells drilled brazil achieved 75 percent success rate four gross wells drilled egypt hydrocarbons found two five 40 percent gross exploratory wells drilled participated drilling discussion activities brazil egypt see part item 1 business exploration production segment international cash operating costs monitor cash operating costs required produce natural gas oil production volumes cash operating costs nongaap measure calculated per mcfe basis includes total operating expenses less depreciation depletion amortization expense ceiling test impairment charges transportation costs cost products cash operating costs per unit valuable measure operating performance efficiency exploration production segment year ended december 31 2009 cash operating costs per unit decreased 182mcfe compared 197mcfe 2008 decrease 2009 primarily due lower lease operating expenses production taxes partially offset lower production volumes 2009 versus 2008 reserve replacement ratioreserve replacement costs calculate two primary metrics reserve replacement ratio ii reserve replacement costs measure ability establish longterm trend adding reserves reasonable cost core asset areas reserve replacement ratio indicator ability replenish annual production volumes grow reserves important us economically find develop new reserves offset produced volumes provide future production given inherent decline hydrocarbon reserves addition calculate reserve replacement costs assess cost adding reserves ultimately included depreciation depletion amortization expense believe ability develop competitive advantage natural gas oil companies dependent adding reserves core asset areas lower costs competition calculate metrics follows reserve replacement ratio sum reserve additions1 2 actual production corresponding period reserve replacement costsmcfe total oil gas capital costs3 sum reserve additions 1 2 1 reserve additions include proved reserves reflect reserve revisions prices performance extensions discoveries additions acquisitions include unproved reserve quantities proved reserve additions attributable investments accounted using equity method present metrics separately including excluding impact price revisions reserves demonstrate effectiveness drilling program exclusive economic factors price outside control amounts derived directly table presented item 8 financial statements supplementary data supplemental natural gas oil operations 2 proved reserves used calculation reserve replacement ratio reserve replacement costs 2009 determined based sec’s final rule modernization oil gas reporting final rule effective december 31 2009 final rule among things revised definitions proved reserves required us use first day 12month average price determining estimated proved reserves 3 total oil gas capital costs include costs development exploration property acquisition activities conducted add reserves exclude asset retirement obligations amounts derived directly table presented item 8 financial statements supplementary data supplemental natural gas oil operations reserve replacement ratio reserve replacement costs per unit statistical indicators limitations including predictive comparative value annual measure reserve replacement ratio limited typically varies widely based extent timing new discoveries project sanctioning property acquisitions addition since reserve replacement ratio consider cost timing developing future production new reserves cannot used measure value creation exploration acquisition development natural gas oil reserves inherently uncertain discussed part item 1a risk factors risks related business one risks uncertainties ability spend sufficient capital increase reserves currently expect spend amounts future assurances timing magnitude expenditures classification proved reserves developed undeveloped december 31 2009 proved developed reserves represent approximately 67 percent total proved reserves proved developed reserves generally begin producing within year added whereas proved undeveloped reserves generally require major future expenditure table shows reserve replacement costs reserve replacement ratio domestic worldwide operations including excluding effect price revisions reserves years ended december 31 typically cite reserve replacement costs context multiyear trend recognition limitation single year measure also demonstrate consistency stability essential business model table shows reserve replacement costs domestic worldwide operations three years ended december 31 2009 capital expenditures oil gas capital expenditures follows three years ended december 31 1 total oil gas capital costs include costs development exploration property acquisition activities conducted add reserves exclude asset retirement obligations amounts derived directly table presented item 8 financial statements supplementary data supplemental natural gas oil operations outlook 2010 anticipate continued volatility commodity markets general economic climate exercise flexibility allocating capital response changing conditions expect following worldwide basis price risk management activities enter derivative contracts natural gas oil production stabilize cash flows reduce risk financial impact downward commodity price movements commodity sales protect economic assumptions associated capital investment programs apply marktomarket accounting financial derivative contracts hedge entirety price risk strategy partially reduces commodity price exposure reported results operations financial position cash flows impacted significantly commodity price movements period adjustments strategy decision enter new positions alter existing positions made based goals overall company 2009 entered option basis swap contracts 2010 2011 natural gas production swaps 2010 oil production paid 173 million premiums enter contracts following table reflects contracted volumes minimum maximum average prices receive derivative contracts december 31 2009 1 volumes presented tbtu natural gas mbbl oil prices presented per mmbtu natural gas per bbl oil 2 basis swaps effectively limit exposure differences nymex gas price location sell gas average prices listed amounts pay per mmbtu relative nymex price “lockin” locational price differences internationally production camarupim field brazil sold price adjusted quarterly based basket fuel oil prices addition amounts included table december 31 2009 fuel oil swaps effectively lock price approximately 400 per mmbtu approximately 8 tbtu projected brazilian natural gas production 2010 first two months 2010 entered 635 mbbls fixed price swaps anticipated 2010 oil production average price 8518 per barrel addition entered collars 2008 mbbls anticipated 2011 oil production floor price 80 per barrel average ceiling price 9556 per barrel basis swaps average price 021 per mmbtu 15 tbtu anticipated 2011 natural gas production operating results variance analysis information provides financial results analysis significant variances results periods ended december 31 year ended december 31 2009 compared year ended december 31 2008 ebit 2009 increased 99 million compared 2008 table shows significant variances financial results 2009 compared 2008 physical sales physical sales represent accrualbased commodity sales transactions customers year ended december 31 2009 natural gas oil condensate ngl revenues decreased compared 2008 due lower commodity prices lower production volumes realized unrealized gains financial derivatives year ended december 31 2009 recognized net gains 687 million compared net gains 196 million 2008 due lower natural gas oil prices 2009 relative commodity prices contained derivative contracts depreciation depletion amortization expense 2009 depreciation depletion amortization expense decreased result lower depletion rate lower production volumes lower depletion rate primarily result impact ceiling test charges recorded december 2008 march 2009 production costs production costs decreased 2009 compared periods 2008 primarily due lower production taxes result lower natural gas oil revenues lower lease operating expenses cost declines lower commodity price environment general administrative expenses general administrative expenses increased 2009 compared periods 2008 primarily due reversal 20 million accrual 2008 result favorable ruling legal matter higher severance costs approximately 7 million due reorganizations 2009 ceiling test charges required conduct quarterly impairment tests capitalized costs full cost pools fourth quarter 2008 first quarter 2009 recorded total noncash ceiling test charges 27 billion 21 billion calculation charges based spot commodity prices end period calculating fourth quarter 2008 ceiling test charges capitalized costs exceeded ceiling limit 22 billion domestic full cost pool 05 billion brazilian full cost pool first quarter 2009 due low natural gas oil prices experienced downward pricerelated reserve revision approximately 400 bcfe primarily arklatex raton midcontinent areas recorded noncash ceiling test charges approximately 20 billion domestic full cost pool 28 million brazilian full cost pool fourth quarter 2009 primarily due proved reserve additions record ceiling test charges domestic full cost pool however recorded 30 million ceiling test charge brazilian full cost pool result lower commodity prices downward performancerelated reserve revision pescadaarabaiana fields result sec’s final rule modernization oil gas reporting effective december 31 2009 required use 12month average price calculated unweighted arithmetic average price first day month within 12month period prior end reporting period performing ceiling tests calculating ceiling test charges also required hold prices constant life reserves even though actual prices natural gas oil volatile change period information first day 12month average price used calculate ceiling test see supplemental natural gas oil operations 2009 2008 also recorded noncash ceiling test charges egyptian full cost pool 34 million 9 million charges primarily result dry hole costs unsuccessful wells drilled years impairment inventory assets 2009 recorded 16 million noncash charge reflect current market price expect receive upon sale certain casing tubular goods inventory materials supplies prior third quarter intended use capital programs based changes capital program decided would sell inventory use proceeds purchase inventory related current capital projects also recorded 9 million noncash charge result decision close bluebell processing plant 2010 equity earnings four star increased 63 million year ended december 31 2009 compared 2008 primarily due impairment carrying value investment 125 million recorded 2008 partially offset impact lower commodity prices 2009 year ended december 31 2008 compared year ended december 31 2007 ebit 2008 decreased 2357 million compared 2007 table shows significant variances financial results 2008 compared 2007 physical sales physical sales represent accrualbased commodity sales transactions customers 2008 revenues increased compared 2007 due primarily higher commodity prices year ended december 31 2008 also benefited increase production volumes domestic divisions compared 2007 primarily result successful drilling programs peoples acquisition third quarter 2007 gulf coast division production volumes decreased 2008 versus 2007 primarily due asset sales production shut result hurricanes ike gustav natural production declines realized unrealized gains financial derivatives year ended december 31 2008 recognized net gains 196 million compared net gains 184 million 2007 due natural gas oil prices 2008 relative commodity prices contained derivative contracts depreciation depletion amortization expense 2008 depletion rate increased compared period 2007 result peoples zapata county texas acquisitions 2007 higher finding development costs production costs production costs increased 2008 compared 2007 primarily due higher production taxes increased due higher natural gas oil revenues increase production taxes partially offset reduction lease operating expenses year ended december 31 2008 primarily result impact divested properties general administrative expenses general administrative expenses decreased 2008 compared periods 2007 primarily due reversal 20 million accrual result favorable ruling legal matter ceiling test charges fourth quarter 2008 recorded noncash full cost ceiling test charges 27 billion capitalized costs exceeded ceiling limit 22 billion domestic full cost pool 05 billion brazilian full cost pool calculation charges based december 31 2008 spot natural gas price 571 per mmbtu oil price 4460 per barrel required time calculating ceiling test charges required hold prices constant life reserves even though actual prices natural gas oil volatile change period prior fourth quarter 2008 included derivatives designated accounting hedges determination future net revenues purposes calculating ceiling tests fourth quarter 2008 removed hedging designation commoditybased derivative contracts related hedged natural gas oil production volumes estimate chosen dedesignate hedges ceiling test charges december 31 2008 would lower approximately 400 million equity earnings four star 2008 decreased compared 2007 due primarily 125 million impairment carrying value investment based decline fair value result lower forecasted commodity prices marketing segment marketing segment’s primary focus market exploration production segment’s natural gas oil production manage el paso’s overall price risk addition continue manage liquidate remaining legacy contracts primarily entered prior deterioration energy trading environment 2002 remaining contracts subject counterparty credit nonperformance risks remaining marktomarket contracts also subject interest rate exposure legacy power contracts primary exposure remaining marketing segment relates marktomarket power contracts extend april 2016 exposure relates volatility locational power prices within pennsylvanianew jerseymaryland pjm region legacy transportationrelated contracts impact accrualbased contracts based ability use remarket contracted pipeline capacity december 31 2009 contracts require us pay demand charges 47 million 2010 average 41 million 2011 2014 additionally fourth quarter 2009 entered agreement associated ruby pipeline project commences 2016 continues 2021 legacy natural gas contracts december 31 2009 long term gas supply contracts obligate us deliver natural gas specified power plants accounting contracts combination marktomarket accrualbased expected minimal future impact segment substantially offset fixed price exposure operating results overview overall operating results analysis significant contract type marketing segment three years ended december 31 follows 2009 results primarily driven 52 million marktomarket gain related adoption new accounting requirements derivative liabilities associated noncash collateral eg letters credit partially offset 27 million related impact el paso’s credit standing derivative liabilities 2008 2007 results significantly impacted marktomarket losses productionrelated natural gas crude contracts held managed years losses 46 million 100 million 2008 2007 due changes fair value pjm contracts additionally 2008 signed capacity purchase agreement executed reduce exposure installed capacity prices contributed losses recognized 2007 also recorded 19 million revenue related bankruptcy settlements additional items impacting 2007 results 23 million income sale investment 28 million 23 million revenues 5 million income related settlement outstanding california power price disputes power segment overview december 31 2009 remaining investment guarantees letters credit related projects segment totaled approximately 174 million consisted primarily equity investments notes accounts receivable follows years ended december 31 2009 2008 2007 power segment generated ebit loss 25 million ebit 1 million ebit loss 37 million 2009 ebit loss primarily relates loss sale porto velho notes receivable 2009 2007 ebit loss primarily due impairments 57 million porto velho 15 million manaus rio negro project offset 30 million ebit generated porto velho prior impairment 9 million manaus rio negro project beginning 2007 ceased recognizing earnings porto velho project based inability realize earnings expected sales price investment 2007 brazilian operations generated ebit 12 million 2008 transferred ownership manaus rio negro power plants brazil plants’ power purchaser longer plants still exposure relating outstanding brazilian reaisdenominated receivables due power purchaser also process trying resolve several outstanding claims related projects early 2009 completed sale investment porto velho power generation facility brazil partner project cash notes receivable second quarter 2009 sold notes including accrued interest third party financial institution 57 million recorded loss 22 million 2009 also sold investment argentinatochile pipeline partners approximately 32 million sale remaining international investments completed manaus rio negro receivables collected matters discussed item 8 financial statements supplementary data note 19 resolved changes regional political economic conditions could negatively impact anticipated proceeds may receive could result impairments remaining assets investments corporate expenses net corporate activities include general administrative functions well number miscellaneous businesses qualify operating segments material current year results following summary significant items impacting ebit corporate activities three years ended december 31 litigation environmental reserves year ended december 31 2009 recorded marktomarket gains 21 million associated indemnification conjunction sale legacy ammonia facility based fluctuations ammonia prices also recorded 16 million additional estimated environmental remediation costs related legacy nonoperating chemical plant 2008 recorded favorable adjustments related resolving certain legacy litigation matters including 65 million related case corporation indemnification dispute see item 8 financial statements supplementary data note 13 32 million related settlement certain class action matters partially offsetting 2008 settlements approximately 46 million marktomarket losses based significant increases ammonia prices first quarter 2008 changes ammonia prices continue impact contract could affect results future 2007 recorded gain approximately 77 million reversal liability related coastal corporation’s legacy crude oil marketing trading business number pending litigation matters reserves related historical business operations affect corporate results adverse rulings unfavorable outcomes settlements us related matters impacted may continue impact future results addition matters anticipate increase noncash pension costs approximately 40 million 2010 primarily result pension plan asset performance 2008 overall losses pension assets amortized future net benefit cost 2011 despite increased expense anticipate making contributions primary pension plan 2010 discussion primary pension plan related net benefit cost see item 8 financial statements supplementary data note 14 extinguishment debt 2007 incurred losses 291 million conjunction repurchasing refinancing 5 billion debt information debt see item 8 financial statements supplementary data note 12 interest debt expense interest debt expense years ended december 31 2009 2008 2007 10 billion 09 billion 10 billion 2009 interest debt expense increased compared prior year due primarily higher interest rates amortization discounts related debt issuances financing obligations net retirements 2008 interest debt expense decreased compared 2007 primarily due debt repurchases 2007 2008 net issuances see item 8 financial statements supplementary data note 12 discussion income taxes 2009 overall effective tax rate continuing operations differed statutory rate due primarily recording 88 million income tax benefit relating us tax loss liquidation certain foreign entities following 2009 sale remaining significant noncore international power projects entities liquidating value entities tax basis liquidation resulted tax loss 2008 overall effective tax rate continuing operations differed statutory rate due primarily brazilian ceiling test charge exploration production operations corresponding us brazilian tax benefit ii establishment valuation allowance deferred tax assets associated brazilian net operating losses based uncertainties ability realize assets 2007 overall effective tax rate continuing operations impacted primarily earnings unconsolidated affiliates anticipate receiving dividends qualify dividend received deduction discussion items affecting effective tax rates year tax matters see item 8 financial statements supplementary data note 5 discontinued operations 2007 income discontinued operations due gain sale anr related operations 648 million net income taxes 354 million discussed item 8 financial statements supplementary data note 2 commitments contingencies discussion commitments contingencies see item 8 financial statements supplementary data note 13 climate change energy legislation regulation various legislative regulatory measures relating climate change energy policies proposed enacted likely impact business climate change legislation regulation measures address climate change greenhouse gas ghg emissions various phases discussions implementation international federal regional state levels measures include kyoto protocol ratified international countries operations mexico brazil egypt 50 countries including us brazil submitted formal pledges cut limit emissions response united nations sponsored copenhagen accord reasonably likely federal legislation requiring ghg controls enacted within next years united states although uncertain legislation ultimately enacted belief capandtrade marketbased legislation sets price carbon emissions increase demand natural gas particularly power sector believe increased demand occur due substantially less carbon emissions associated use natural gas compared alternate fuel sources power generation including coal oilfired power generation however actual impact demand depend legislative provisions ultimately adopted including level emission caps allowances granted offset programs established cost emission credits incentives provided fossil fuels lower carbon technologies like nuclear carbon capture sequestration renewable energy sources also reasonably likely federal legislation enacted would increase cost environmental compliance requiring us install additional equipment reduce carbon emissions larger facilities well potentially purchase emission allowances based 2008 operational data reported california climate action registry operations united states emitted approximately 139 million tonnes carbon dioxide equivalent emissions 2008 believe approximately 107 124 million tonnes ghg emissions depending legislation interpreted would subject regulations climate change legislation passed us house representatives house june 2009 amounts would subject regulation believe approximately 45 million tonnes would subject capandtrade rules contained proposed legislation remainder would subject performance standards proposed house portion ghg emissions would subject capandtrade rules could require us purchase allowances offset credits portion ghg emissions would subject performance standards could require us install additional equipment initiate new work practice standards reduce emission levels many facilities costs purchasing emission allowances offset credits installing additional equipment changing work practices would likely material increases costs suppliers comply capandtrade rules performance standards electricity purchase operations could also material would likely increase costs operations although believe many costs recoverable sales price natural gas rates charged pipelines recovery mechanisms still uncertain time climate change bill also voted upon favorably senate committee energy public works committee november 2009 ordered reported committee final bill passed us senate likely see substantial changes cannot yet predict form may take timing legislation enacted implemented may impact operations ultimately enacted environmental protection agency epa finalized regulations monitor report ghg emissions annual basis epa also proposed new regulations regulate ghgs clean air act epa indicated could finalized early march 2010 effective date substantive requirements epa final rule subject interpretation possible legal challenges addition uncertain whether federal legislation might enacted either delays implementation climate change regulations epa adopts different statutory structure regulating ghgs provided pursuant clean air act therefore potential impact operations construction projects remains uncertain addition march 2009 epa proposed rule impacting emissions reciprocating internal combustion engines would require us install emission controls engines pipeline systems expected rule finalized august 2010 proposed engines subject regulations would compliance august 2013 based upon timeframe would expect would commence incurring expenditures late 2010 majority work expenditures incurred 2011 2012 regulations adopted proposed would expect incur approximately 60 million capital expenditures period 2010 2013 legislative regulatory efforts underway various states regions rules finalized may impose additional costs operations permitting facilities could include costs purchase offset credits emission allowances retrofit install equipment change existing work practice standards addition various lawsuits filed seeking force regulation ghg emissions well require specific companies reduce ghg emissions operations enactment additional regulations federal state governments well lawsuits could result delays negative impacts ability obtain permits regulatory approvals regard existing new facilities could impact costs operations well require us install new equipment control emissions facilities costs would likely material energy legislation conjunction climate change proposals various federal state legislative regulatory proposals would create additional incentives move less carbon intensive “footprint” proposals would establish renewable energy efficiency standards federal state level would require material increase renewable sources wind solar power generation next several decades also proposals increase development nuclear power commercialize carbon capture sequestration especially coal fired facilities proposals would establish incentives energy efficiency conservation although reasonably likely many proposals enacted next years cannot predict form laws regulations might enacted timing implementation precise impact operations demand natural gas however proposals enacted could negatively impact natural gas demand longer term liquidity capital resources continued focus expanding core pipeline exploration production businesses build liquidity fund growth primary sources cash flows generated operations amounts available us revolving credit facilities conditions warrant may also generate funds additional bank financings project financings capital market activities asset sales primary uses cash funding capital expenditure programs meeting operating needs repaying debt due repurchasing debt conditions warrant believe well positioned 2010 meet obligations based anticipated performance core businesses financing actions taken date planned 2010 additional steps announced november 2009 enhance liquidity available liquidity outlook 2010 december 31 2009 available liquidity approximately 18 billion approximately 05 billion cash 13 billion available credit facility exclusive approximately 04 billion combined cash credit facility capacity epb ruby 2009 took number actions generate additional liquidity address instability global financial markets including reducing 2009 capital program obtaining 50 percent partner ruby pipeline project described raising 21 billion net liquidity financings 2009 financings included issuance approximately 500 million el paso notes 250 million tgp notes ii completing two additional facilities provide combined 300 million letter credit capacity iii completing 300 million financings related elba island lng facility elba express pipeline project iv extending 300 million el paso exploration production company 364day revolving credit facility without additional collateral requirements maintain current borrowing base v raising 215 million conjunction contributing additional interests cig master limited partnership vi selling approximately 300 million noncore assets 2010 capital programs anticipate planned cash capital expenditures operations follows although 2010 pipeline capital requirements significant 2011 requirements decline significantly end 2011 backlog placed service capital program designed deliver pipeline expansion backlog keeping exploration production capital spend levels essentially consistent 2009 allowing continued reserve growth addition capital needs 2010 approximately 250 million debt excluding ruby debt approximately 217 million anticipate convert ruby preferred equity mature however primary revolving credit facility scheduled renewal late 2012 plan meet requirements variety measures 2010 include generating positive operating cash flows core operations ii raising approximately 15 billion third party financing ruby expected close first half 2010 expect borrow approximately 1 billion 2010 iii receiving approximately 300 million committed funding global infrastructure partners gip ruby project iv selling 300 million 500 million assets also consider additional opportunities mlp markets permit november 2009 announced additional actions 2010 provide incremental funding improve financial flexibility including reduction 150 million annual operating administrative expenses sale 300 million 500 million assets reduction quarterly dividend annual cash savings approximately 112 million part plan february 2010 entered agreement sell interest mexican pipeline compression assets 300 million expected close second quarter 2010 subject lender consent mexican regulatory approval believe actions planned 2010 provide sufficient liquidity meet operating financing capital needs 2010 however number factors could impact plans including ability access financial markets fund longterm capital needs financial markets restricted decline commodity prices announced actions sufficient events occur additional adjustments plan outlook may required could impact financial operating performance including reductions discretionary capital program reductions operating general administrative expenses obtaining secured financing arrangements seeking additional partners growth projects sale additional noncore assets ruby financing third quarter 2009 entered agreement several infrastructure funds managed gip whereby invest 700 million ruby pipeline holding company llc ruby three major tranches including series 7 percent loans totaling 405 million 217 million borrowed december 31 2009 converted preferred equity interest ruby upon satisfaction certain conditions ii 145 million contributed october 2009 convertible preferred equity interest ruby simultaneously exchanged convertible preferred equity interest cheyenne plains investment company “cheyenne plains” 15 percent rate return ruby pipeline project placed inservice among conditions iii additional 150 million convertible preferred equity made ruby conditions ferc approvals construction project obtained third party financing approximately 14 billion secured ruby december 2010 convertible preferred equity interest ruby earn 13 percent yield beginning final project completion gip right convert preferred equity common equity ruby time however preferred equity subject mandatory conversion common equity upon satisfaction certain conditions including ruby entering additional firm transportation agreements conditions closing satisfied waived time project completion gip would 50 percent equity interest ruby ownership cheyenne plains would transferred back us however gip preferred equity interests ruby cheyenne plains amounts borrowed gip’s loan commitment ruby 15 percent return outstanding amounts must repaid cash gip ferc approvals construction ruby pipeline project obtained december 2010 ii third party financing approximately 14 billion secured ruby december 2010 iii ruby pipeline project placed inservice within 16 months obtaining ferc approvals additionally financings completed gip option convert preferred interest cheyenne plains 50 percent common interest cheyenne plains obligation repay amounts secured equity interests ruby cheyenne plains approximately 50 million common units mlp overview 2009 cash flow activities 2009 generated positive operating cash flow approximately 21 billion primarily pipeline exploration production operations also generated approximately 03 billion sale certain noncore power exploration production assets 16 billion debt issuances 2009 including consolidated project financings utilized amounts fund capital programs refinance 2009 debt maturities 10 billion pay common preferred dividends among items year ended december 31 2009 2008 cash flows continuing operations summarized follows offbalance sheet arrangements enter variety financing arrangements contractual obligations referred offbalance sheet arrangements include guarantees letters credit interests variable interest entities guarantees indemnifications involved joint ventures ownership arrangements sometimes require financial performance guarantees financial guarantee obligated make payments guaranteed party fails make payments violates terms financial arrangement performance guarantee provide assurance guaranteed party execute terms contract required perform behalf also periodically provide indemnification arrangements related assets businesses sold arrangements include limited indemnifications income taxes resolution existing disputes environmental matters potential exposure guarantee indemnification agreements range specified unlimited dollar amount depending nature claim particular transaction many agreements may specify maximum potential exposure specified duration indemnification obligation circumstances amount duration unlimited arrangements specified dollar amount maximum stated value approximately 08 billion primarily relates indemnification arrangements associated sale anr macae power facility brazil legacy assets amounts exclude guarantees issued related letters credit discussed item 8 financial statements supplementary data note 12 included maximum stated value certain indemnification agreements expired however claims made prior expiration related claim periods unable estimate maximum exposure guarantee indemnification agreements provide limits amount future payments due uncertainty exposures december 31 2009 recorded obligations 52 million related guarantee indemnification arrangements liability consists primarily indemnification one subsidiaries provided related sale ammonia facility reflected financial statements fair value provided partial parental guarantee subsidiary’s obligations indemnification letters credit enter letters credit ordinary course operations well periodically conjunction sales assets businesses december 31 2009 outstanding letters credit approximately 13 billion including 07 billion letters credit securing recorded obligations related price risk management activities additional information counterparty credit nonperformance risk see item 8 financial statements supplementary data note 7 depending changes commodity prices interest rates could required post additional margin may recover margin earlier anticipated 10 percent change natural gas power prices would significant impact margin requirements derivative contracts december 31 2009 interests variable interest entities interests several variable interest entities primarily ruby variable interest entity legal entity whose equity owners sufficient equity risk controlling financial interest entity required consolidate entities allocated majority variable interest entity’s losses return including fees paid entity december 31 2009 significant variable interest entities consolidate additional information regarding interest ruby see item 8 financial statements supplementary data note 18 variable interest entities qualifying special purpose entities contractual obligations party various contractual obligations include offbalance sheet arrangements described portion obligations reflected financial statements longterm debt liabilities commoditybased derivative contracts accrued liabilities obligations demand charges transportation storage commitments operating leases capital commitments reflected balance sheet following table discussion summarizes contractual cash obligations december 31 2009 periods presented longterm financing obligations principal interest debt obligations included table represent stated maturities unless instrument otherwise puttable us prior stated maturity date interest payments shown stated maturity date related debt based contractual interest rate fixed rate debt ii current market interest rates contractual credit spread variable rate debt discussion debt obligations see item 8 financial statements supplementary data note 12 liabilities commoditybased derivative contracts amounts include fair value price risk management liabilities fair value commoditybased price risk management assets 333 million december 31 2009 reflected amounts also excluded margin deposits held associated contracts amounts discussion commoditybased derivative contracts see discussion commoditybased derivative contracts contractual liabilities included amount contractual environmental obligations included current noncurrent liabilities balance sheet excluded amounts expected contributions pension postretirement benefit plans expected contributions contractually required information expected contributions pension post retirement benefit plans see item 8 financial statements supplementary data note 14 also excluded amounts liabilities unrecognized tax benefits 260 million december 31 2009 since cannot reasonably estimate time frame amounts may resolved operating leases discussion obligations see item 8 financial statements supplementary data note 13 contractual commitments purchase obligations contractual commitments purchase obligations defined legally enforceable agreements purchase goods services fixed minimum quantities fixed minimum variable price provisions detail approximate timing underlying obligations included following • transportation storage commitments included amounts commitments demand charges firm access natural gas transportation storage capacity • commitments included amounts commitments purchasing pipe related assets pipeline operations commitments drilling seismic activities exploration production operations various maintenance engineering procurement construction contracts well service license agreements used operations also included longterm commitments us related right way payments discussed item 8 financial statements supplementary data note 13 excluded asset retirement obligations reserves litigation environmental remediation selfinsurance claims disclosed liabilities contractually fixed timing amount commoditybased derivative contracts use derivative financial instruments exploration production marketing segments manage price risk commodities commoditybased derivative contracts currently designated accounting hedges include options swaps natural gas oil power purchase supply contracts traded active exchanges following table details fair value commoditybased derivative contracts year maturity december 31 2009 following reconciliation commoditybased derivatives years ended december 31 2009 2008 fair value contract settlements fair value contract settlements period represents estimated amounts derivative contracts settled physical delivery commodity claim cash accounts receivable payable also includes physical financial contract terminations due counterparty bankruptcies sale settlement derivative contracts early termination sale entities contracts including amounts received sale option contracts changes fair value contracts change fair value contracts year represents change value contracts beginning period date origination acquisition settlement early termination settled terminated end period reclassifications dedesignated hedges fourth quarter 2008 removed hedging designation commoditybased derivative contracts related hedged natural gas oil production volumes critical accounting estimates significant accounting policies described note 1 consolidated financial statements included item 8 annual report form 10k preparation financial statements conformity generally accepted accounting principles requires management select appropriate accounting estimates make estimates assumptions affect reported amount assets liabilities revenue expenses disclosures contingent assets liabilities consider critical accounting estimates require difficult complex subjective judgment necessary accounting inherently uncertain matters could significantly influence financial results based changes judgments changes facts circumstances may result revised estimates actual results may differ materially estimates discussed development selection following critical accounting estimates related disclosures audit committee board directors accounting natural gas oil producing activities estimates proved reserves reflect quantities natural gas oil ngl geological engineering data demonstrate reasonable certainty recoverable future years known reservoirs existing economic conditions process estimating natural gas oil reserves complex requiring significant judgment evaluation available geological geophysical engineering economic data proved reserves estimated property level compiled reporting purposes centralized group experienced reservoir engineers work closely operating groups engineers interact engineering geoscience personnel operating areas accounting marketing personnel obtain necessary data projecting future production costs net revenues ultimate recoverable reserves reviewed internally senior management quarterly presented board directors summary form annual basis additionally annual basis property reviewed detail centralized operating divisional engineers ensure forecasts operating expenses netback prices production trends development timing reasonable proved reserves also reviewed internal committees processes controls used estimating proved reserves reviewed internal auditors addition thirdparty reservoir engineering firm appointed reports audit committee board directors conducts audit estimates significant portion proved reserves particular ryder scott company lp conducted audit estimates proved reserves december 31 2009 december 31 2009 total consolidated proved reserves 33 percent undeveloped 31 percent including four star 14 percent developed nonproducing data given field may change substantially time result numerous factors including additional development activity evolving production history continual reassessment viability production changing economic conditions result material revisions existing reserve estimates occur time addition subjective decisions variances available data various fields increase likelihood significant changes estimates proved natural gas oil reserves primarily impact property plant equipment amounts balance sheets depreciation depletion amortization amounts ceiling test charges income statements among items use full cost method account natural gas oil producing activities accounting method capitalize substantially costs incurred connection acquisition exploration development natural gas oil reserves including salaries benefits internal costs directly related finding activities asset retirement costs capitalized interest capitalized costs maintained full cost pools geographic area regardless whether reserves actually discovered record depletion expense capitalized amounts plus estimated finding development costs life proved reserves based unit production method factors held constant 10 percent increase estimated proved reserves would decrease unit production depletion rate 9 percent 10 percent decrease estimated proved reserves would increase unit depletion rate 11 percent information regarding price sensitivities related estimated proved reserves see part item 1 business natural gas oil properties natural gas oil properties include unproved property costs excluded costs depleted unproved property costs include nonproducing leasehold geological geophysical costs associated unevaluated leasehold drilling interests exploration drilling costs investments unproved properties major development projects direct interest exclude costs countrybycountry basis proved reserves found determined costs impaired costs excluded reviewed least quarterly determine exclusion fullcost pool continues appropriate costs determined impaired amount impairment transferred full cost pool reserve base exists expensed reserve base yet created impairments transferred full cost pool increase depletion rate country full cost accounting method natural gas oil properties required conduct quarterly impairment tests capitalized costs full cost pools impairment test referred ceiling test total capitalized costs net related deferred income taxes limited ceiling based present value future net revenues proved reserves discounted 10 percent plus cost unproved natural gas oil properties amortized less related income tax effects december 31 2009 adopted provisions sec’s final rule modernization oil gas reporting among things final rule revised definition proved reserves required us use first day 12month average price calculating ceiling test estimating proved reserves rather period end spot price required prior periods discounted future net cash flows greater equal total capitalized costs required writedown capitalized costs level discounted future net cash flows costbased regulation account regulated operations accordance current financial accounting standard board fasb accounting standards rateregulated operations economic effects regulation result regulated company recording assets costs expected approved recovery customers recording liabilities amounts expected returned customers ratesetting process period different period amounts would recorded unregulated enterprise accordingly record assets liabilities result regulated ratemaking process would recorded gaap nonregulated entities management regularly assesses whether regulatory assets probable future recovery regulatory liabilities probable refunded customers considering factors applicable regulatory changes recent rate orders applicable regulated entities based continual assessment management believes existing regulatory assets probable recovery periodically evaluate applicability accounting standards related regulated operations consider factors regulatory changes impact competition costbased regulation ends competition increases may reduce certain asset balances reflect market basis lower cost writeoff associated regulatory assets accounting legal environmental reserves guarantees indemnifications accrue legal environmental reserves assessments indicate probable liability incurred asset recovered amount reasonably estimated estimates liabilities based evaluation potential outcomes currently available facts case environmental reserves existing technology presently enacted laws regulations taking consideration likely effects societal economic factors estimates associated onsite offsite groundwater technical studies legal costs actual results may differ estimates often revised future either negatively positively depending upon actual outcomes changes expectations based facts surrounding matter december 31 2009 accrued approximately 67 million legal matters reduced 1 million related insurance receivables 189 million environmental matters reduced 24 million amounts paid directly government sponsored programs settlement arrangements environmental estimates range approximately 189 million approximately 381 million amounts accrued represent combination two estimation methodologies first likely outcome reasonably estimated cost accrued 10 million second likely outcome cannot estimated range costs established 179 million 371 million lower end expected range accrued also guarantee indemnification agreements related various joint ventures ownership arrangements require us assess potential exposure range specified amount unlimited dollar amount depending nature claim particular transaction arrangements specified dollar amount maximum stated value approximately 08 billion december 31 2009 recorded obligations 52 million related guarantee indemnification arrangements unable estimate maximum exposure guarantee indemnification agreements provide limits amount future payments agreement due uncertainty exposures information see balance sheet arrangements accounting pension postretirement benefits reflect asset liability pension postretirement benefit plans based funded status december 31 2009 pension plans funded 154 million postretirement benefit plans funded 399 million pension postretirement benefit obligations net benefit costs primarily based actuarial calculations use various assumptions performing calculations including related return expect earn plan assets rate expect compensation employees increase plan term estimated cost health care benefits provided plans factors significant assumption utilize discount rates used calculating benefit obligations select discount rates matching timing amount expected future benefit payments pension postretirement benefit obligations average yields various highquality bonds corresponding maturities actual results may differ assumptions included calculations result estimates associated pension postretirement benefits often revised future income statement impact changes assumptions related benefit obligations along changes plans items deferred amortized income either period expected future service active participants lives inactive plan participants record deferred amounts accumulated comprehensive income nonregulated operations either regulatory asset liability regulated operations december 31 2009 deferred net losses approximately 682 million net income taxes accumulated comprehensive income following table shows impact one percent change primary assumptions used actuarial calculations associated pension postretirement benefits year ended december 31 2009 millions 1 actual return plan assets one percent lower expected return plan assets expected cash contributions pension postretirement benefit plans would change significantly estimates net benefit expense income partially based expected return pension plan assets use marketrelated value plan assets determine expected return pension plan assets determining marketrelated value plan assets differences expected actual asset returns deferred three years considered inclusion net benefit expense income used fair value plan assets instead marketrelated value plan assets determining expected return pension plan assets net benefit expense would 85 million higher year ended december 31 2009 price risk management activities record derivative instruments used price risk management activities fair values estimate fair value derivative instruments using exchange prices thirdparty pricing data valuation techniques incorporate specific contractual terms statistical simulation analysis present value concepts one primary assumptions used estimate fair value derivative instruments pricing assumptions based upon price curves derived actual prices observed market pricing information supplied thirdparty valuation specialist independent pricing sources models rely forward pricing information extent rely pricing information received third parties developing assumptions based part whether information considers availability observable data marketplace example relatively illiquid markets pjm forward power market may make adjustments pricing information receive third parties based evaluation whether third party market participants would use pricing assumptions consistent sources table presents hypothetical sensitivity commoditybased price risk management activities changes fair values arising immediate selected potential changes natural gas oil power prices december 31 2009 another significant assumption discount rates use determining fair value derivative instruments table presents hypothetical sensitivity commoditybased price risk management activities changes fair values arising changes discount rates used determine fair value derivatives december 31 2009 significant assumptions use determining fair value derivative instruments related anticipated market liquidity credit nonperformance risk counterparties adjust fair value derivative assets risk nonperformance counterparties considering collateral posted derivative changes counterparties’ creditworthiness measured part based changes bond yields changes actively traded credit default swap prices available information credit standing adjust fair value derivative liabilities creditworthiness utilizing similar inputs considering cash collateral posted counterparties table presents hypothetical sensitivity commoditybased price risk management activities changes fair values arising potential changes credit risk december 31 2009 deferred taxes uncertain income tax positions record deferred income tax assets liabilities reflecting tax consequences deferred future periods based differences financial statement carrying value assets liabilities tax basis assets liabilities additionally deferred tax assets liabilities reflect assessment tax positions taken resulting tax basis reflect conclusions positions likely sustained audited taxing authorities significant judgments tax related matters include limited items noted matters involve exercise significant judgment could change materially impact financial condition results operations discussion items income tax matters see item 8 financial statements supplementary data note 5 valuation allowance realization deferred tax assets depends recognition sufficient future taxable income specific tax jurisdictions periods temporary differences deductible valuation allowances established necessary reduce deferred income tax assets amounts believe likely recovered evaluating valuation allowance consider reversal existing temporary differences existence taxable income prior carryback years tax planning strategies future taxable income taxable jurisdictions latter two involve exercise significant judgment changes valuation allowance could materially impact results operations uncertain tax positions liabilities unrecognized tax benefits related uncertain tax positions connected ongoing examinations open tax years changes assessment liabilities may require us increase liability record additional tax expense reverse liability recognize tax benefit would positively negatively impact effective tax rate undistributed earnings foreign investees certain unconsolidated affiliates record deferred tax liabilities undistributed earnings foreign investments anticipate earnings repatriated plan repatriate foreign undistributed earnings provision made us taxes foreign withholding taxes changes repatriation assumptions including repatriation proceeds sales investments could require us record additional deferred taxes additionally believe certain unconsolidated affiliates’ undistributed earnings ultimately distributed us dividends would eligible dividends received deduction joint venture partners intent ability recover cumulative undistributed earnings time dividends structured sale would result additional deferred tax liabilities asset investment impairments accounting rules asset investment impairments require us continually monitor businesses business environment performance investments determine event occurred indicates longlived asset investment may impaired event occurs determination involves judgment estimate fair value asset considers number factors including potential value would receive sold asset projected cash flows asset based current anticipated future market conditions discount rates assessment project level cash flows requires significant judgment make projections assumptions many years future pricing demand competition operating costs legal regulatory issues factors often outside control due imprecise nature projections assumptions actual results often differ estimates utilize cash flow projections assess ability recover carrying value assets investments based either longlived assets’ ability generate future cash flows undiscounted basis ii fair value investments unconsolidated affiliates whether decline fair value carrying amount considered temporary impairment indicated record impairment charge excess carrying value asset fair value year ended december 31 2009 recorded impairments 21 million related longlived assets recorded impairments longlived assets 41 million 20 million impairments losses investments advances unconsolidated affiliates 127 million 75 million years ended december 31 2008 2007 future changes economic business environment impact assessments potential impairments new accounting pronouncements issued yet adopted see item 8 financial statements supplementary data note 1 new accounting pronouncements issued yet adopted incorporated herein reference item 7aitem 7 management’s discussion analysis financial condition results operations overview management’s discussion analysis mda read conjunction consolidated financial statements accompanying footnotes mda includes forwardlooking statements subject risks uncertainties may result actual results differing statements make risks uncertainties discussed item 1a risk factors listed general outline mda business includes summary business purpose description factors influencing profitability summary 2010 performance outlook 2011 results operations includes yearoveryear analysis results business segments corporate activities income statement items including trends may impact business future liquidity capital resources includes general discussion sources uses cash available liquidity outlook 2011 overview cash flow activity 2010 additional factors could impact liquidity balance sheet arrangements contractual obligations includes discussion balance sheet arrangements including guarantees letters credit ii contractual obligations critical accounting estimates includes discussion accounting estimates involve use significant assumptions andor judgments preparation financial statements business provide natural gas related energy products safe efficient dependable manner interests north america’s largest interstate natural gas pipeline systems provide stable base earnings cash flow backlog committed expansion projects also large independent natural gas oil producer focused generating competitive financial returns disciplined capital allocation portfolio management cost control marketing selling natural gas oil production optimal prices managing associated price risks also emerging midstream business factors influencing profitability pipeline operations rateregulated accordingly generate profit based ability earn return excess costs rates charge customers exploration production operations generate profits dependent prices natural gas oil costs explore develop produce natural gas oil volumes able produce among factors longterm profitability operating segments primarily influenced following factors pipelines • executing successfully remaining backlog committed expansion projects developing new growth projects market supply areas • contracting recontracting pipeline capacity customers • maintaining obtaining approval ferc acceptable rates terms service expansion projects • improving operating efficiency exploration production • growing natural gas oil proved reserve base production volumes successful lowrisk drilling programs • finding producing natural gas oil reasonable cost • managing price risks optimize realized prices natural gas oil production addition factors future profitability affected impacts volatility financial commodity markets debt level related interest costs successful resolution historical contingencies legacy activities summary 2010 performance 2010 generated significant earnings pipeline exploration production businesses continued focus delivering remaining backlog pipeline expansion projects achieving operational success exploration production business 2010 pipeline business placed approximately 1 billion pipeline expansion projects service time total approximately 100 million budget also continued advance ruby project largest pipeline expansion project currently expect go service july 2011 updated total cost approximately 355 billion exploration production business continued executing strategy increased production volumes lower per unit cash operating costs expanded 2011 2012 hedging program designed support balance sheet cash flows commenced shifting capital program 2010 provide us exposure oil opportunities particularly altamont eagle ford wolfcamp areas believe stability pipeline earnings coupled hedging program exploration production business continue protect earnings base cash flows operations following table provides highlights core businesses financing activities area operations significant highlights pipelines completed 15 billion project financing facility ruby pipeline expansion project received final approval ferc began construction project progressed remaining backlog expansion projects completing five expansion projects time budget including phase slng elba expansion iii elba express pipeline expansion cig raton 2010 expansion wic system expansion phase sng south system iii project received 23 billion cash conjunction contributing ownership interests slng elba express sng mlp funded issuance mlp debt unit issuances sold interests certain mexican pipeline compression assets approximately 03 billion filed new rate cases ferc epng tgp systems exploration production achieved overall domestic drilling success rate 98 percent focused domestic capital program core programs including haynesville shale northwest louisiana east texas eagle ford shale south texas altamont fractured tight sands utah late 2010 also acquired 123000 net acres wolfcamp shale permian basin texas managed commodity price risk derivative contracts 2010 2011 2012 natural gas production increased oil liquids based revenues 2010 23 percent total revenues 8 percent increase 2009 also entered joint venture emerging midstream business sold 50 percent interest altamont gathering processing assets 125 million cash venture partner expect invest approximately 500 million future midstream projects current level earnings midstream business significant number projects evaluating believe movement unconventional supply basins present future opportunities business outlook 2011 expect pipeline operations continue provide strong base earnings operating cash flow approximately 80 percent pipeline revenues collected form demand reservation charges dependent upon commodity prices throughput levels coupled diversity pipeline systems helps mitigate risk changes throughput ongoing shifts supply demand 2010 experienced lower demand firm transportation commitments epng system long haul transportation replaced short haul transportation tgp system additionally result shift flow patterns tgp system experienced lower realized prices volumes gas used operations pipeline results also impacted rate cases currently two pipelines outstanding rate cases pending ferc certain pipelines projected upcoming rate actions anticipated effective dates 2011 2014 2011 pipeline capital expenditure program expected approximately 17 billion including 13 billion remaining backlog growth projects currently plan place five projects service end 2011 exploration production business also expect generate significant earnings operating cash flow planned average daily production 2011 expected range 790 mmcfed 840 mmcfed including approximately 60 mmcfed ownership interest production four star expect trend low natural gas prices continue expanded financial derivative contracts place 2011 providing 595 average floors approximately 75 percent estimated domestic natural gas production 86009200 per barrel collars approximately 85 percent estimated oil production also expanded 2012 natural gas oil hedge program oil natural gas production hedge programs help protect cash flows years addition focused execution cost management ensure favorable economics programs current low gas price environment exploration production business expect spend approximately 13 billion capital expenditures 2011 9095 percent focused domestically haynesville altamont eagle ford wolfcamp areas capital focus provides us greater exposure oil natural gas liquids opportunities considering securing joint venture partner eagle ford oil acreage accelerate development core area deliver higher returns invested capital emerging midstream business continue seek opportunities focus synergies pipeline andor exploration production businesses funding projects manner consistent longterm goal improving balance sheet including evaluation partnership opportunities projects december 31 2010 approximately 24 billion available liquidity exclusive cash credit facility capacity epb ruby expect available liquidity operating cash flows 2011 sufficient fund estimated 32 billion 2011 capital program 2011 also debt maturities approximately 500 million pay mature additionally end 2012 required renew three primary revolving credit facilities result 2010 actions current available liquidity hedging program place natural gas oil production planned future actions including continuing mlp drop strategy market conditions permit believe well positioned 2011 meet obligations well continue efforts strengthen balance sheet continue assess take actions prudent meet longterm objectives capital requirements well address changes financial commodity markets businesses discussion see liquidity capital resources results operations overview two core operating business segments pipelines exploration production also marketing segment markets natural gas oil production manages legacy trading contracts segments managed separately provide variety energy products services require different technology marketing strategies prior 2010 also power segment combined corporate activities periods presented corporate activities include general administrative functions miscellaneous businesses including newly formed midstream business management uses earnings interest expense income taxes ebit measure assess operating results effectiveness business segments consist consolidated businesses investments unconsolidated affiliates believe ebit useful investors allows evaluate effectively operating performance using performance measure analyzed internally management investors may evaluate operating results without regard financing methods capital structure define ebit net income loss adjusted items interest debt expense ii income taxes iii net income attributable noncontrolling interests ebit may comparable measures used companies additionally ebit considered conjunction net income loss income loss income taxes performance measures operating income operating cash flows reconciliation ebit segment consolidated net income loss three years ended december 31 discussions follow provide additional analysis year results business segments corporate activities income statement items pipelines segment overview pipelines segment operates united states consists interstate natural gas transmission storage lng terminalling related services face varying degrees competition segment existing proposed pipelines proposed lng facilities well alternative energy sources used generate electricity hydroelectric power nuclear energy wind solar coal fuel oil revenues transportation storage lng terminalling related services consist two types percent 2010 type description revenues reservation revenues customers referred firm customers reserve capacity pipeline systems storage facilities lng terminalling facilities firm customers obligated pay monthly reservation demand charge regardless amount natural gas transport store term contracts usage revenues firm customers interruptible customers without reserved capacity pay usage charges provide fuel inkind based volume gas actually transported stored injected withdrawn also earn revenues processing sale natural gas liquids miscellaneous sources ferc regulates rates charge customers rates generally function cost providing services customers including reasonable return invested capital regulated nature high percentage revenues attributable reservation charges revenues historically relatively stable however financial results subject volatility due factors changes natural gas prices changes supply demand changes gas flows regulatory actions competition weather declines creditworthiness customers also experience earnings volatility one pipelines amount natural gas used operations differs amounts receive purpose historically much business conducted longterm contracts customers however many customers shifted traditional dependence longterm contracts portfolio approach balances shortterm opportunities longterm commitments shift increase volatility revenues due changes market conditions competition driven state utility deregulation local distribution company mergers new supply sources volatility natural gas prices demand shortterm capacity new power plant markets continue manage process renewing expiring contracts limit risk significant impacts revenues ability extend existing customer contracts remarket expiring contracted capacity dependent competitive alternatives regulatory environment federal state local levels market supply demand factors relevant dates contracts extended expire duration new renegotiated contracts affected current prices competitive conditions judgments concerning future market trends volatility although attempt recontract remarket capacity maximum rates allowed tariffs frequently enter firm transportation contracts amounts less maximum rates remain competitive extent amounts less maximum rates varies pipeline systems existing contracts mature various times varying amounts throughput capacity weighted average remaining contract term active contracts approximately six years december 31 2010 contract expiration portfolio associated revenue expirations firm transportation contracts wholly majority owned systems december 31 2010 including terms beginning 2010 later summary operational financial performance ebit increased approximately 11 percent comparing year ended december 31 2010 2009 compared 2008 2010 2009 ebit benefited expansion projects placed service increase allowance funds used construction related pipeline expansion projects yet service ruby project however periods net income attributable noncontrolling interests also increased result contributing assets epb coupled decline revenues epng tgp systems 2011 plan spend 17 billion capital pipeline business including 13 billion remaining backlog expansion projects significant projects listed grouped anticipated inservice dates listed additional information related certain significant backlog projects • ruby pipeline project ruby pipeline project consists approximately 680 miles 42” pipeline multiple compressor stations total horsepower approximately 157000 11 bcfd contractually committed firm basis customers 10 15 years total design capacity 15 bcfd 2010 received blm rightofway grant project final approval ferc began construction pipeline several groups filed appeals us court appeals certain approvals actions ferc blm us fish wildlife service related project although currently able continue construction pipeline pending federal court appeals review petitions currently unable predict action court take response appeals subsequent filings may made one groups construction ruby pipeline project continues advance approximately 85 percent pipe welded order avoid interference sage grouse mating season certain areas 40mile portion route nevada construction suspended area march 1 may 15 2011 updated cost estimate expect project completed cost approximately 355 billion placed service july 2011 although made substantial progress constructing pipeline ability complete project date within estimated costs continue depend factors outside control including delays obtaining additional regulatory clearances adverse court determinations regard existing regulatory clearances adverse weather conditions ability complete construction activities certain work periods provided regulatory authorizations • tgp 300 line project firm transportation capacity resulting project northeast us market area fully subscribed one shipper based executed precedent agreement 2010 ferc issued favorable environmental assessment tgp received certificate authorization ferc construct pipeline compression facilities june 2010 commenced construction compression facilities related project construction remaining facilities occur 2011 • tgp northeast upgrade project 2010 tgp entered precedent agreements two shippers provide 636 mmcfd additional firm transportation service receipt points marcellus shale basin interconnect new jersey firm transportation capacity fully subscribed two shippers order accommodate additional service pursue project includes approximately 40 miles 30 inch pipeline looping approximately 22310 horsepower additional compression successful execution committed pipeline backlog continue require effective project management attempt mitigate market risk associated expansion projects subscribing substantial portion capacity longterm contracts investmentgrade customers purchasing committing purchase steel fixed prices well contracting significant portion construction costs operating results 1 volumes exclude intrasegment activities 2 represents proportional share unconsolidated affiliates discussion factors impacting ebit 2010 compared 2009 compared 2008 also provided outlook events could impact ebit future periods 1 consists individually insignificant items several pipeline systems expansions 2010 2009 benefited increased reservation revenues due expansion projects placed service projects included carthage expansion totem gas storage facility concord lateral expansion wic system expansion phase slng elba expansion iii elba express pipeline expansion cig raton 2010 expansion capitalize carrying cost afudc equity funds related construction longlived assets years ended december 31 2010 2009 benefited increase income approximately 149 million 49 million associated equity portion afudc expansion projects increase primarily due ruby pipeline project 2010 slng elba expansion iii elba express pipeline expansion projects 2009 subsequent placing expansion projects service level earnings depend level contracted customer capacity ability market unsubscribed firm capacity currently approximately 11 bcfd ruby pipeline project subscribed expect additional firm capacity subscriptions near term placed service ruby project consolidated financial results currently fund reflect 100 percent capital cost project including cost overruns results reflect higher afudc capitalized due project delays shortly completion project subject meeting certain conditions anticipate reflecting ruby financial statements equity investment 50 percent deconsolidated required evaluate investment ruby impairment based increased costs delays project completion impact net book value investment depending fair value time evaluation may required writedown portion investment ruby additionally reflect equity earnings ruby ebit impact interest expense taxes preferred interests ebit contribution ruby decline pipeline placed service reservation usage revenues reservation usage revenues variance comparing three year period ended december 31 2010 primarily relates changes epng tgp sng pipeline systems discussed table millions discussion follows 1 increases primarily due higher tariff rates effective september 1 2009 due sng’s rate case settlement 2 consists individually insignificant items pipeline systems 2009 epng experienced increased contracted capacity primary delivery points california resulted higher reservation revenues approximately 15 million compared 2008 however epng’s throughput volumes decreased 2009 2010 due lower natural gas electric generation demand resulting weak macroeconomic conditions southwestern us increased competition california arizona market areas including increased activity lng facility reduced basis differentials unfavorably impacted ebit 4 million 76 million compared prior periods tgp system comparing 2009 2008 overall ebit unfavorably impacted 20 million decrease activity various interruptible services lower demand increased competition southeast area milder weather partially offset executed transportation capacity contracts shippers primarily marcellus shale basin northeast market area increased reservation revenues approximately 8 million compared 2008 throughput volumes tgp system increased 2010 compared 2009 however reservation usage revenues lower approximately 10 million primarily longhaul transports tgp system decreased due shift receipts gulf coast region rockies express pipeline interconnect ohio marcellus shale basin shorthaul transportation subject lower rates believe marcellus expansion projects tgp 300 line project tgp northeast upgrade project tgp northeast supply diversification project expand presence marcellus new york new england markets throughput affect level revenues commodity charges items changes gas flows tgp epng systems indication risks may face seeking recontract renew existing firm transportation contracts continuing negative economic impacts demand well adverse shifting sources supply could negatively impact basis differentials ability renew firm transportation contracts expiring systems ability renew contracts current rates although risk exists pipelines significant epng system may required discount certain transportation rates order renew certain firm transportation contracts conditions continue determine significant change revenues costs billing determinants pipeline systems option file rates cases ferc certain pipelines provide opportunity recover prudently incurred costs 2010 epng tgp filed rate cases ferc although rate cases intended address significant factors leading loss revenues increased costs eliminate ongoing business risks including competition shifts throughput gas used operations revaluations year ended december 31 2010 compared 2009 ebit unfavorably impacted 69 million due lower realized prices lower volumes gas used operations result shift flow patterns primarily tgp system partially offset 15 million lower electric compression usage higher realized prices operational sales lower imbalance revaluations contributed favorably ebit approximately 16 million 2009 compared 2008 addition lower electric compression usage increased ebit 13 million year ended december 31 2009 compared 2008 future earnings may impacted positively negatively depending changes throughput well fluctuations natural gas prices continue explore options minimize price volatility associated operational pipeline activities result tgp rate case filed ferc proposes increase base tariff rates effective june 1 2011 percentage revenues derived reservation charges may increase therefore may reduce impacts ebit due excess fuel recoveries bankruptcy proceeds 2008 revenue increased 39 million related calpine corporation’s calpine’s rejection transportation contracts us primarily associated distributions received calpine’s approved plan reorganization 2008 recorded income approximately 10 million net amounts potentially owed certain customers related amounts recovered enron bankruptcy settlement operating general administrative expenses year ended december 31 2010 operating general administrative expenses lower 2009 primarily due severance costs approximately 14 million recorded 2009 additionally comparing year ended december 31 2009 2008 operating general administrative expenses favorably impacted 18 million decreased field repair maintenance expense several pipeline systems asset write downs 2010 incurred 21 million noncash asset write based ferc order related sale natural buttes compressor station gas processing plant 2009 recorded gain 8 million related sale assets recorded impairments approximately 10 million 4 million 2010 2009 primarily related decision continue storage project due market conditions 2008 recorded impairments 41 million including impairment related essexmiddlesex lateral project due prolonged permitting process impairment epng arizona gas storage projects longer developing due declining real estate values tgp entered agreement effective date october 2010 sell certain offshore pipeline assets related facilities tgp filed abandonment application ferc related sale contingent upon receiving ferc approval abandonment application including ability recover future rates difference regulatory net book value purchase price well designation certain facilities nonjurisdictional approved tgp expects complete sale assets mid2012 may incur loss sale financial accounting purposes however outcome ferc’s approval application currently undeterminable assets considered held sale mexican assets 2010 recorded gain approximately 80 million sale interests certain mexican pipeline compression assets net income attributable noncontrolling interests net income attributable noncontrolling interests increased 2010 2009 due issuance additional public common units contribution additional assets mlp 2010 mlp issued 465 million additional public common units also 2010 contributed additional 35 percent interest sng 100 percent interest slng elba express mlp december 31 2010 ownership interest mlp 51 percent including two percent general partner interest net income attributable noncontrolling interests also includes preferred returns gip’s interests cheyenne plains ruby year ended december 31 2010 recorded 49 million associated gip’s preferred interests cheyenne plains ruby discussion preferred stock subsidiaries see item 8 financial statements supplementary data note 14 discussion items could impact ebit future periods pipeline systems periodically file changes rates subject approval ferc changes rates tariff provisions resulting regulatory proceedings potential positively negatively impact profitability currently certain pipelines expected continue operating existing rates pipelines projected upcoming rate actions anticipated effective dates 2011 2014 discussed sng rate case january 2010 ferc approved sng’s settlement sng increased base tariff rates effective september 1 2009 ii implemented volume tracker gas used operations iii agreed file next general rate case effective august 31 2012 later september 1 2013 iv extended vast majority sng’s firm transportation contracts august 31 2013 epng rate case april 2010 ferc approved uncontested partial offer settlement increased epng’s base tariff rates effective january 1 2009 part settlement epng made refunds customers 2010 settlement resolved four issues proceeding january 2011 presiding administrative law judge issued decision part found epng four issues epng appeal decisions ferc may also seek review ferc’s decisions us court appeals although final outcome currently determinable believe accruals established matter adequate september 2010 epng filed new rate case ferc proposing increase base tariff rates permitted settlement previous rate case new base tariff rates would increase revenue approximately 107 million annually previously effective tariff rates october 2010 ferc issued order accepting suspending effective date proposed rates april 1 2011 subject refund outcome hearing proceedings time outcome matter currently determinable tgp rate case november 2010 tgp filed rate case ferc proposing increase base tariff rates including proposed change rate structure expected increase percentage reservation revenues tgp relative revenues derived excess fuel recoveries throughput system new base tariff rates would increase revenue approximately 203 million annually previously effective tariff rates december 2010 ferc issued order accepting suspending effective date proposed rates june 1 2011 subject refund outcome hearing proceedings time outcome matter currently determinable cig rate case terms 2006 rate case settlement cig must file new general rate case effective later october 1 2011 late january 2011 cig filed ferc amendment 2006 settlement unopposed cig’s shippers request modification settlement allow effective date required new rate case moved december 1 2011 purpose delay filing date allow cig shippers opportunity reach settlement rate proceeding formally filed ferc time outcome prefiling settlement negotiations outcome upcoming general rate case event prefiling settlement cannot reached uncertain exploration production segment overview strategy exploration production segment conducts natural gas oil exploration production activities profitability performance segment driven ability locate develop economic natural gas oil reserves extract reserves lowest possible production administrative costs accordingly manage business goal creating value disciplined capital allocation cost control portfolio management strategy focuses building applying competencies assets repeatable programs executing improve capital expense efficiency maximizing returns adding assets inventory match competencies divesting assets 2010 approximately 93 percent capital spent domestic projects continued focus unconventional resource plays including haynesville shale northwest louisiana east texas eagle ford shale south texas altamont fractured tight sands utah also entered emerging wolfcamp shale permian basin lease acreage area current state commodity prices forecasts project natural gas prices remain low near term strategy shift focus toward oilier liquids rich areas assets 2011 capital primarily focused domestically target haynesville altamont eagle ford wolfcamp areas information estimated 2011 capital program see outlook 2011 internationally portfolio consists producing fields along several exploration development projects offshore brazil exploration projects egypt 2010 international capital primarily brazil constituted approximately 7 percent total capital program success international programs brazil egypt require effective project management strong partner relations obtaining approvals regulatory agencies although material impact operations date uncertain effect political unrest associated changes government egypt short term long term plans country evaluate acquisition growth opportunities focused core competencies areas competitive advantage strategic acquisitions like leasehold acquisitions wolfcamp shale permian basin haynesville shale eagle ford shale 2010 natural gas oil properties altamont utah 2009 provide us greater opportunities achieve long term goals leveraging existing expertise key operating areas balance exposure regions basins commodities help us achieve riskadjusted returns competitive available within existing inventory increase reserves supplementing current drilling inventory profitability performance impacted ability execute upon strategy changes commodity prices industrywide changes cost drilling oilfield services impact daily production operating capital costs additionally may impacted effect hurricanes weather events effects domestic international regulatory actions response events outside control eg oil spills extent possible attempt mitigate certain risks actions entering longer term contractual arrangements control costs entering derivative contracts reduce financial impact downward commodity price movements significant operational factors affecting year ended december 31 2010 production average daily production year 782 mmcfed including 62 mmcfed equity interest production four star analysis 2010 production division mmcfed central division 2010 central division production volumes continued increase result successful arklatex drilling programs including haynesville shale haynesville shale drilled 78 wells year average net production approximately 143 mmcfed december 31 2010 58 operated wells producing rate approximately 210 mmcfed western division 2010 western division production volumes increased primarily due successful drilling programs altamont offset natural declines rockies gulf coast division 2010 gulf coast division production volumes decreased primarily due natural declines lower levels drilling activity division 2010 focus increasing eagle ford shale acreage december 31 2010 hold approximately 170000 net acres approximately 105000 net acres located liquidsrich area successfully drilled 21 wells also acquired additional 123000 acres wolfcamp shale area bringing total leasehold amount approximately 138000 acres brazil 2010 production increased due production camarupim field began production fourth quarter 2009 cash operating costs monitor cash operating costs required produce natural gas oil cash operating costs nongaap measure calculated per mcfe basis includes total operating expenses less depreciation depletion amortization expense ceiling test impairment charges transportation costs cost products cash operating costs per unit valuable measure operating performance efficiency exploration production segment year ended december 31 2010 cash operating costs per unit decreased 178mcfe compared 182mcfe 2009 decrease 2010 primarily due lower lease operating expenses lower general administrative expenses reserve replacement ratioreserve replacement costs calculate two primary metrics reserve replacement ratio ii reserve replacement costs measure ability establish longterm trend adding reserves reasonable cost core asset areas reserve replacement ratio indicator ability replenish annual production volumes grow reserves important us economically find develop new reserves offset produced volumes provide future production given inherent decline hydrocarbon reserves addition calculate reserve replacement costs assess cost adding reserves ultimately included depreciation depletion amortization expense believe ability develop competitive advantage natural gas oil companies dependent adding reserves core asset areas lower costs competition calculate metrics follows reserve replacement ratio sum reserve additions1 2 actual production corresponding period reserve replacement costsmcfe total oil gas capital costs3 sum reserve additions 1 2 1 reserve additions include proved reserves reflect reserve revisions prices performance extensions discoveries additions acquisitions include unproved reserve quantities proved reserve additions attributable investments accounted using equity method present metrics separately including excluding impact price revisions reserves demonstrate effectiveness drilling program exclusive economic factors price outside control amounts derived directly table presented item 8 financial statements supplementary data supplemental natural gas oil operations 2 proved reserves used calculation reserve replacement ratio reserve replacement costs 2010 2009 determined based sec’s final rule modernization oil gas reporting final rule effective december 31 2009 final rule among things revised definitions proved reserves required us use first day 12month average price determining estimated proved reserves 3 total oil gas capital costs include costs development exploration property acquisition activities conducted add reserves exclude asset retirement obligations amounts derived directly table presented item 8 financial statements supplementary data supplemental natural gas oil operations reserve replacement ratio reserve replacement costs per unit statistical indicators limitations including predictive comparative value annual measure reserve replacement ratio limited typically varies widely based extent timing new discoveries project sanctioning property acquisitions addition since reserve replacement ratio consider cost timing developing future production new reserves cannot used measure value creation exploration acquisition development natural gas oil reserves inherently uncertain discussed part item 1a risk factors risks related business one risks uncertainties ability spend sufficient capital increase reserves currently expect spend amounts future assurances timing magnitude expenditures classification proved reserves developed undeveloped december 31 2010 proved developed reserves represent approximately 60 percent total consolidated proved reserves proved developed reserves generally begin producing within year added whereas proved undeveloped reserves generally require major future expenditure table shows reserve replacement costs reserve replacement ratio domestic worldwide operations including excluding effect price revisions reserves years ended december 31 1 proved property acquisition costs excluded calculations leasehold unproved acquisitions costs included calculations typically cite reserve replacement costs context multiyear trend recognition limitation single year measure also demonstrate consistency stability essential business model table shows reserve replacement costs domestic worldwide operations three years ended december 31 2010 capital expenditures oil gas capital expenditures follows three years ended december 31 1 total oil gas capital costs include costs development exploration property acquisition activities conducted add reserves exclude asset retirement obligations amounts derived directly table presented item 8 financial statements supplementary data supplemental natural gas oil operations outlook 2011 expect following worldwide basis • capital expenditures excluding acquisitions approximately 13 billion total expect spend approximately 12 billion domestic program approximately half expected allocated oil liquids programs approximately 01 billion brazil egypt retain flexibility allocating capital response market conditions changes price natural gas oil results core oil programs • average daily production volumes year approximately 790 mmcfed 840 mmcfed includes approximately 60 mmcfed four star • average cash operating costs 170mcfe 190mcfe year • depreciation depletion amortization rate 190mcfe 210mcfe price risk management activities enter derivative contracts natural gas oil production primarily stabilize cash flows reduce risk financial impact downward commodity price movements commodity sales apply marktomarket accounting financial derivative contracts hedge entirety price risks strategy partially reduces commodity price exposure reported results operations financial position cash flows impacted significantly commodity price movements period adjustments strategy decision enter new positions alter existing positions made based goals overall company following table reflects contracted volumes minimum maximum average prices receive derivative contracts december 31 2010 1 volumes presented tbtu natural gas mbbl oil prices presented per mmbtu natural gas per bbl oil 2 basis swaps effectively limit exposure differences nymex gas price location sell gas average prices listed amounts pay per mmbtu relative nymex price “lockin” locational price differences 3 three way collarsfloors effectively “lockin” cash settlement 2014 market prices 37 mmbbls first two months 2011 entered 641 mbbls fixed price swaps anticipated 2012 oil production average price 10013 per barrel also entered additional threeway collars 43 mmbbls anticipated 2012 oil production volumes transactions effectively provide average ceiling price 10869 per barrel average floor price 9000 per barrel unless oil prices drop 6500 per barrel oil prices drop 6500 per barrel transactions effectively lockin cash settlement market price plus 2500 per barrel operating results variance analysis information provides financial results analysis significant variances results periods ended december 31 year ended december 31 2010 compared year ended december 31 2009 ebit 2010 increased 21 billion compared 2009 table shows significant variances financial results 2010 compared 2009 physical sales physical sales represent accrualbased commodity sales transactions customers 2010 revenues increased compared 2009 due primarily higher commodity prices year ended december 31 2010 also benefited increase production volumes central western divisions brazil realized unrealized gains financial derivatives year ended december 31 2010 recognized net gains 390 million compared net gains 687 million 2009 gains losses period based movements forward commodity prices relative prices underlying financial derivative contracts depreciation depletion amortization expense year ended december 31 2010 depreciation depletion amortization expense increased compared period 2009 result higher depletion rate higher production volumes year ended december 31 2009 depletion rate largely impacted ceiling test charges recorded first quarter 2009 production costs production costs increased 2010 compared 2009 primarily due higher production taxes increased due higher natural gas oil revenues general administrative expenses general administrative expenses decreased 2010 compared period 2009 primarily due lower payroll administrative costs support business following reorganizations 2009 ceiling test charges required conduct quarterly impairment tests capitalized costs full cost pools year ended december 31 2010 recorded noncash ceiling test charges 25 million egyptian full cost pool result contractual acreage relinquishments blocks dry hole drilled tanta block year ended december 31 2009 recorded noncash ceiling test charges 21 billion domestic brazilian full cost pools result low natural gas oil prices egyptian full cost pool result dry hole costs future may required record additional ceiling test charges related egyptian brazilian full cost pools continue add costs respective full cost pools including costs currently excluded amortizable base without corresponding increase value proved reserves equity earnings four star 2010 increased 23 million compared 2009 primarily due impact higher commodity prices partially offset lower production volumes year ended december 31 2009 compared year ended december 31 2008 ebit 2009 increased 99 million compared 2008 table shows significant variances financial results 2009 compared 2008 physical sales year ended december 31 2009 natural gas oil condensate ngl revenues decreased compared 2008 due lower commodity prices lower production volumes realized unrealized gains financial derivatives year ended december 31 2009 recognized net gains 687 million compared net gains 196 million 2008 due lower natural gas oil prices 2009 relative commodity prices contained derivative contracts depreciation depletion amortization expense 2009 depreciation depletion amortization expense decreased result lower depletion rate lower production volumes lower depletion rate primarily result impact ceiling test charges recorded december 2008 march 2009 production costs production costs decreased 2009 compared periods 2008 primarily due lower production taxes result lower natural gas oil revenues lower lease operating expenses cost declines lower commodity price environment general administrative expenses general administrative expenses increased 2009 compared periods 2008 primarily due reversal 20 million accrual 2008 result favorable ruling legal matter higher severance costs approximately 7 million due reorganizations 2009 ceiling test charges fourth quarter 2008 first quarter 2009 recorded total noncash ceiling test charges 27 billion 21 billion calculation charges based spot commodity prices end period calculating fourth quarter 2008 ceiling test charges capitalized costs exceeded ceiling limit 22 billion domestic full cost pool 05 billion brazilian full cost pool first quarter 2009 due low natural gas oil prices experienced downward pricerelated reserve revision approximately 400 bcfe primarily arklatex raton midcontinent areas recorded noncash ceiling test charges approximately 20 billion domestic full cost pool 28 million brazilian full cost pool fourth quarter 2009 primarily due proved reserve additions record ceiling test charges domestic full cost pool however recorded 30 million ceiling test charge brazilian full cost pool result lower commodity prices downward performancerelated reserve revision pescadaarabaiana fields accordance sec’s final rule modernization oil gas reporting effective december 31 2009 used 12month average price calculated unweighted arithmetic average price first day month within 12month period prior end reporting period performing ceiling tests calculating ceiling test charges also required hold prices constant life reserves even though actual prices natural gas oil volatile change period information first day 12month average price used calculate ceiling test see supplemental natural gas oil operations 2009 2008 also recorded noncash ceiling test charges egyptian full cost pool 34 million 9 million charges primarily result dry hole costs unsuccessful wells drilled years impairment inventory assets 2009 recorded 16 million noncash charge reflect market price expect receive upon sale certain casing tubular goods inventory materials supplies prior time intended use capital programs based changes capital program decided would sell inventory use proceeds purchase inventory related current capital projects also recorded 9 million noncash charge result decision close bluebell processing plant 2010 equity earnings four star increased 63 million year ended december 31 2009 compared 2008 primarily due impairment carrying value investment 125 million recorded 2008 partially offset impact lower commodity prices 2009 marketing segment marketing segment’s primary focus market exploration production segment’s natural gas oil production manage el paso’s overall price risk addition continue manage liquidate remaining legacy contracts primarily entered prior deterioration energy trading environment 2002 remaining contracts subject counterparty credit nonperformance risks remaining marktomarket contracts also subject interest rate exposure natural gas transportationrelated contracts impact accrualbased transportation contracts based ability use remarket contracted pipeline capacity amount production exploration production segment december 31 2010 contracts require us pay demand charges 41 million 2011 average 40 million 2012 2015 beginning 2016 agreement associated ruby pipeline project continues 2021 legacy natural gas power contracts december 31 2010 contracts include longterm accrual based supply contracts including transportation expenses obligate us deliver natural gas specified power plants ii power contracts pjm region 2016 marktomarket results contracts expected minimal future impact us entered offsetting positions eliminate price risks associated pjm power contracts substantially offset fixed price exposure related natural gas supply contracts operating results overview overall operating results analysis marketing segment three years ended december 31 follows years ended december 31 2010 2009 2008 results impacted changes fair value legacy power contracts pjm prior entering contracts eliminated risks associated pjm power contracts result entering contracts expect future earnings impact pjm contracts solely related changes interest rates credit risk also impacting twelve months ended december 31 2009 52 million marktomarket gain related adoption new accounting requirements derivative liabilities associated noncash collateral eg letters credit partially offset 27 million loss related impact el paso’s credit standing derivative liabilities year ended december 31 2008 also recognized mark market losses productionrelated natural gas crude contracts held managed year ii 19 million revenue related bankruptcy settlements associated natural gas derivative contracts corporate expenses net corporate activities include general administrative functions emerging midstream business remaining power operations miscellaneous businesses following summary significant items impacting ebit corporate activities three years ended december 31 environmental legal reserves results periods presented impacted changes certain legacy litigation environmental remediation reserves indemnification liabilities including adjustments environmental reserves associated nonoperating chemical plant 2010 2009 2008 recorded favorable adjustments related resolving certain legacy litigation matters including 65 million related case corporation indemnification dispute see item 8 financial statements supplementary data note 12 32 million related settlement certain class action matters partially offset marktomarket losses associated indemnification related sale legacy ammonia facility fluctuates ammonia prices 2010 eliminated significant portion exposure indemnification number pending litigation environmental matters reserves related historical business operations affect corporate results adverse rulings unfavorable outcomes settlements us related matters impacted may continue impact future results gain loss sale assets additionally december 2010 recorded gain 110 million conjunction sale 50 percent interest new midstream joint venture comprised altamont gathering processing midstream assets 125 million cash 50 percent interest operate new joint venture accounted equity investment 2009 recorded loss 22 million associated sale notes receivable previously received consideration sale investment porto velho 2008 recorded gains related sale share telecommunication assets legacy assets loss debt extinguishment 2010 recorded total loss 217 million conjunction exchanging approximately 349 million 1200 senior notes due 2013 cash 650 senior notes due 2020 ii repurchasing approximately 709 million senior notes due 2011 2016 2010 recorded 40 million income due receipt funds previously escrowed expensed conjunction coastal corporation merger postretirement benefit costs general administrative costs related legacy acitivities impacted results 2010 2009 2008 losses pension plan assets previous years amortized net benefit costs future anticipated increase expense related plan 2011 beyond despite increased expense anticipate making contributions primary pension plan 2011 discussion postretirement plans related net benefit cost see item 8 financial statements supplementary data note 13 interest debt expense interest debt expense years ended december 31 2010 2009 2008 10 billion 10 billion 09 billion interest debt expense flat 2010 compared 2009 primarily due increases ruby pipeline project financings net higher afudc debt associated ruby project additionally 2010 impacted changes estimates allowance funds used construction increase interest rate 7 percent 13 percent ruby term loan 2009 interest debt expense increased compared prior year due primarily higher interest rates amortization discounts related debt issuances financing obligations net retirements see item 8 financial statements supplementary data note 11 discussion 2010 exchanged repurchased approximately 11 billion debt rates ranging 7 percent 12 percent described item 8 financial statements supplementary data note 11 expect reduction annual interest expense approximately 80 million 85 million independent financing actions income taxes discussion effective tax rate refer item 8 financial statements supplementary data note 5 commitments contingencies discussion commitments contingencies see item 8 financial statements supplementary data note 12 liquidity capital resources primary sources cash include cash flow operations funds obtained long term financings including capital market activities including executing financing strategy utilizing master limited partnership bank credit facilities also generate cash project financings ruby asset sales warranted typically rely shortterm borrowings fulfill liquidity needs primary uses cash funding capital expenditure programs meeting operating needs paying distributions dividends repaying debt due repurchasing debt conditions warrant available liquidity outlook 2011 2010 successful funding capital liquidity needs december 31 2010 approximately 24 billion available liquidity exclusive cash credit facility capacity epb ruby partially result 2010 funding actions including receipt 23 billion cash conjunction contributing ownership interests slng elba express sng mlp funded acquisitions issuance debt common units ii sale interests certain mexican pipeline compression assets approximately 03 billion receipt 01 billion cash conjunction sale 50 percent interest altamont gathering processing assets part new midstream joint venture iii finalizing sevenyear amortizing 15 billion ruby financing facility matures 2017 borrowed approximately 11 billion december 31 2010 full year capital requirements including ruby pipeline project pipeline projects exploration production expenditures significant however 2011 requirements decline considerably end 2011 expect substantial portion pipeline backlog placed service 2011 capital programs anticipate planned cash capital expenditures operations follows 1 pipeline growth capital expenditures reflect 100 percent capital related ruby project 2009 obtained partner project described 2 includes planned cash capital expenditures midstream operations approximately 01 billion began construction largest pipeline project ruby project 2010 currently expect project placed service july 2011 estimated total cost approximately 355 billion gip 50 percent partner ruby pipeline project provided approximately 700 million support ruby project subject satisfaction various conditions including placing ruby pipeline project service entering certain additional firm transportation agreements obligation repay amounts secured equity interests ruby cheyenne plains 50 million common units mlp also provided contingent completion costoverrun guarantee ruby lenders however upon ruby pipeline project becoming operational making certain permitting representations project financing become nonrecourse us pursuant cost overrun guarantee ruby lenders required post letters credit forecasted cost overruns project approved lender’s independent engineer regard posted approximately 04 billion letters credit cover anticipated cost overruns additional cost overruns forecasted approved lender’s engineer subsequent months additional letters credit required issued pursuant ruby financing agreements description project agreement gip see item 8 financial statements supplementary data notes 11 17 expect current liquidity sources operating cash flow sufficient fund estimated 2011 capital program 2011 also debt maturities approximately 500 million pay mature additionally end 2012 required renew primary longterm revolving credit facilities see item 8 financial statements supplementary data note 11 significant facilities 15 billion epc revolver 13 billion epep revolving credit facilities year ended december 31 2010 amount borrowed utilized letters credit two facilities aggregated approximately 09 billion result 2010 actions current available liquidity hedging program place natural gas oil production planned future actions including continuing mlp drop strategy markets permit believe well positioned meet obligations well continue efforts strengthen balance sheet continue assess take actions prudent meet longterm objectives capital requirements well address changes financial commodity markets however number factors could impact plans including ability access financial markets fund longterm capital needs financial markets restricted decline commodity prices events occur additional adjustments plan outlook may required including reductions discretionary capital program reductions operating general administrative expenses obtaining secured financing arrangements seeking additional partners growth projects sale additional noncore assets could impact financial operating performance overview 2010 cash flow activities 2010 generated operating cash flow approximately 18 billion primarily pipeline exploration production operations generated approximately 05 billion total sale certain mexican pipeline compression assets sale 50 percent interest altamont gathering processing assets part new midstream joint venture asset sales ii approximately 13 billion result issuance mlp common units iii approximately 34 billion debt proceeds including mlp financings well ruby consolidated project financings utilized amounts fund capital programs repay amounts outstanding various credit facilities debt obligations pay common preferred dividends distributions mlp unitholders holders subsidiary preferred stock among items year ended december 31 2010 2009 cash flows operations summarized follows offbalance sheet arrangements enter variety financing arrangements contractual obligations referred offbalance sheet arrangements include guarantees letters credit interests variable interest entities guarantees indemnifications involved joint ventures ownership arrangements sometimes require financial performance guarantees financial guarantee obligated make payments guaranteed party fails make payments violates terms financial arrangement performance guarantee provide assurance guaranteed party execute terms contract required perform behalf also periodically provide indemnification arrangements related assets businesses sold arrangements include limited indemnifications income taxes resolution existing disputes environmental matters potential exposure guarantee indemnification agreements range specified unlimited dollar amount depending nature claim particular transaction many agreements may specify maximum potential exposure specified duration indemnification obligation circumstances amount duration unlimited arrangements specified dollar amount maximum stated value approximately 08 billion primarily relates indemnification arrangements associated sale anr macae power facility brazil legacy assets amounts exclude guarantees issued related letters credit discussed item 8 financial statements supplementary data note 11 included maximum stated value certain indemnification agreements expired however claims made prior expiration related claim periods unable estimate maximum exposure guarantee indemnification agreements provide limits amount future payments due uncertainty exposures december 31 2010 recorded obligations 18 million related guarantee indemnification arrangements liability consists primarily indemnification one subsidiaries provided related sale ammonia facility reflected financial statements fair value provided partial parental guarantee subsidiary’s obligations indemnification letters credit enter letters credit ordinary course operations well periodically conjunction sales assets businesses december 31 2010 outstanding letters credit approximately 11 billion including 05 billion letters credit securing recorded obligations related price risk management activities additional information counterparty credit nonperformance risk see item 8 financial statements supplementary data note 7 depending changes commodity prices interest rates could required post additional margin may recover margin earlier anticipated 10 percent change natural gas power prices would significant impact margin requirements derivative contracts december 31 2010 interests variable interest entities interests several variable interest entities primarily ruby variable interest entity legal entity whose equity owners sufficient equity risk characteristics controlling financial interest entity required consolidate entities ability control direct operating financial decisions activities significant entity december 31 2010 significant variable interest entities consolidate additional information regarding interest ruby see item 8 financial statements supplementary data note 17 contractual obligations party various contractual obligations include offbalance sheet arrangements described portion obligations reflected financial statements longterm debt liabilities commoditybased derivative contracts accrued liabilities obligations demand charges transportation storage commitments operating leases capital commitments reflected balance sheet following table discussion summarizes contractual cash obligations december 31 2010 periods presented longterm financing obligations principal interest debt obligations included table represent stated maturities interest payments shown stated maturity date related debt based contractual interest rate fixed rate debt ii current market interest rates contractual credit spread variable rate debt discussion debt obligations see item 8 financial statements supplementary data note 11 liabilities price risk management activities amounts include fair value price risk management liabilities fair value price risk management assets 326 million december 31 2010 reflected amounts also excluded margin deposits held associated contracts amounts contractual liabilities included amount contractual environmental obligations included current noncurrent liabilities balance sheet excluded amounts expected contributions pension postretirement benefit plans expected contributions fixed time amount information expected contributions pension post retirement benefit plans see item 8 financial statements supplementary data note 13 also excluded amounts liabilities unrecognized tax benefits 276 million december 31 2010 since cannot reasonably estimate time frame amounts may resolved operating leases discussion obligations see item 8 financial statements supplementary data note 12 contractual commitments purchase obligations contractual commitments purchase obligations defined legally enforceable agreements purchase goods services fixed minimum quantities fixed minimum variable price provisions detail approximate timing underlying obligations included following • transportation storage commitments included amounts commitments demand charges firm access natural gas transportation storage capacity • commitments included amounts commitments purchasing pipe related assets pipeline operations commitments drilling seismic activities exploration production operations various maintenance engineering procurement construction contracts well service license agreements used operations also included longterm commitments us related right way payments discussed item 8 financial statements supplementary data note 12 excluded asset retirement obligations reserves litigation environmental remediation selfinsurance claims disclosed liabilities contractually fixed timing amount critical accounting estimates significant accounting policies described note 1 consolidated financial statements included item 8 annual report form 10k preparation financial statements conformity generally accepted accounting principles requires management select appropriate accounting estimates make estimates assumptions affect reported amount assets liabilities revenue expenses disclosures contingent assets liabilities consider critical accounting estimates require difficult complex subjective judgment necessary accounting inherently uncertain matters could significantly influence financial results based changes judgments changes facts circumstances may result revised estimates actual results may differ materially estimates discussed development selection following critical accounting estimates related disclosures audit committee board directors accounting natural gas oil producing activities estimates proved reserves reflect quantities natural gas oil ngl geological engineering data demonstrate reasonable certainty recoverable future years known reservoirs existing economic conditions process estimating natural gas oil reserves complex requiring significant judgment evaluation available geological geophysical engineering economic data proved reserves estimated property level compiled reporting purposes centralized group experienced reservoir engineers work closely operating groups engineers interact engineering geoscience personnel operating areas accounting marketing personnel obtain necessary data projecting future production costs net revenues ultimate recoverable reserves reviewed internally senior management quarterly presented board directors summary form annual basis additionally annual basis property reviewed detail centralized operating divisional engineers ensure forecasts operating expenses netback prices production trends development timing reasonable proved reserves also reviewed internal committees processes controls used estimating proved reserves reviewed internal auditors addition thirdparty reservoir engineering firm appointed reports audit committee board directors conducts audit estimates significant portion proved reserves particular ryder scott company lp conducted audit estimates proved reserves december 31 2010 december 31 2010 total consolidated proved reserves 40 percent undeveloped 38 percent including four star 12 percent developed nonproducing data given field may change substantially time result numerous factors including additional development activity evolving production history continual reassessment viability production changing economic conditions result material revisions existing reserve estimates occur time addition subjective decisions variances available data various fields increase likelihood significant changes estimates proved natural gas oil reserves primarily impact property plant equipment amounts balance sheets depreciation depletion amortization amounts ceiling test charges income statements among items use full cost method account natural gas oil producing activities accounting method capitalize substantially costs incurred connection acquisition exploration development natural gas oil reserves including salaries benefits internal costs directly related finding activities asset retirement costs capitalized interest capitalized costs maintained full cost pools geographic area regardless whether reserves actually discovered record depletion expense capitalized amounts plus estimated finding development costs life proved reserves based unit production method factors held constant 10 percent increase estimated proved reserves would decrease unit production depletion rate 9 percent 10 percent decrease estimated proved reserves would increase unit depletion rate 11 percent information regarding price sensitivities related estimated proved reserves see part item 1 business natural gas oil properties natural gas oil properties include unproved property costs excluded costs depleted unproved property costs include nonproducing leasehold geological geophysical costs associated unevaluated leasehold drilling interests exploration drilling costs investments unproved properties major development projects direct interest exclude costs countrybycountry basis proved reserves found determined costs impaired costs excluded reviewed least quarterly determine exclusion fullcost pool continues appropriate costs determined impaired amount impairment transferred full cost pool reserve base exists expensed reserve base yet created impairments transferred full cost pool increase depletion rate country discussion costs country see part ii item 8 financial statements supplementary data supplemental natural gas oil operations full cost accounting method natural gas oil properties required conduct quarterly impairment tests capitalized costs full cost pools impairment test referred ceiling test total capitalized costs net related deferred income taxes limited ceiling based present value future net revenues proved reserves discounted 10 percent plus cost unproved natural gas oil properties amortized less related income tax effects december 31 2009 adopted provisions sec’s final rule modernization oil gas reporting among things final rule revised definition proved reserves required us use first day 12month average price calculating ceiling test estimating proved reserves rather period end spot price required prior periods discounted future net cash flows greater equal total capitalized costs required writedown capitalized costs level discounted future net cash flows costbased regulation account regulated operations accordance current financial accounting standard board fasb accounting standards rateregulated operations economic effects regulation result regulated company recording assets costs expected approved recovery customers recording liabilities amounts expected returned customers ratesetting process period different period amounts would recorded unregulated enterprise accordingly record assets liabilities result regulated ratemaking process would recorded gaap nonregulated entities management regularly assesses whether regulatory assets probable future recovery regulatory liabilities probable refunded customers considering factors applicable regulatory changes recent rate orders applicable regulated entities based continual assessment management believes existing regulatory assets probable recovery periodically evaluate applicability accounting standards related regulated operations consider factors regulatory changes impact competition costbased regulation ends competition increases may reduce certain asset balances reflect market basis lower cost writeoff associated regulatory assets accounting environmental legal reserves guarantees indemnifications accrue environmental legal reserves assessments indicate probable liability incurred amount reasonably estimated estimates liabilities based evaluation potential outcomes currently available facts case environmental reserves existing technology presently enacted laws regulations taking consideration likely effects societal economic factors estimates associated onsite offsite groundwater technical studies legal costs actual results may differ estimates often revised future either negatively positively depending upon actual outcomes changes expectations based facts surrounding matter december 31 2010 accrued approximately 45 million legal matters approximately 173 million environmental matters reduced 19 million amounts paid directly government sponsored programs settlement arrangements environmental estimates range approximately 173 million approximately 365 million lower end expected range accrued also guarantee indemnification agreements related various joint ventures ownership arrangements require us assess potential exposure range specified amount unlimited dollar amount depending nature claim particular transaction arrangements specified dollar amount maximum stated value approximately 08 billion december 31 2010 recorded obligations 18 million related guarantee indemnification arrangements unable estimate maximum exposure guarantee indemnification agreements provide limits amount future payments agreement due uncertainty exposures information see balance sheet arrangements accounting pension postretirement benefits reflect asset liability pension postretirement benefit plans based funded status december 31 2010 pension plans funded 170 million postretirement benefit plans funded 394 million pension postretirement benefit obligations net benefit costs primarily based actuarial calculations use various assumptions performing calculations including related return expect earn plan assets rate expect compensation employees increase plan term estimated cost health care benefits provided plans factors significant assumption utilize discount rates used calculating benefit obligations select discount rates matching timing amount expected future benefit payments pension postretirement benefit obligations average yields various highquality bonds corresponding maturities actual results may differ assumptions included calculations result estimates associated pension postretirement benefits often revised future income statement impact changes assumptions related benefit obligations along changes plans items deferred amortized income either period expected future service active participants expected future lives inactive plan participants record deferred amounts accumulated comprehensive income nonregulated operations either regulatory asset liability regulated operations december 31 2010 deferred net losses approximately 682 million net income taxes accumulated comprehensive income related pension postretirement benefits following table shows impact one percent change primary assumptions used actuarial calculations associated pension postretirement benefits year ended december 31 2010 millions 1 actual return plan assets one percent lower expected return plan assets expected cash contributions pension postretirement benefit plans would change significantly estimates net benefit expense income partially based expected return pension plan assets use marketrelated value plan assets determine expected return pension plan assets determining marketrelated value plan assets differences expected actual asset returns deferred three years considered inclusion net benefit expense income used fair value plan assets instead marketrelated value plan assets determining expected return pension plan assets net benefit expense would 15 million higher year ended december 31 2010 price risk management activities record derivative instruments used price risk management activities fair values estimate fair value derivative instruments using exchange prices thirdparty pricing data valuation techniques incorporate specific contractual terms statistical simulation analysis present value concepts one primary assumptions used estimate fair value derivative instruments pricing assumptions based upon price curves derived actual prices observed market pricing information supplied thirdparty valuation specialist independent pricing sources models rely forward pricing information extent rely pricing information received third parties developing assumptions based part whether information considers availability observable data marketplace example relatively illiquid markets may make adjustments pricing information receive third parties based evaluation whether third party market participants would use pricing assumptions consistent sources table presents hypothetical sensitivity commoditybased price risk management activities changes fair values arising immediate selected potential changes natural gas oil power prices december 31 2010 another significant assumption discount rates use determining fair value derivative instruments table presents hypothetical sensitivity commoditybased price risk management activities changes fair values arising changes discount rates used determine fair value derivatives december 31 2010 significant assumptions use determining fair value derivative instruments related anticipated market liquidity credit nonperformance risk counterparties adjust fair value derivative assets risk nonperformance counterparties considering collateral posted derivative changes counterparties’ creditworthiness measured part based changes bond yields changes actively traded credit default swap prices available information credit standing adjust fair value derivative liabilities creditworthiness utilizing similar inputs considering cash collateral posted counterparties table presents hypothetical sensitivity commoditybased price risk management activities changes fair values arising potential changes credit risk december 31 2010 deferred taxes uncertain income tax positions record deferred income tax assets liabilities reflecting tax consequences deferred future periods based differences financial statement carrying value assets liabilities tax basis assets liabilities additionally deferred tax assets liabilities reflect assessment tax positions taken resulting tax basis reflect conclusions positions likely sustained audited taxing authorities significant judgments tax related matters include limited items noted matters involve exercise significant judgment could change materially impact financial condition results operations discussion items income tax matters see item 8 financial statements supplementary data note 5 valuation allowance realization deferred tax assets depends recognition sufficient future taxable income specific tax jurisdictions periods temporary differences deductible valuation allowances established necessary reduce deferred income tax assets amounts believe likely recovered evaluating valuation allowance consider reversal existing temporary differences existence taxable income prior carryback years tax planning strategies future taxable income taxable jurisdictions latter two involve exercise significant judgment changes valuation allowance could materially impact results operations uncertain tax positions liabilities unrecognized tax benefits related uncertain tax positions connected ongoing examinations open tax years changes assessment liabilities may require us increase liability record additional tax expense reverse liability recognize tax benefit would positively negatively impact effective tax rate undistributed earnings foreign investees certain unconsolidated affiliates record deferred tax liabilities undistributed earnings foreign investments anticipate earnings repatriated plan repatriate foreign undistributed earnings provision made us taxes foreign withholding taxes changes repatriation assumptions including repatriation proceeds sales investments could require us record additional deferred taxes additionally believe certain unconsolidated affiliates’ undistributed earnings ultimately distributed us dividends would eligible dividends received deduction joint venture partners intent ability recover cumulative undistributed earnings time dividends structured sale would result additional deferred tax liabilities asset investment impairments accounting rules asset investment impairments require us continually monitor businesses business environment performance investments determine event occurred indicates longlived asset investment may impaired event occurs determination involves judgment estimate fair value asset estimate considers number factors including potential value would receive sold asset projected cash flows asset based current anticipated future market conditions discount rates assessment fair value including limited estimates project level cash flows requires significant judgment make projections assumptions many years future pricing demand competition operating costs legal regulatory issues factors often outside control due imprecise nature projections assumptions actual results often differ estimates utilize cash flow projections assess ability recover carrying value assets investments based either longlived assets’ ability generate future cash flows undiscounted basis ii fair value investments unconsolidated affiliates whether decline fair value carrying amount considered temporary impairment indicated record impairment charge excess carrying value asset fair value years ended december 31 2010 2009 2008 recorded impairments 10 million 30 million 41 million related longlived assets recorded impairments losses investments advances unconsolidated affiliates 127 million year ended december 31 2008 future changes economic business environment impact assessments potential impairments principles consolidation entities third parties equity interests perform evaluation determine party consolidate entity part evaluation required determine whether entity considered variable interest entity vie ultimately party considered primary beneficiary andor controls entitys operating financial decisions part evaluations significant amount judgment involved evaluating entities contractual relationships relative nature third partys interests entities ability control direct activities different judgment applied accounting treatment financial statement presentation entities could significantly impacted discussion significant variable interest entities investments unconsolidated affiliates december 31 2010 see item 8 financial statements supplementary data notes 17 18 item 7aitem 7 management’s discussion analysis financial condition results operations overview management’s discussion analysis mda read conjunction consolidated financial statements accompanying footnotes forwardlooking statements section throughout form 10k also read conjunction announcement definitive agreement kmi described part item 1 business mda includes forwardlooking statements subject risks uncertainties discussed item 1a risk factors may result actual results differing statements make proposed merger kinder morgan inc october 16 2011 announced definitive merger agreement kinder morgan inc kmi whereby kmi acquire el paso corporation el paso transaction valued el paso approximately 38 billion based kmi stock price date including assumption debt merger agreement approved kmi’s board directors completion merger subject satisfaction waiver certain closing conditions including among others customary regulatory approvals approval stockholders approval issuance kmi stock warrants kmi’s stockholders voting agreement executed certain stockholders kmi holding approximately 75 percent voting power kmi stockholders agreed vote favor merger issuance kmi stock warrants completion merger constitute change control el paso may trigger provisions certain agreements including related debt financing agreements ii severance agreements iii incentive compensation plan agreements result immediate acceleration unvested stock based compensation awards upon closing merger debt financing agreements containing covenants related change control events terminated pursuant merger either amended agreements obtained waivers covenants however downgrade credit ratings upon completion transactions kmi could trigger certain change control provisions certain agreements party merger agreement includes customary representations warranties covenants specific agreements relating conduct el paso’s kmi’s respective businesses date signing merger agreement closing merger transactions ii efforts parties cause merger transactions completed addition certain covenants agreed encourage solicit initiate facilitate takeover proposal third party enter agreement arrangement understanding requiring us abandon terminate fail consummate merger related transactions merger agreement contains certain termination rights el paso kmi provides upon termination merger agreement certain circumstances el paso may required pay kmi termination fee equal 650 million certain circumstances el paso may required reimburse kmi expenses 20 million certain financing related expenses terms merger agreement agreed conduct business ordinary course material respects substantially manner conducted prior date merger agreement subject certain conditions restrictions thresholds including limited ability commit capital expenditures current capital budgets ii acquire invest dispose material properties assets equity interests defined merger agreement iii incur new debt refinance guarantee debt borrowed money iv enter terminate amend certain material contracts v issue grant sell redeem new el paso capital stock stockbased compensation awards andor pay dividends excess 001share among limitations conjunction merger kmi announced intend sell exploration production assets february 24 2012 entered purchase sale agreement sell exploration production assets affiliate apollo global management llc “apollo” certain parties 715 billion subject certain adjustments items contributions distributions incurrence debt title defects sale contemplated merger agreement kmi closing sale conditioned upon closing transactions contemplated merger agreement kmi transactions expected completed second quarter 2012 purchase sale agreement contains customary representations warranties relating exploration production assets operations additionally el paso entered performance guarantee favor apollo guarantee performance seller subsidiaries’ obligations purchase sale agreement pursuant merger agreement kmi required indemnify us cost incurred us arising relating sale exploration production assets upon completion sale exploration production business reflected discontinued operation financial statements listed general outline mda business includes summary business purpose description factors influencing profitability summary 2011 performance results operations includes yearoveryear analysis results business segments corporate activities income statement items including trends may impact business future liquidity capital resources includes overview sources uses cash available liquidity overview cash flow activity 2011 additional factors could impact liquidity balance sheet arrangements contractual obligations includes discussion balance sheet arrangements including guarantees letters credit ii contractual obligations critical accounting estimates includes discussion accounting estimates involve use significant assumptions andor judgments preparation financial statements business provide natural gas related energy products safe efficient dependable manner interests north america’s largest interstate natural gas pipeline systems provide stable base earnings cash flow also large independent oil natural gas producer focused generating competitive financial returns disciplined capital allocation portfolio management cost control marketing selling oil natural gas production optimal prices managing associated price risks also emerging midstream business conjunction proposed merger kmi announced intent sell exploration production business noted closing transaction subject customary regulatory shareholder approvals expected occur second quarter year sale exploration production business condition closing merger kmi discussion see overview factors influencing profitability pipeline operations rateregulated accordingly generate profit based ability earn return excess costs rates charge customers exploration production operations generate profits dependent prices oil natural gas costs explore develop produce oil natural gas volumes able produce among factors longterm profitability operating segments primarily influenced following factors pipelines • contracting recontracting pipeline capacity customers • maintaining obtaining approval ferc acceptable rates terms service expansion projects • ensuring safety pipeline systems assets • improving operating efficiency • executing successfully expansion projects developing growth projects market supply areas exploration production • growing oil natural gas proved reserve base production volumes successful execution drilling programs • finding producing oil natural gas reasonable cost • managing price risks optimize realized prices oil natural gas production addition factors future profitability affected ability execute strategy impacts volatility financial commodity markets industrywide changes cost drilling oilfield services impact daily production operating capital costs debt level related interest costs successful resolution historical contingencies legacy activities extent possible attempt mitigate certain risks actions entering longer term contractual arrangements control costs entering derivative contracts reduce financial impact downward commodity price movements additionally may also impacted hurricanes weather events domestic international regulatory actions response events outside control eg oil spills summary 2011 performance 2011 continued deliver solid operational performance strong base earnings cash flows operations pipeline exploration production businesses 2011 completed remainder 8 billion backlog pipeline expansion projects ruby project placed service four months later planned due permitting weather delays approximately 07 billion original 30 billion budget projects completed time budget exploration production business continued execute strategy increasing production volumes adding proved reserves lowering per unit cash operating costs utilizing hedging program designed support balance sheet cash flows shifted capital program provide us exposure oil opportunities particularly altamont eagle ford wolfcamp areas finally midstream business joint venture expanded asset base altamont eagle ford operating areas 2011 segment ebit 1325 million compared 2341 million period 2010 pipelines segment ebit 2011 significantly impacted noncash loss approximately 475 million based difference net carrying value ruby estimated fair value investment ruby noncash loss approximately 125 million recorded upon deconsolidation ruby associated accumulated comprehensive loss associated interest rate swaps ruby debt exploration production segment increased production volumes year however segment ebit yeartodate decreased approximately 233 million largely due marktomarket impacts financial derivatives third quarter noncash brazilian ceiling test charge approximately 152 million results periods also impacted 169 million debt extinguishment losses associated repurchase approximately 10 billion debt 2011 results discussed individual segment results follow following table provides highlights core businesses financing activities area operations significant highlights pipelines completed 8 billion backlog expansion projects including ruby pipeline project florida gas transmission fgt phase viii expansion phases ii sng south system iii expansion phase ii sng southeast supply header gulf lng clean energy tgp 300 line projects received approximately 14 billion cash conjunction contributing additional ownership interests sng cig master limited partnership mlp funded acquisitions primarily issuance common units debt settled rate cases ferc cig tgp systems exploration production increased proved oil natural gas reserves 40 tcfe 2011 34 tcfe 2010 includes 66 percent increase oil ngl proved reserves increased consolidated oil condensate production 27 percent 2011 increase contributed oil condensate based revenues 30 percent total revenues 58 percent increase 2010 achieved 100 percent domestic drilling success rate focused domestic capital program core programs haynesville shale northwest louisiana altamont fractured tight oil sands utah eagle ford shale south texas wolfcamp shale permian basin texas introduced emerging louisiana wilcox program south louisiana provides additional liquid hydrocarbon resources drilling program managed commodity price risk derivative contracts portion 2011 2014 oil production 2011 2012 natural gas production expanded altamont eagle ford operating areas midstream operations joint venture refinanced 325 billion revolving credit extending maturities 2016 results operations overview december 31 2011 business consists following segments pipelines exploration production marketing also business corporate activities include midstream miscellaneous businesses segments managed separately provide variety energy products services require different technology marketing strategies use segment earnings interest expense income taxes segment ebit measure assess operating results effectiveness business segments believe segment ebit useful investors allows use performance measure analyzed internally management evaluate performance businesses investments without regard manner financed capital structure segment ebit defined net income loss adjusted interest debt expense income taxes reflect reduction amounts attributable noncontrolling interests segment ebit may comparable measurements used companies additionally segment ebit considered conjunction net income loss income loss income taxes performance measures operating income operating cash flows 2010 2009 amounts conformed reflect current performance measure reconciliation segment ebit consolidated net income loss three years ended december 31 discussions follow provide additional analysis year results business segments activities income statement items pipelines segment overview pipelines segment operates united states consists interstate natural gas transmission storage lng receiving terminal services face varying degrees competition segment existing proposed pipelines proposed lng facilities well alternative energy sources used generate electricity hydroelectric power nuclear energy wind solar coal fuel oil revenues transportation storage lng terminalling related services consist two types type description percent 2011 revenues1 reservation revenues customers referred firm customers reserve capacity pipeline systems storage facilities lng terminalling facilities firm customers obligated pay monthly reservation demand charge regardless amount natural gas transport store term contracts usage revenues firm customers interruptible customers without reserved capacity pay usage charges provide fuel inkind based volume gas actually transported stored injected withdrawn also earn revenues processing sale natural gas liquids miscellaneous sources 1 excludes revenues associated liquids condensate sales also excludes regulatory liability adjustment see results operations discussion ferc regulates rates charge customers rates generally function cost providing services customers including reasonable return invested capital regulated nature high percentage revenues attributable reservation charges revenues historically relatively stable however financial results subject volatility due factors changes natural gas prices changes supply demand changes gas flows regulatory actions competition weather declines creditworthiness customers continue manage process renewing expiring contracts limit risk significant impacts revenues ability extend existing customer contracts remarket expiring contracted capacity dependent competitive alternatives regulatory environment federal state local levels market supply demand factors relevant dates contracts extended expire duration new renegotiated contracts affected current prices competitive conditions judgments concerning future market trends volatility although attempt recontract remarket capacity maximum rates allowed tariffs frequently enter firm transportation contracts amounts less maximum rates remain competitive extent amounts less maximum rates varies pipeline systems existing contracts mature various times varying amounts throughput capacity attempt sell capacity long term contracts market remaining open positions shorter term contracts market demand permits currently face recontracting risk certain market areas particularly rockies southwest region 2012 significant amount contracted capacity expire epng system southwest region certain customers hold capacity epng system contract terms one year also hold renewal rights often renew contracts year basis currently remarketing expiring capacity epng system serve either existing customers serve new customers time uncertain much expiring capacity recontracted rates contract expiration portfolio associated revenue expirations firm transportation contracts wholly majority owned systems december 31 2011 including terms beginning 2012 later weighted average remaining contract term active contracts approximately six years december 31 2011 summary operational financial performance 2011 completed 8 billion backlog expansion projects largest company’s history pipelines segment ebit 2011 benefited primarily expansion projects placed service 2010 2011 higher rates tgp system effective june 1 2011 due november 2010 rate case offsetting impact items comparing 2010 noncash losses 2011 associated deconsolidation ruby third quarter 2011 addition gain sale mexican pipeline compression assets 2010 comparable item 2011 expansion projects related afudc higher 2010 compared 2009 partially offset lower revenues epng tgp systems operating results 1 includes losses associated deconsolidation ruby year ended december 31 2011 2 volumes exclude intrasegment activities 3 represents proportional share unconsolidated affiliates discussion factors impacting segment ebit 2011 compared 2010 compared 2009 also provided outlook events could impact segment ebit future periods 1 consists individually insignificant items several pipeline systems expansions 2011 2010 benefited increased reservation revenues due placing number expansion projects service including wic system expansion ii phase slng elba expansion iii elba express pipeline expansion projects iii cig raton 2010 expansion iv phases ii sng south system iii expansion v ruby pipeline project prior deconsolidation vi tgp 300 line expansion project partially offsetting increases depreciation operating expenses associated placing projects service well increased third party capacity commitments capitalize carrying cost afudc funds related construction longlived assets reflect costs increases income statements upon placing project service pursuant regulatory requirements cease recording afudc expansion projects year ended december 31 2011 segment ebit impacted decline approximately 49 million compared 2010 primarily due ruby ceasing record afudc june 2011 based amendment ferc certificate limited afudc accruals however benefited increase equity portion afudc approximately 149 million 2010 compared 2009 primarily ruby pipeline project offset afudc recorded projects placed service 2010 addition projects placed service part 8 billion backlog expansion projects anticipate placing tgp northeast upgrade project service november 2013 estimated cost approximately 400 million project provide 620 mmcfd additional firm transportation service receipt points marcellus shale basin interconnect new jersey firm transportation capacity fully subscribed two shippers agreements executed 2010 tgp filed certificate application ferc march 2011 anticipates receiving approval first quarter 2012 reservationusage revenues expenses reservation usage revenues systems three year period ended december 31 2011 impacted number factors including regulatory actions competition changes supply demand significant noted • tgp system experienced overall net increase reservation usage revenues approximately 134 million year ended december 31 2011 compared 2010 increase primarily due higher rates became effective june 1 2011 result november 2010 rate case higher throughput volumes due increased supply haynesville marcellus shale basins partially offsetting favorable impacts lower usage revenues certain interruptible services due lower prices basis differentials comparing 2010 2009 usage revenues lower approximately 12 million primarily due decrease longhaul transports shift receipts gulf coast region rockies express pipeline interconnect ohio marcellus shale basin shorthaul transportation subject lower rates • epng effective april 1 2011 epng’s rates higher result september 2010 rate case however throughput volumes epng system continued decline 2011 2010 declines driven number factors including reduced demand california market 2011 due high gas storage levels increased hydroelectric generation ii nonrenewal certain expiring contracts iii increased competition california arizona market areas iv lower prices due lower basis differentials related certain interruptible services overall impact items pipelines segment ebit unfavorable 2011 2010 10 million 76 million compared prior periods • sng nonrenewal expiring contracts decreased segment ebit 8 million year ended december 31 2011 compared 2010 additionally sng’s usage revenues lower 6 million primarily due record weather conditions southeast 2010 compared 2011 comparing 2010 2009 pipelines segment ebit favorably impacted 50 million primarily due higher tariff rates effective september 1 2009 due sng’s rate case settlement • cigwic year ended december 31 2011 compared 2010 reservation revenues cig system lower 13 million due increased competition rockies region nonrenewal certain contracts weak market conditions additionally higher transportation expenses wic cig systems 3 million year ended december 31 2011 negatively impacted 2011 results compared 2010 due increased third party capacity commitments gas used operations effective june 1 2011 tgp implemented fuel volume tracker part rate case filed ferc result longer recognizes revenues associated gas used operations lowered pipelines segment ebit 67 million year ended december 31 2011 addition tgp implemented electric compression tracker part rate case resulted lower electric compression expenses 11 million net unfavorable impacts associated operational activities offset higher reservation revenues discussed prior june 1 2011 gas used operations tgp system resulted revenues us recognized volumes retained valued market prices specified tariff 2011 experienced lower prices coupled lower retained fuel volumes excess fuel used operations due shift flow patterns lower volumes operational sales unfavorably impacted segment ebit 10 million partially offset gas sales 8 million 2010 lower realized prices operational sales contributed negatively segment ebit 69 million compared 2009 partially offset 15 million lower electric compression regulatory liability adjustment part tgp’s rate case settlement december 2011 recorded reduction regulatory liabilities associated postretirement benefit plan certain deferred taxes since items provided prior rate settlements funding requirement cost recovery current rates items see discussion tgp rate case regulatory matters operating general administrative expenses 2011 pipelines segment experienced higher benefits payroll costs higher allocated corporate overhead costs based estimated level resources devoted pipelines segment factors negatively impacted results 43 million compared 2010 additionally pipelines segment ebit unfavorably impacted 2011 26 million increased contractor costs due field repairs cig tgp pipeline systems 7 million due higher property taxes several pipeline systems 2010 experienced lower operating general administrative expenses compared 2009 primarily due severance costs approximately 14 million recorded 2009 loss ruby deconsolidation september 2011 upon meeting certain conditions partner lenders deconsolidated ruby began reflecting investment unconsolidated affiliate subsequent deconsolidation ruby’s income loss reflected earnings unconsolidated affiliates income statement reflect earnings ruby interest taxes preferred return partner result deconsolidation ruby recorded noncash loss approximately 475 million based difference net carrying value ruby estimated fair value investment ruby noncash loss approximately 125 million related recognition accumulated comprehensive loss associated interest rate swaps ruby debt additional information ruby pipeline project see item 8 financial statements supplementary data note 18 asset salewrite downs 2010 pipelines segment ebit impacted following asset writedowns sale 21 million noncash asset writedown third quarter based ferc order related sale natural buttes compressor station gas processing plant 2009 ii impairment approximately 10 million primarily related decision continue storage project due market conditions iii third quarter gain approximately 80 million sale interests certain mexican pipeline compression assets regulatory matters pipeline systems periodically file changes rates subject approval ferc changes rates tariff provisions resulting regulatory proceedings potential positively negatively impact profitability currently several pipelines projected upcoming rate actions described epng rate case september 2010 epng filed new rate case proposing increase base tariff rates would increase revenue approximately 100 million annually previously effective tariff rates october 2010 ferc issued order accepting suspending effective date proposed rates april 1 2011 subject refund outcome hearing proceedings hearing commenced late october 2011 concluded december 2011 decision due may 2012 uncertain whether requested increase achieved context settlement epng customers following outcome hearing rate case although final outcome currently determinable believe accruals established matter adequate tgp rate case december 2011 ferc approved tgp’s settlement resolved outstanding issues arising general rate case filing settlement provides among things increase tgp’s base tariff rates effective june 1 2011 ii implementation cost trackers fuel pipeline safety greenhouse gas iii significant contract extensions october 2014 iv filing requirement next general rate case effective earlier april 2014 later november 2015 v revenue sharing mechanism certain customers certain revenues annual threshold addition part settlement tgp refund approximately 68 million customers march 31 2012 believe accruals established matter adequate cig rate case august 2011 ferc approved uncontested prefiling settlement rate case required terms cig’s previous settlement generally provides cig’s current tariff rates continue next general rate case effective earlier october 1 2014 later october 1 2016 ii contract extensions march 2016 iii revenue sharing mechanism certain customers certain revenues annual threshold amounts iv revenue surcharge mechanism certain customers charge certain shortfalls revenue less annual threshold amount exploration production segment overview strategy exploration production business one north america’s leading independent oil natural gas ngl producers focused generating competitive financial returns disciplined capital allocation portfolio management cost control marketing selling oil natural gas production optimal prices managing associated price risks profitability performance business driven ability locate develop economic oil natural gas reserves extract reserves lowest possible production administrative costs strategy focuses building applying competencies assets repeatable programs maximizing returns adding assets reserves resources match competencies divesting assets executing improve capital expense efficiency domestically operate three divisions central western southern central division includes operations east texas louisiana alabama indiana eastern oklahoma operations western division located uintah basin utah raton basin new mexico colorado southern division located along gulf coast south west areas texas gulf mexico core programs include haynesville shale northwest louisiana east texas altamont fractured tight sands utah eagle ford shale south texas wolfcamp shale located permian basin west texas description core program haynesville operated approximately four rigs area 2011 currently running one rig although efficient drilling program haynesville shale plan shut program due low natural gas prices expect release rigs end first quarter 2012 plan redeploy capital allocated haynesville oil programs altamont area gaining operational efficiencies develop field ran approximately three rigs 2011 currently running two rigs eagle ford eagle ford oil program economic potential portfolio current prices approximately 60 percent acreage liquids rich area shale play currently running four rigs wolfcamp program entered 2010 focused optimizing drilling completion hydraulic fracturing designs artificial lift systems currently running one rig internationally portfolio consists producing fields along exploration development projects offshore brazil exploration projects egypt success international programs brazil egypt require effective project management strong partner relations obtaining approvals regulatory agencies exploration production operations generate profits dependent prices oil natural gas costs explore develop produce oil natural gas volumes able produce among factors longterm profitability primarily influenced following factors • growing oil natural gas proved reserve base production volumes successful execution drilling programs • finding producing oil natural gas reasonable cost • managing price risks optimize realized prices oil natural gas production addition factors future profitability performance affected ability execute strategy impacts volatility financial commodity markets industrywide changes cost drilling oilfield services impact daily production operating capital costs debt level related interest costs additionally may impacted hurricanes weather events domestic international regulatory issues actions outside control eg oil spills extent possible attempt mitigate certain risks actions entering longer term contractual arrangements control costs entering derivative contracts reduce financial impact downward commodity price movements significant operational factors affecting year ended december 31 2011 volumes commodity years ended december 31 follows production average daily production volumes year ended december 31 2011 838 mmcfed including 61 mmcfed equity interest production four star analysis production division years ended december 31 1 2011 gulf coast division renamed southern division made minor changes properties contained within various domestic operating divisions divisional amounts prior periods adjusted reflect changes central division 2011 central division production volumes continued increase result successful drilling programs haynesville shale december 31 2011 108 operated wells total average production 2011 approximately 265 mmcfed addition south louisiana developing emerging wilcox program relatively new oil play added drilling program december 31 2011 14 operated wells related wilcox program western division 2011 western division production volumes decreased compared 2010 due divestitures rockies program natural declines county line program offset increased production volumes altamont raton programs december 31 2011 altamont program 289 net operated wells total oil production approximately 7 mbblsd southern division 2011 southern division production volumes decreased primarily due natural declines lower levels drilling activity texas gulf coast gulf mexico areas division continue focus eagle ford shale activity december 31 2011 total 64 operated wells located principally liquids rich area eagle ford shale 2011 total oil ngl production approximately 5 mbblsd related eagle ford also continue assess wolfcamp shale area drilled 13 wells 2011 international 2011 production volumes brazil increased due production camarupim field fourth well field began production 2011 informed environmental permit request pinauna field camamu basin denied brazilian environmental regulatory agency result released 94 million unevaluated capitalized costs related field brazilian full cost pool filed appeal awaiting response additionally 2011 released approximately 86 million unevaluated capitalized costs related es5 block espirito santo basin upon completion evaluation exploratory wells drilled 2009 2010 without additions proved reserves continue pursue alternatives hydrocarbons discovered areas 2011 due political unrest egypt experienced delay obtaining governmental approval new partner south alamein block postponed drilling south mariut expect matters resolved 2012 continue evaluate commerciality areas december 31 2011 total oil natural gas capitalized costs approximately 205 million 74 million brazil egypt 8 million 74 million unevaluated capitalized costs cash operating costs monitor cash operating costs required produce oil natural gas production volumes cash operating costs nongaap measure calculated per mcfe basis includes total operating expenses less depreciation depletion amortization expense ceiling test impairment charges transportation costs cost products cash operating costs per unit valuable measure operating performance efficiency exploration production segment however measure may comparable used companies year ended december 31 2011 cash operating costs per unit increased slightly 179mcfe compared 178mcfe 2010 increase 2011 per unit basis primarily due higher lease operating expenses production taxes offset higher production volumes reserve replacement ratioreserve replacement costs calculate two primary metrics reserve replacement ratio ii reserve replacement costs measure ability establish longterm trend adding reserves reasonable cost core asset areas reserve replacement ratio indicator ability replenish annual production volumes grow reserves important us economically find develop new reserves offset produced volumes provide future production given inherent decline hydrocarbon reserves addition calculate reserve replacement costs assess cost adding reserves ultimately included depreciation depletion amortization expense believe ability develop competitive advantage oil natural gas companies dependent adding reserves core asset areas lower costs competition calculate metrics follows reserve replacement ratio sum reserve additions1 actual production corresponding period reserve replacement costsmcfe total oil gas capital costs2 sum reserve additions 1 reserve additions include proved reserves reflect reserve revisions prices performance extensions discoveries additions acquisitions include unproved reserve quantities proved reserve additions attributable investments accounted using equity method present metrics separately including excluding impact price revisions reserves demonstrate effectiveness drilling program exclusive economic factors price outside control amounts derived directly table presented item 8 financial statements supplementary data supplemental oil natural gas operations 2 total oil natural gas capital costs include costs development exploration property acquisition activities conducted add reserves exclude asset retirement obligations amounts derived directly table presented item 8 financial statements supplementary data supplemental oil natural gas operations reserve replacement ratio reserve replacement costs per unit statistical indicators limitations including predictive comparative value annual measure reserve replacement ratio limited typically varies widely based extent timing new discoveries project sanctioning property acquisitions addition since reserve replacement ratio consider cost timing developing future production new reserves cannot used measure value creation exploration acquisition development oil natural gas reserves inherently uncertain discussed part item 1a risk factors risks related business one risks uncertainties ability spend sufficient capital increase reserves currently expect spend amounts future assurances timing magnitude expenditures classification proved reserves developed undeveloped december 31 2011 proved developed reserves represent approximately 50 percent total consolidated proved reserves proved developed reserves generally begin producing within year added whereas proved undeveloped reserves generally require additional future expenditures table shows reserve replacement ratio reserve replacement costs domestic worldwide operations including excluding effect price revisions reserves years ended december 31 1 proved property acquisition costs excluded calculations leasehold unproved acquisitions costs included calculations typically cite reserve replacement costs context multiyear trend recognition limitation single year measure also demonstrate consistency stability essential business model table shows reserve replacement costs domestic worldwide operations three years ended december 31 2011 capital expenditures total capital expenditures follows years ended december 31 1 total oil natural gas capital costs include costs development exploration property acquisition activities conducted add reserves exclude asset retirement obligations capital expenditures average rig count core program year ended december 31 2011 price risk management activities enter derivative contracts oil natural gas production primarily stabilize cash flows reduce risk financial impact downward commodity price movements commodity sales apply marktomarket accounting financial derivative contracts hedge price risks strategy partially reduces commodity price exposure reported results operations financial position cash flows impacted significantly commodity price movements period adjustments strategy decision enter new positions alter existing positions made based goals overall company 2011 approximately 80 percent natural gas production 95 percent crude oil production economically hedged average floor prices 583 per mmbtu 8599 per barrel respectively following table reflects contracted volumes minimum maximum average prices receive derivative contracts december 31 2011 1 volumes presented tbtu natural gas mbbl oil prices presented per mmbtu natural gas per bbl oil 2 market prices settle 6754 7500 years 2012 2013 respectively threeway collarsfloors effectively “lockin” cash settlement market price plus 2500 per bbl 2012 2013 operating results variance analysis information provides financial results analysis significant variances results periods ended december 31 1 includes 11 million 11 million 406 million years ended december 31 2011 2010 2009 reclassified accumulated comprehensive income associated accounting hedges 2 income expense includes equity earnings four star unconsolidated affiliate net amortization purchase cost excess equity interest underlying net assets table provides additional detail volumes prices costs per unit present average realized prices based physical sales oil condensate natural gas ngl well ii average realized prices inclusive impacts financial derivative settlements average realized prices including financial derivative settlements reflect cash received andor paid period settled financial derivatives based period contracted settlements originally scheduled occur however prices reflect impact associated premiums paid enter certain derivative contracts 1 cash premiums related oil derivatives settled years ended december 31 2011 2010 2009 premiums paid 2009 related natural gas derivatives settled year ended december 31 2010 157 million premiums paid related natural gas derivatives settled year ended december 31 2011 23 million included premiums natural gas average realized prices 2010 2011 realized price including financial derivative settlements would decreased 070mcf 010mcf years ended december 31 2010 2011 2 years ended december 31 2011 2010 2009 include approximately 338 million 306 million 834 million cash receipts settlement natural gas derivative contracts years ended december 31 2011 2010 include approximately 7 million 8 million cash paid settlement crude oil derivative contracts additionally year ended december 31 2009 includes approximately 176 million cash receipts settlement crude oil derivative contracts 3 production taxes include ad valorem severance taxes 4 includes 005 per mcfe year ended december 31 2011 006 per mcfe years ended december 31 2010 2009 related accretion expense asset retirement obligations year ended december 31 2011 compared year ended december 31 2010 segment ebit 2011 decreased 233 million compared 2010 table shows significant variances financial results 2011 compared 2010 physical sales physical sales represent accrualbased commodity sales transactions customers 2011 revenues increased compared 2010 due primarily higher oil natural gas volumes higher oil condensate prices partially offset lower natural gas prices higher volumes due focus core programs haynesville eagle ford shales realized unrealized gains financial derivatives year ended december 31 2011 recognized net gains 284 million compared net gains 390 million 2010 gains losses period due changes fair value derivative contracts based forward commodity prices relative prices underlying contracts depreciation depletion amortization expense year ended december 31 2011 depreciation depletion amortization expense increased result higher depletion rate higher production volumes compared period 2010 depreciation depletion amortization rate increased 2011 focused capital oil programs production costs production costs increased 2011 compared 2010 primarily due higher lease operating expenses higher production taxes mainly associated higher volumes lease operating expenses increased due higher maintenance repair power costs western division temporary higher costs southern division due early well testing higher expenses international division general administrative expenses general administrative expenses increased 2011 compared period 2010 due severance costs related office closure higher employee benefit costs ceiling test charges required conduct quarterly impairment tests capitalized costs full cost pools year ended december 31 2011 recorded noncash ceiling test charge approximately 152 million brazilian full cost pool ceiling test charge driven release costs brazilian full cost pool substantially due denial necessary environmental permit pinauna project well completion evaluation certain exploratory wells drilled 2009 2010 filed appeal regard denial permit awaiting response year ended december 31 2010 recorded noncash ceiling test charges 25 million egyptian full cost pool result acreage relinquishments south mariut south alamein dry hole drilled tanta block may incur additional ceiling test charges brazil future depending value proved reserves subject change result factors prices costs well performance future may incur ceiling test charges egypt depending results activities country due political unrest egypt 2011 experienced delay governmental approval new partner south alamein block postponed drilling south mariut expect matters resolved 2012 continue evaluate commerciality areas current natural gas prices significantly 12month average price used determine domestic proved reserves december 31 2011 sustained period low domestic natural gas prices time result downward revision proved reserves corresponding reduction discounted future net cash flows proved reserves could result ceiling test charges domestic full cost pool addition fair value investment four star could decline result lower natural gas prices may required record impairment carrying value future year ended december 31 2010 compared year ended december 31 2009 segment ebit 2010 increased 21 billion compared 2009 table shows significant variances financial results 2010 compared 2009 physical sales physical sales represent accrualbased commodity sales transactions customers 2010 revenues increased compared 2009 due primarily higher commodity prices year ended december 31 2010 also benefited increase production volumes central western divisions brazil realized unrealized gains financial derivatives year ended december 31 2010 recognized net gains 390 million compared net gains 687 million 2009 gains losses period based movements forward commodity prices relative prices underlying financial derivative contracts depreciation depletion amortization expense year ended december 31 2010 depreciation depletion amortization expense increased compared period 2009 result higher depletion rate higher production volumes year ended december 31 2009 depletion rate largely impacted ceiling test charges recorded first quarter 2009 production costs production costs increased 2010 compared 2009 primarily due higher production taxes increased due higher oil natural gas revenues general administrative expenses general administrative expenses decreased 2010 compared period 2009 primarily due lower payroll administrative costs support business following reorganizations 2009 ceiling test charges year ended december 31 2010 recorded noncash ceiling test charges 25 million egyptian full cost pool result contractual acreage relinquishments blocks dry hole drilled tanta block year ended december 31 2009 recorded noncash ceiling test charges 21 billion domestic brazilian full cost pools result low oil natural gas prices egyptian full cost pool result dry hole costs equity earnings four star 2010 increased 23 million compared 2009 primarily due impact higher commodity prices partially offset lower production volumes marketing segment marketing segment’s primary focus market exploration production segment’s oil natural gas production manage el paso’s overall price risk including legacy contracts primarily entered prior deterioration energy trading environment 2002 segment also agreements midstream joint venture market natural gas natural gas liquids production utah operations contracts subject counterparty credit nonperformance risks remaining marktomarket contracts also subject interest rate exposure revenues marketing activities recorded net related costs natural gas transportationrelated contracts impact accrualbased transportation contracts based ability use remarket contracted pipeline capacity amount production exploration production segment december 31 2011 contracts require us pay demand charges 56 million 2012 average 31 million per year 2013 2016 legacy natural gas power contracts december 31 2011 contracts include longterm accrual based supply contracts including transportation expenses obligate us deliver natural gas specified power plants ii power contracts pjm region 2016 marktomarket results contracts expected minimal future earnings impact us entered offsetting positions eliminate price risks associated pjm power contracts substantially offset fixed price exposure related natural gas supply contracts operating results overview overall operating results analysis marketing segment three years ended december 31 follows year ended december 31 2011 demand charges increased primarily due increases transport tariff rates existing contracts recorded 22 million loss settlement affiliated fuel supply agreement terminated june 2011 reflected component settlements net termination payments accrualbased contracts years ended december 31 2011 2010 2009 results also impacted changes fair value legacy power contracts pjm end 2010 entered contracts eliminated price risks associated pjm power contracts based actions changes fair value legacy power contracts occuring 2011 primarily result changes interest rates credit risk items may also impact future earnings related contracts 2009 recorded 52 million marktomarket gain related adoption new accounting requirements derivative liabilities associated noncash collateral eg letters credit partially offset 27 million loss related impact el paso’s credit standing derivative liabilities activities include midstream operations discussed part item 1 business corporate general administrative functions miscellaneous businesses following summary significant items impacting segment ebit activities three years ended december 31 loss debt extinguishment 2011 2010 incurred losses primarily related repurchase exchange approximately 10 billion 11 billion senior unsecured notes environmental legal reserves number pending litigation matters reserves related historical business operations affect results adverse rulings unfavorable outcomes settlements us related matters impacted may continue impact future results periods presented primarily impacted adjustments certain legacy environmental matters including nonoperated chemical plant nonoperated refinery south texas also impacting results adjustments certain legacy indemnifications including indemnification liability fluctuates ammonia prices midstream december 2010 recorded gain 110 million conjunction sale 50 percent interest new midstream joint venture comprised altamont gathering processing midstream assets 125 million cash 50 percent interest operate joint venture accounted equity investment net earnings losses related legacy investments equity investments receivables related legacy foreign power telecommunications operations certain impacted foreign currency fluctuations 2011 results also impacted 16 million gain sale remaining interest telecommunications equity investment 2009 results impacted 22 million loss associated sale notes receivable related legacy power investment results impacted items including benefit costs associated certain postretirement benefit plans 2011 results also impacted 20 million costs associated previously announced spinoff exploration production operations costs related anticipated merger kinder morgan 2010 results impacted 40 million income due receipt funds previously escrowed expensed conjunction coastal corporation merger 2001 interest debt expense interest debt expense years ended december 31 2011 2010 2009 09 billion 10 billion 10 billion interest debt expense decreased year ended december 31 2011 compared 2010 primarily associated exchange repurchase approximately 21 billion debt 2010 2011 rates 6875 percent 12 percent interest savings associated transactions partially offset interest costs new borrowings interest debt expense flat 2010 compared 2009 primarily due increases ruby pipeline project financings net higher afudc debt associated ruby project additionally 2010 impacted changes estimates allowance funds used construction increase interest rate 7 percent 13 percent ruby term loan income taxes negative effective tax rate year ended december 31 2011 reflects impact low level pretax income ii 71 million deferred state tax benefit recorded upon conversion subsidiary limited liability company reduced state effective tax rates iii favorable resolution certain tax matters partially offsetting items 53 million tax impact brazilian ceiling test charge without corresponding us brazilian tax benefit deferred brazilian tax benefits offset equal valuation allowance absent items effective tax rate year ended december 31 2011 would 24 percent well statutory rate due income attributable nontaxable noncontrolling interests discussion effective tax rate refer item 8 financial statements supplementary data note 5 commitments contingencies discussion commitments contingencies see item 8 financial statements supplementary data note 12 liquidity capital resources overview primary sources cash include cash flow operations funds obtained long term financings including capital market activities eg executing financings utilizing master limited partnership bank credit facilities also generate cash project financings asset sales warranted typically rely shortterm borrowings fulfill liquidity needs primary uses cash funding capital expenditures meeting operating needs paying distributions dividends repaying debt due repurchasing debt conditions warrant 2011 completed remainder 8 billion backlog expansion projects largest company’s history continuing support exploration production program july 2011 placed ruby pipeline project service upon making certain permitting representations meeting certain conditions el paso’s guarantee gip’s 700 million investment ruby cheyenne plains entity owns cheyenne plains pipeline expired ruby project financing obligations became nonrecourse us result deconsolidated ruby description project agreement gip see item 8 financial statements supplementary data note 18 available liquidity december 31 2011 approximately 09 billion available liquidity exclusive cash credit facility capacity epb 2011 generated operating cash flow approximately 21 billion ii spent approximately 38 billion primarily capital programs iii refinanced approximately 325 billion revolving credit facilities extend maturities 2016 iv received approximately 14 billion cash conjunction contributing additional ownership interests sng cig mlp funded acquisitions primarily issuance common units debt july 2011 500 million unsecured credit facility matured december 2011 allowed 300 million ep energy corporation epe borrowing base credit facility mature pursuant merger agreement kmi subject certain conditions restrictions thresholds including ability refinance incur new debt issue el paso capital stock andor dispose material properties assets equity interests prescribed merger agreement however result current available liquidity hedging program place oil natural gas production expect current liquidity sources operating cash flow sufficient fund working capital requirements estimated 2012 capital expenditures approximately 362 million 2012 debt maturities continue assess take actions prudent ordinary course business meet capital requirements well address changes financial commodity markets however number factors could impact future plans including limited completion proposed merger kmi decline commodity prices events occur fail occur additional adjustments plan may required including reductions discretionary capital program reductions operating general administrative expenses could impact financial operating performance overview 2011 cash flow activities 2011 generated operating cash flow approximately 21 billion primarily pipeline exploration production operations also generated approximately 07 billion asset sales primarily noncore oil natural gas properties ii approximately 09 billion result issuance mlp common units iii approximately 59 billion issuance debt borrowings revolving credit facilities utilized amounts fund capital programs including completing ruby project july 2011 investments repay amounts outstanding various credit facilities debt obligations pay common preferred dividends distributions mlp unitholders holders subsidiary preferred stock among items description ruby see item 8 financial statements supplementary data notes 11 18 year ended december 31 2011 2010 cash flows operations summarized follows offbalance sheet arrangements enter variety financing arrangements contractual obligations referred offbalance sheet arrangements include guarantees letters credit interests variable interest entities guarantees indemnifications involved joint ventures ownership arrangements sometimes require financial performance guarantees financial guarantee obligated make payments guaranteed party fails make payments violates terms financial arrangement performance guarantee provide assurance guaranteed party execute terms contract required perform behalf also periodically provide indemnification arrangements related assets businesses sold arrangements include limited indemnifications income taxes resolution existing disputes environmental matters potential exposure guarantee indemnification agreements range specified unlimited dollar amount depending nature claim particular transaction many agreements may specify maximum potential exposure specified duration indemnification obligation circumstances amount duration unlimited arrangements specified dollar amount maximum stated value approximately 710 million comprised 438 million indemnification associated sale anr 120 million indemnification associated sale macae power facility brazil 152 million indemnifications guarantees related sale legacy assets fourth quarter 2011 received full claim macae indemnification matters believe specifically excluded scope indemnification amounts exclude guarantees issued related letters credit discussed included maximum stated value certain indemnification agreements expired however claims made prior expiration related claim periods unable estimate maximum exposure guarantee indemnification agreements provide limits amount future payments due uncertainty exposures december 31 2011 recorded obligations 15 million related guarantee indemnification arrangements liability consists primarily indemnification one subsidiaries provided related sale ammonia facility reflected financial statements fair value provided partial parental guarantee subsidiary’s obligations indemnification letters credit enter letters credit ordinary course operations well periodically conjunction sales assets businesses december 31 2011 outstanding letters credit surety bonds approximately 06 billion including 03 billion letters credit securing recorded obligations related price risk management activities additional information counterparty credit nonperformance risk see item 8 financial statements supplementary data note 7 depending changes commodity prices interest rates could required post additional margin may recover margin earlier anticipated 10 percent change natural gas power prices would significant impact margin requirements derivative contracts december 31 2011 interests variable interest entities interests variable interest entities legal entities whose equity owners sufficient equity risk characteristics controlling financial interest entities required consolidate entities ability control direct operating financial decisions activities significant entity december 31 2011 significant variable interest entities contractual obligations party various contractual obligations include offbalance sheet arrangements described portion obligations reflected financial statements longterm debt liabilities commoditybased derivative contracts accrued liabilities obligations demand charges transportation storage commitments operating leases capital commitments contractual interest amounts reflected balance sheet following table discussion summarizes contractual cash obligations december 31 2011 periods presented longterm financing obligations principal interest debt obligations included table represent stated maturities interest payments shown stated maturity date related debt based contractual interest rate fixed rate debt ii current market interest rates contractual credit spread variable rate debt discussion debt obligations see item 8 financial statements supplementary data note 11 liabilities price risk management activities amounts include fair value price risk management liabilities fair value price risk management assets 302 million december 31 2011 reflected amounts also excluded margin deposits held associated contracts amounts net derivative assets liabilities counterparties legal right offset discussion price risk management activities see item 8 financial statements supplementary data note 7 contractual liabilities included amount contractual environmental obligations included current noncurrent liabilities balance sheet excluded amounts expected contributions pension postretirement benefit plans expected contributions fixed time amount information expected contributions pension post retirement benefit plans see item 8 financial statements supplementary data note 13 also excluded amounts liabilities unrecognized tax benefits 266 million december 31 2011 since cannot reasonably estimate time frame amounts may resolved operating leases discussion obligations see item 8 financial statements supplementary data note 12 contractual commitments purchase obligations contractual commitments purchase obligations defined legally enforceable agreements purchase goods services fixed minimum quantities fixed minimum variable price provisions detail approximate timing underlying obligations included following • transportation storage commitments included amounts commitments demand charges firm access natural gas transportation storage capacity • commitments included amounts commitments purchasing pipe related assets pipeline operations commitments drilling seismic activities exploration production operations various maintenance engineering procurement construction contracts well service license agreements used operations also included longterm commitments us related right way payments discussed item 8 financial statements supplementary data note 12 excluded asset retirement obligations reserves litigation environmental remediation selfinsurance claims disclosed liabilities contractually fixed timing amount critical accounting estimates significant accounting policies described note 1 consolidated financial statements included item 8 annual report form 10k preparation financial statements conformity generally accepted accounting principles requires management select appropriate accounting estimates make estimates assumptions affect reported amount assets liabilities revenue expenses disclosures contingent assets liabilities consider critical accounting estimates require difficult complex subjective judgment necessary accounting inherently uncertain matters could significantly influence financial results based changes judgments changes facts circumstances may result revised estimates actual results may differ materially estimates discussed development selection following critical accounting estimates related disclosures audit committee board directors accounting oil natural gas producing activities estimates proved reserves reflect quantities oil natural gas ngl geological engineering data demonstrate reasonable certainty recoverable future years known reservoirs existing economic conditions process estimating oil natural gas reserves complex requiring significant judgment evaluation available geological geophysical engineering economic data proved reserves estimated property level compiled reporting purposes centralized group experienced reservoir engineers work closely operating groups engineers interact engineering geoscience personnel operating areas accounting marketing personnel obtain necessary data projecting future production costs net revenues ultimate recoverable reserves reviewed internally senior management quarterly presented board directors summary form annual basis additionally annual basis property reviewed detail centralized operating divisional engineers ensure forecasts operating expenses netback prices production trends development timing reasonable proved reserves also reviewed internal committees processes controls used estimating proved reserves reviewed internal auditors addition thirdparty reservoir engineering firm appointed reports audit committee board directors conducts audit estimates significant portion proved reserves particular ryder scott company lp conducted audit estimates proved reserves december 31 2011 december 31 2011 total consolidated proved reserves 50 percent undeveloped 49 percent including four star 9 percent developed nonproducing data given field may change substantially time result numerous factors including additional development activity evolving production history continual reassessment viability production changing economic conditions result material revisions existing reserve estimates occur time addition subjective decisions variances available data various fields increase likelihood significant changes estimates proved oil natural gas reserves primarily impact property plant equipment amounts balance sheets depreciation depletion amortization amounts ceiling test charges income statements among items use full cost method account oil natural gas producing activities accounting method capitalize substantially costs incurred connection acquisition exploration development oil natural gas reserves including salaries benefits internal costs directly related finding activities asset retirement costs capitalized interest capitalized costs maintained full cost pools geographic area regardless whether reserves actually discovered record depletion expense capitalized amounts plus estimated finding development costs life proved reserves based unit production method factors held constant 10 percent increase estimated proved reserves would decrease unit production depletion rate 9 percent 10 percent decrease estimated proved reserves would increase unit depletion rate 11 percent information regarding price sensitivities related estimated proved reserves see part item 1 business oil natural gas properties oil natural gas properties include unproved property costs excluded costs depleted unproved property costs include nonproducing leasehold geological geophysical costs associated unevaluated leasehold drilling interests exploration drilling costs investments unproved properties major development projects direct interest exclude costs countrybycountry basis proved reserves found determined costs impaired costs excluded reviewed least quarterly determine exclusion fullcost pool continues appropriate costs determined impaired amount impairment transferred full cost pool reserve base exists expensed reserve base yet created impairments transferred full cost pool increase depletion rate country discussion costs country see part ii item 8 financial statements supplementary data supplemental oil natural gas operations full cost accounting method oil natural gas properties required conduct quarterly impairment tests capitalized costs full cost pools impairment test referred ceiling test total capitalized costs net related deferred income taxes limited ceiling based present value future net revenues proved reserves less estimated future capital expenditures discounted 10 percent plus cost unproved oil natural gas properties amortized less related income tax effects required use first day 12month average price calculating ceiling test estimating proved reserves discounted future net cash flows greater equal total capitalized costs required writedown capitalized costs level discounted future net cash flows costbased regulation account regulated operations accordance current financial accounting standard board fasb accounting standards rateregulated operations economic effects regulation result regulated company recording assets costs expected approved recovery customers recording liabilities amounts expected returned customers ratesetting process period different period amounts would recorded unregulated enterprise accordingly record assets liabilities result regulated ratemaking process would recorded gaap nonregulated entities management regularly assesses whether regulatory assets probable future recovery regulatory liabilities probable refunded customers considering factors applicable regulatory changes recent rate orders applicable regulated entities based continual assessment management believes existing regulatory assets probable recovery periodically evaluate applicability accounting standards related regulated operations consider factors regulatory changes impact competition costbased regulation ends competition increases may evaluate assets impairment writeoff associated regulatory assets accounting environmental legal reserves guarantees indemnifications accrue environmental legal reserves assessments indicate probable liability incurred amount reasonably estimated estimates liabilities based evaluation potential outcomes currently available facts case environmental reserves existing technology presently enacted laws regulations taking consideration likely effects societal economic factors estimates associated onsite offsite groundwater technical studies legal costs actual results may differ estimates often revised future either negatively positively depending upon actual outcomes changes expectations based facts surrounding matter december 31 2011 accrued approximately 38 million outstanding legal proceedings approximately 181 million environmental matters reduced 18 million amounts paid directly government sponsored programs settlement arrangements environmental estimates range approximately 181 million approximately 321 million lower end expected range accrued also guarantee indemnification agreements related various joint ventures ownership arrangements require us assess potential exposure range specified amount unlimited dollar amount depending nature claim particular transaction arrangements specified dollar amount maximum stated value approximately 07 billion december 31 2011 recorded obligations 15 million related guarantee indemnification arrangements unable estimate maximum exposure guarantee indemnification agreements provide limits amount future payments agreement due uncertainty exposures information see balance sheet arrangements accounting pension postretirement benefits reflect asset liability pension postretirement benefit plans based funded status december 31 2011 pension plans funded 418 million postretirement benefit plans funded 321 million pension postretirement benefit obligations net benefit costs primarily based actuarial calculations use various assumptions performing calculations including related return expect earn plan assets rate expect compensation employees increase plan term estimated cost health care benefits provided plans factors significant assumption utilize discount rates used calculating benefit obligations select discount rates matching timing amount expected future benefit payments pension postretirement benefit obligations average yields various highquality bonds corresponding maturities actual results may differ assumptions included calculations result estimates associated pension postretirement benefits often revised future income statement impact changes assumptions related benefit obligations along changes plans items deferred amortized income either period expected future service active participants expected future lives inactive plan participants record deferred amounts either accumulated comprehensive income loss regulatory asset liability certain regulated operations december 31 2011 deferred net losses approximately 751 million net income taxes accumulated comprehensive income related pension postretirement benefits following table shows impact one percent change primary assumptions used actuarial calculations associated pension postretirement benefits year ended december 31 2011 millions 1 actual return plan assets one percent lower expected return plan assets expected cash contributions pension postretirement benefit plans would change significantly estimates net benefit expense income partially based expected return pension plan assets use marketrelated value plan assets determine expected return pension plan assets determining marketrelated value plan assets differences expected actual asset returns deferred three years considered fully recognized purposes determining net benefit expense income used fair value plan assets instead marketrelated value plan assets determining expected return pension plan assets net benefit expense would 25 million lower year ended december 31 2011 price risk management activities record derivative instruments used price risk management activities fair values estimate fair value derivative instruments using exchange prices thirdparty pricing data valuation techniques incorporate specific contractual terms statistical simulation analysis present value concepts one primary assumptions used estimate fair value derivative instruments pricing assumptions based upon price curves derived actual prices observed market pricing information supplied thirdparty valuation specialist independent pricing sources models rely forward pricing information extent rely pricing information received third parties developing assumptions based part whether information considers availability observable data marketplace example relatively illiquid markets may make adjustments pricing information receive third parties based evaluation whether third party market participants would use pricing assumptions consistent sources table presents hypothetical sensitivity commoditybased price risk management activities changes fair values arising immediate selected potential changes natural gas oil power prices december 31 2011 another significant assumption discount rates use determining fair value derivative instruments table presents hypothetical sensitivity commoditybased price risk management activities changes fair values arising changes discount rates used determine fair value derivatives december 31 2011 significant assumptions use determining fair value derivative instruments related anticipated market liquidity credit nonperformance risk counterparties adjust fair value derivative assets risk nonperformance counterparties considering collateral posted derivative changes counterparties’ creditworthiness part based changes bond yields changes actively traded credit default swap prices available information credit standing adjust fair value derivative liabilities creditworthiness utilizing similar inputs considering cash collateral posted counterparties table presents hypothetical sensitivity commoditybased price risk management activities changes fair values arising potential changes credit risk december 31 2011 deferred taxes uncertain income tax positions record deferred income tax assets liabilities reflecting tax consequences deferred future periods based differences financial statement carrying value assets liabilities tax basis assets liabilities additionally deferred tax assets liabilities reflect assessment tax positions taken resulting tax basis reflect conclusions positions likely sustained audited taxing authorities significant judgments tax related matters include limited items noted matters involve exercise significant judgment could change materially impact financial condition results operations discussion items income tax matters see item 8 financial statements supplementary data note 5 valuation allowance realization deferred tax assets depends recognition sufficient future taxable income specific tax jurisdictions periods temporary differences deductible valuation allowances established necessary reduce deferred income tax assets amounts believe likely recovered evaluating valuation allowance consider existence taxable income prior carryback years reversal existing temporary differences tax planning strategies future taxable income taxable jurisdictions latter involves exercise significant judgment changes valuation allowance could materially impact results operations uncertain tax positions liabilities unrecognized tax benefits related uncertain tax positions connected ongoing examinations open tax years changes assessment liabilities may require us increase liability record additional tax expense reverse liability recognize tax benefit would positively negatively impact effective tax rate undistributed earnings foreign investees certain unconsolidated affiliates record deferred tax liabilities undistributed earnings foreign investments anticipate earnings repatriated plan repatriate foreign undistributed earnings provision made us taxes foreign withholding taxes changes repatriation assumptions including repatriation proceeds sales investments could require us record additional deferred taxes additionally believe certain unconsolidated affiliates’ undistributed earnings ultimately distributed us dividends would eligible dividends received deduction joint venture partners intent ability recover cumulative undistributed earnings time dividends structured sale would result additional deferred tax liabilities asset investment impairments accounting rules asset investment impairments require us continually monitor businesses business environment performance investments determine event occurred indicates longlived asset investment may impaired event occurs determination involves judgment may required estimate fair value asset estimate considers number factors including potential value would receive sold asset projected cash flows asset based current anticipated future market conditions discount rates assessment fair value including limited estimates project level cash flows requires significant judgment make projections assumptions believe market participant would use pricing demand competition operating costs legal regulatory issues factors extend many years future often outside control due imprecise nature projections assumptions actual results often differ estimates utilize cash flow projections assess ability recover carrying value assets investments based either longlived assets’ ability generate future cash flows undiscounted basis ii fair value investments unconsolidated affiliates whether decline fair value carrying amount considered temporary impairment indicated record impairment charge excess carrying value asset fair value years ended december 31 2011 2010 2009 recorded impairments 7 million 10 million 30 million related longlived assets 2011 connection deconsolidation ruby also recorded noncash loss approximately 475 million based difference net carrying value ruby estimated fair value investment ruby recorded noncash loss 125 million related recognition accumulated comprehensive loss associated interest rate swaps ruby’s debt discussion ruby pipeline project see item 8 financial statements supplementary data note 18 future changes economic business environment impact assessments potential impairments principles consolidation entities third parties equity interests perform evaluation determine party consolidate entity part evaluation required determine whether entity considered variable interest entity vie ultimately party considered primary beneficiary andor controls entity’s operating financial decisions part evaluations significant amount judgment involved evaluating entities’ contractual relationships relative nature third party’s interests entities ability control direct activities different judgment applied accounting treatment financial statement presentation entities could significantly impacted discussion significant investments unconsolidated affiliates december 31 2011 see item 8 financial statements supplementary data note 18 item 7a item 7a quantitative qualitative disclosures market risk company utilizes derivative financial instruments manage market risks associated certain energy commodities interest foreign currency exchange rates companys primary market risk exposure changing commodity prices market risks monitored corporate risk management committee operates independently business segments create actively manage risk exposures ensure compliance companys stated risk management policies approved board policies set forth item 8 financial statements supplementary data note 1 trading commodity price risk epem exposed certain market risks inherent financial instruments entered trading purposes associated natural gas power petroleum products epem marks market energy trading activities including transportation capacity storage epems policy manage commodity price risks variety financial instruments including forward contracts involving cash settlements physical delivery energy commodity swap contracts require payment receipts counterparties based differential fixed variable price commodity exchangetraded options overthecounter options contractual arrangements epem manages markets risk portfolio basis subject parameters established risk management committee comprehensive risk management processes policies procedures established monitor control market risk companys risk management committee also continually reviews policies ensure responsive changing business conditions epem measures risk commodity energy related contract portfolio daily basis utilizing valueatrisk var model determine maximum potential oneday unfavorable impact earnings existing portfolio due normal market movements monitors risk comparison established thresholds var computations based historical simulation utilizes price movements specified period simulate forward price curves energy markets several key assumptions including selection confidence level expected losses holding period liquidation epem also utilizes measures outside var methodology monitor risk commodity energy related contract portfolio monthly basis including stress testing position limit control credit liquidity event risk management epem previously utilized sensitivity analysis report market risk based ten percent change commodity prices uncertainty market place increased trading derivative instruments complexity instruments created demand comprehensive portfolio level quantitative measure market risk accordingly epem converted utilizing sensitivity analysis var model 1998 assuming confidence level 95 percent oneday holding period epems estimated potential oneday unfavorable impact income taxes minority interest measured var related commodity energy related contracts held trading purposes approximately 3 million 2 million december 31 1998 1997 respectively var implemented april 1 1998 therefore volatilities correlations applicable april 1 1998 used provide comparative data december 31 1997 actual losses could exceed measured var nontrading commodity price risk estimated potential oneday unfavorable impact income taxes minority interest measured var related epems nontrading commodity activities immaterial december 31 1998 1997 interest rate risk companys debt financial instruments sensitive market fluctuations interest rates table presents principal cash flows related weighted average interest rates expected maturity dates december 31 1998 1997 carrying amounts shortterm borrowings representative fair values shortterm maturity instruments fair value longterm debt estimated based quoted market prices similar issues companys nontrading derivative financial instruments including interest rate equity swaps also sensitive market fluctuations interest rates interest rate swap agreements entered mpc effectively convert 114 million floatingrate debt fixedrate debt see item 8 financial statements supplementary data note 4 mpc makes payments counterparties fixed rates return receives payments floating rates two swap agreements entered march 1992 remaining terms approximately 1 year 3 years respectively transaction recorded using accrual accounting addition march 1997 company purchased 105 percent interest capsa approximately 57 million connection acquisition company entered equity swap transaction associated additional 185 percent capsas outstanding stock equity swap company pays interest counterparty quarterly basis notional amount 100 million rate libor plus 085 percent exchange company receives dividends capsa stock extent counterpartys equity interest 185 percent february 1999 company extended term swap two half years interest rate equity swaps table presents notional amounts weighted average interest rates expected contractual maturity dates notional amounts used calculate contractual payments exchanged contact fair value derivative financial instruments estimated amount management believes could liquidated reasonable period time based quoted market prices current market conditions estimates obtained thirdparty dealers tabular presentation related activities commodity trading december 31 1998 1997 illustrated variable rates presented average forward rates remaining term contract b company receives dividends extent paid capsa stock extent counterpartys equity interest 185 percent dividends received 1998 dividends expected 1999 item 8item 7a quantitative qualitative disclosures market risk company utilizes derivative financial instruments manage market risks associated certain energy commodities interest foreign currency exchange rates companys primary market risk exposure changing energy commodity prices market risks monitored corporate risk management committee operates independently business segments create actively manage risk exposures ensure compliance companys stated risk management policies approved board trading commodity price risk merchant energy exposed certain market risks inherent financial instruments used trading energy related commodities merchant energy marks market energy trading activities including transportation capacity storage merchant energys policy manage commodity price risks variety financial instruments including exchangetraded futures contracts involving cash settlements forward contracts involving cash settlements physical delivery energy commodity swap contracts require payment receipts counterparties based differential fixed variable prices commodity exchangetraded options overthecounter options contractual arrangements merchant energy manages market risk portfolio basis subject parameters established risk management committee comprehensive risk management processes policies procedures established monitor control market risk companys risk management committee also continually reviews policies ensure responsive changing business conditions merchant energy measures risk commodity energy related contract portfolio daily basis utilizing valueatrisk var model determine maximum potential oneday unfavorable impact earnings existing portfolio due normal market movements monitors risk comparison established thresholds var computations based historical simulation deltagamma positions capture significant portion exposure related option positions utilize price movements specified period simulate forward price curves energy markets using several key assumptions including selection confidence level expected losses holding period liquidation merchant energy also utilizes measures outside var methodology monitor risk portfolio monthly basis including stress testing position limit control credit liquidity event risk management assuming confidence level 95 percent oneday holding period merchant energys estimated potential oneday unfavorable impact income taxes minority interest measured var related contracts held trading purposes approximately 3 million 3 million 1 million december 31 1999 1998 1997 respectively 1999 merchant energys highest lowest average estimated potential one day unfavorable impact income taxes minority interest measured var 3 million 1 million 2 million respectively average value represents twelve month average 1999 month end values high low valuations represent highest lowest month end values 1999 var implemented april 1 1998 therefore volatilities correlations applicable april 1 1998 used provide comparative data december 31 1997 actual losses could exceed measured var nontrading commodity price risk company mitigates market risk associated significant physical transactions including crude oil natural gas liquids production delivery use nontrading financial instruments including forward contracts swaps addition merchant energy functions agent production field services hedging portion commodity risk entering derivative financial instruments third parties estimated potential oneday unfavorable impact income taxes minority interest measured var related merchant energys nontrading commodity activities insignificant december 31 1999 1998 1997 interest rate risk companys debt financial instruments certain project arrangements sensitive market fluctuations interest rates company attempts mitigate exposure risks use nontrading derivative financial instruments including interest rate equity swaps august 1999 el paso entered interest rate swap agreement notional amount 600 million termination date july 2001 el paso swapped fixed interest rate july 1999 600 million aggregate principal senior notes due 2001 floating 3 month libor plus rate margin 1475 basis points transaction recorded using accrual accounting december 31 1998 company maintained interest rate swap debt held mpc october 1999 swap terminated cost approximately 5 million march 1997 company purchased 105 percent interest capsa approximately 57 million connection acquisition company entered equity swap associated additional 185 percent capsas outstanding stock equity swap company pays interest counterparty quarterly basis notional amount 100 million rate libor plus 085 basis points exchange company receives dividends capsa stock extent counterpartys equity interest 185 percent company also fully participates market appreciation depreciation underlying investment whereby company realize appreciation fund depreciation attributable actual sale stock upon termination expiration swap transaction february 1999 company extended term swap two half years notional amount 103 million interest rate libor plus 175 basis points table presents principal cash flows related weighted average interest rates expected maturity dates december 31 1999 carrying amounts shortterm borrowings representative fair values shortterm maturity instruments fair value longterm debt estimated based quoted market prices similar issues interest rate equity swaps notional amounts weighted average interest rates presented expected contractual maturity dates notional amounts used calculate contractual payments exchanged contact fair value derivative financial instruments estimated amount management believes could liquidated reasonable period time based quoted market prices current market conditions estimates obtained thirdparty dealers athe variable rates presented average forward rates remaining term contract bthe company receives dividends extent paid capsa stock extent counterpartys equity interest 185 percent dividends received 1998 1999 dividends expected 2000 2001 cthe difference cash flow based average interest rates annual cash flow shown result timing differences receipt payment interest dthe company realize appreciation fund depreciation attributable actual sale capsa stock upon termination swap transaction august 2001 foreign currency exchange rate risk company uses derivative financial instruments principally foreign currency forward purchase sale contracts various terms manage exposures changes foreign currency exchange rates companys primary exposure relates changes foreign currency rates certain merchant activities outside united states following table summarizes major currency notional amounts average settlement rates fair value foreign currency forward purchase sale contracts december 31 1999 following table summarizes foreign currency forward purchase sale contracts expected maturity dates along annual anticipated cash flow impacts december 31 1999 item 8item 7a quantitative qualitative disclosures market risk utilize derivative financial instruments manage market risks associated energy commodities interest foreign currency exchange rates market risks monitored corporate risk management committee operates independently business segments create actively manage risk exposures ensure compliance overall stated risk management policies approved board directors trading commodity price risk merchant energy segment exposed market risks inherent financial instruments uses trading energy related commodities merchant energy records energy trading activities including transportation capacity storage fair value changes fair value reflected income statement merchant energys policy manage commodity price risks variety financial instruments including exchangetraded futures contracts involving cash settlements forward contracts involving cash settlements physical delivery energy commodity swap contracts require payment receipts counterparties based difference fixed variable prices commodity exchangetraded overthecounter options contractual arrangements merchant energy manages market risk subject parameters established corporate risk management committee comprehensive risk management processes policies procedures established monitor control market risk management committee also continually reviews policies ensure responsive changing business conditions merchant energy measures risk commodity energy related contracts daily basis utilizing valueatrisk model determine maximum potential oneday unfavorable impact earnings due normal market movements monitors risk comparison established thresholds valueatrisk computations capture significant portion exposure related option positions utilize historical price movements specified period project future price movements energy markets merchant energy also utilizes measures provide additional assurance risks commodity energy related contracts properly monitored daily basis including sensitivity analysis position limit control credit risk management based confidence level 95 percent oneday holding period merchant energys estimated potential oneday unfavorable impact income taxes minority interest measured valueatrisk related contracts held trading purposes approximately 19 million 3 million 3 million december 31 2000 1999 1998 increase valueatrisk 2000 reflects significant increase commodity trading activities period 2000 merchant energys highest lowest average estimated potential one day unfavorable impact income taxes minority interest measured valueatrisk 19 million 2 million 9 million fourth quarter 2000 merchant energy also began managing asset based commodity transactions valueatrisk methodology utilized trading purposes potential oneday unfavorable impact income taxes minority interest related asset based commodity transactions measured valueatrisk 10 million december 31 2000 highest lowest average estimated oneday unfavorable impact income taxes minority interest asset based commodity transactions measured valueatrisk 10 million 5 million 8 million average value represents average 2000 month end values high low valuations represent highest lowest month end values 2000 actual losses could exceed measured valueatrisk nontrading commodity price risk mitigate market risk associated significant physical transactions including natural gas crude oil natural gas liquids production use nontrading financial instruments including forward contracts swaps merchant energy hedges portion commodity risk production field services facilitating derivative financial instruments third parties estimated potential oneday unfavorable impact income taxes minority interest measured valueatrisk related nontrading commodity activities insignificant december 31 2000 1999 1998 interest rate risk many debt related financial instruments project financing arrangements sensitive market fluctuations interest rates mitigate exposure interest rate risk use nontrading derivative financial instruments including interest rate equity swaps august 1999 entered interest rate swap agreement notional amount 600 million termination date july 2001 swapped fixed interest rate 600 million aggregate principal senior notes due 2001 floating 3 month libor plus 01475 percent rate accounted transaction using accrual accounting november 2000 terminated swap termination swap materially impact financial statements march 1997 purchased 105 percent interest capsa approximately 57 million entered equity swap additional 185 percent ownership equity swap paid interest counterparty quarterly basis notional amount 100 million rate libor plus 085 percent exchange received 185 percent capsas dividends february 1999 extended term swap modified notional amount 103 million rate libor plus 175 percent may 2000 exercised right terminate swap purchased counterpartys 185 percent ownership interest capsa approximately 127 million term swap reflected changes market value equity swap income statement termination swap materially impact financial statements table shows cash flows related weighted average interest rates interest bearing securities expected maturity dates december 31 2000 carrying amounts shortterm borrowings representative fair values shortterm maturity instruments fair value longterm debt estimated based quoted market prices similar issues foreign currency exchange rate risk manage exposure changes foreign currency exchange rates entering derivative financial instruments principally foreign currency forward purchase sale contracts primary exposure relates changes foreign currency rates certain merchant activities outside us denominated adjusted us dollars following table summarizes notional amounts average settlement rates fair value foreign currency forward purchase sale contracts december 31 2000 following table summarizes foreign currency forward purchase sale contracts expected maturity dates along annual anticipated cash flow impacts december 31 2000 equity risk merchant energys financial services unit manage invest private investment funds well privately placed securities privately publicly held companies account investments using investment company accounting result holdings measured fair value changes fair value recorded income statement fair value investments determined based estimates amounts would realized securities sold fair values investments subject equity risks december 31 2000 1999 well impact ten percent increase decrease fair values investments period presented item 8item 7a quantitative qualitative disclosures market risk use derivative financial instruments manage market risks associated energy commodities interest rates foreign currency exchange rates primary market risk exposures changing commodity prices market risks monitored corporate risk management committee ensure compliance overall stated risk management policies approved audit committee board directors committee operates independently business segments create actively manage risk exposures 2001 experienced significantly changing energy market brought energy crisis california events september 11th bankruptcy enron corp significant decline energy commodity prices limited market risk exposure period market uncertainty continually monitoring net physical financial positions assuming minimal risk expect continuous monitoring reduced risk assumption continue near term trading commodity price risk merchant energy segment exposed market risks inherent financial instruments uses trading energy related commodities merchant energy records energy trading activities including transportation capacity tolling agreements storage contracts fair value changes fair value activities reflected income statement merchant energys policy manage commodity price risks variety financial instruments including exchangetraded futures contracts involving cash settlements forward contracts involving cash settlements physical delivery energy commodity swap contracts require payments receipts counterparties based difference fixed variable price two variable prices commodity exchangetraded overthecounter options contractual arrangements merchant energy measures risk traded commodity energy related contracts daily basis using valueatrisk model determine maximum potential oneday unfavorable impact earnings due normal market movements monitors risk comparison established thresholds since 1998 merchant energy used known variancecovariance technique measuring valueatrisk technique uses historical price movements specific defined mathematical parameters estimate characteristics relationships components assets liabilities held price risk management activities method works well futures forwards swaps completely capture risk option positions especially large deviations current underlying values reason merchant energy began measuring valueatrisk using historical simulation technique december 2001 technique fully values positions every iteration simulation captures risk types positions including options merchant energy also uses measures provide additional assurance risks commodity energy related contracts properly monitored daily basis including sensitivity analysis stress testing credit risk management establishment parameters monitor measure risk exposure highlight unfavorable trends measure performance portfolio using applicable risk metrics following table presents potential oneday unfavorable impact earnings interest income taxes measured valueatrisk traded commodity energy related contracts prepared based confidence level 95 percent oneday holding period high low valuations represent highest lowest month end values 2001 average valuation represents average 2001 month end values actual losses may exceed measured valueatrisk using either modeling techniques presented 1 portfolio valueatrisk represents combined valueatrisk trading nontrading price risk management activities separate calculation valueatrisk trading nontrading commodity contracts ignores natural correlation exists traded nontraded commodity contracts prices result individually determined values higher combined valueatrisk instances manage risks portfolio approach balances trading nontrading risks nontrading commodity price risk segments exposed variety market risks normal course business activities production segment market risks related oil natural gas produces field services segment market risks related natural gas natural gas liquids retains processing operations refining activities merchant energy segment exposed market risks feedstocks use primarily crude oil petroleum based products well refined products sell merchant energy segment market risks changing prices natural gas locations connected transportation capacity pipelines attempt mitigate market risk associated significant physical transactions use nontrading financial instruments including exchangetraded futures contracts involving cash settlements forward contracts involving cash settlements physical delivery energy commodity swap contracts require payments receipts counterparties based difference fixed variable price two variable prices commodity exchangetraded overthecounter options table presents hypothetical sensitivity changes fair values arising immediate selected potential changes quoted market prices derivative commodity instruments use mitigate market risks outstanding december 31 2001 2000 gain loss derivative commodity instruments would substantially offset corresponding gain loss hedged commodity positions included table december 2001 began measuring risk associated commodity contracts held nontrading purposes using valueatrisk determined using historical simulation technique based confidence level 95 percent oneday holding period estimated potential oneday unfavorable impact earnings interest income taxes 15 million december 31 2001 interest rate risk many debt related financial instruments derivative contracts project financing arrangements sensitive market fluctuations interest rates time manage exposure interest rate risk use nontrading derivative financial instruments primarily interest rate swaps december 31 2001 maintained interest rate swap transaction notional amount 240 million exchanging libor variable interest rate fixed rate 307 transaction results payment fixed rate 449 swap terminates june 2003 fair value swap immaterial december 31 2001 table shows maturity carrying amounts related weighted average interest rates interest bearing securities expected maturity dates december 31 2001 carrying amounts shortterm borrowings representative fair values shortterm maturity instruments fair value longterm debt estimated based quoted market prices similar issues foreign currency exchange rate risk exposure foreign currency exchange rates relates changes foreign currency rates international power investments operations foreign trading operations foreign debt obligations denominated adjusted us dollars time manage exposure changes foreign currency exchange rates entering derivative financial instruments principally foreign currency forward purchase sale contracts following table summarizes notional amounts average settlement rates fair value foreign currency forward purchase sale contracts december 31 2001 following table summarizes foreign currency forward purchase sale contracts expected maturity dates along annual anticipated cash flow impacts december 31 2001 equity risk merchant energy segment holds investments expose us price risk associated equity securities markets account investments using investment company accounting result holdings measured fair value changes fair value recorded income statement fair value investments determined based estimates amounts would realized securities sold also hold variety publicly traded marketable equity securities fair values holdings december 31 2001 2000 well impact ten percent increase decrease underlying fair values securities period presented item 8item 7a quantitative qualitative disclosures market risk use derivative financial instruments energy related contracts manage market risks associated energy commodities interest rates foreign currency exchange rates primary market risk exposures related changing commodity prices market risks monitored corporate risk management committee ensure compliance stated risk management policies approved audit committee board directors committee operates independently business segments create manage risks commodity price risk exposed variety market risks normal course business activities nature market price risks varies based segments production segment price risks related natural gas oil produces field services segment price risks related natural gas liquids retains processing operations global power division merchant energy segment exposed price risks fuel uses primarily natural gas coal well power sells petroleum division merchant energy segment exposed price risks feedstocks uses primarily crude oil petroleumbased products well refined products sells energy trading division merchant energy segment exposed market price risks inherent contractual obligations deliver receive commodities financial instruments uses trading energy energyrelated commodities attempt mitigate price risk associated energy trading activities included energy trading petroleum divisions merchant energy nontrading activities power commodity hedging activities use trading nontrading financial instruments including forwards swaps options futures measure risks commodity energyrelated contracts daily basis using valueatrisk model allows us determine maximum expected oneday unfavorable impact fair values contracts due normal market movements monitors risk comparison established thresholds use known historical simulation technique measuring valueatrisk technique values positions every iteration simulation captures risk types financial positions also use measures monitor risks daily basis including sensitivity analysis stress testing credit risk management measures monitor measure risk exposure following table presents maximum expected oneday unfavorable impact fair values commodity energyrelated contracts measured valueatrisk based confidence level 95 percent oneday holding period high low valuations represent highest lowest month end values 2002 average valuation represents average 2002 month end values actual losses fair value may exceed measured valueatrisk 1 portfolio valueatrisk represents combined valueatrisk trading nontrading commodity energyrelated contracts separate calculation valueatrisk trading nontrading commodity contracts ignores natural correlation exists traded nontraded commodity contracts prices result sum individually determined values higher combined valueatrisk instances manage risks portfolio approach balances trading nontrading risks 10 million decrease trading valueatrisk 2002 attributable efforts limit liquidate trading activities 2002 nontrading valueatrisk decreased 7 million 2002 due reduction hedged volumes future natural gas production 2002 reduced hedged volumes reduce cash requirements nontrading price risk management activities interest rate risk many debtrelated financial instruments project financing arrangements sensitive changes interest rates table shows maturity carrying amounts related weighted average interest rates interestbearing securities expected maturity dates fair values securities december 31 2002 carrying amounts shortterm borrowings representative fair values shortterm maturity instruments fair value longterm securities estimated based quoted market prices similar issues fair value longterm securities significantly impacted series ratings actions initiated moodys standard poors lowered unsecured debt rating caa1 b investment grade ratings remain negative outlook rating actions decreased fair value fixed rate longterm securities 2002 foreign currency exchange rate risk exposure foreign currency exchange rates relates primarily changes foreign currency rates eurodenominated debt obligations eurodenominated debt principal amount 1050 million euros 1100 million eurousd spot exchange rate 10492 december 31 2002 550 million euros 500 million euros debt mature 2006 2009 foreign currency swap converts 275 million euros debt us dollars fixed rate 09275 remaining principal 775 million euros unhedged subject foreign currency exchange risk ten percent increase decrease eurousd exchange rate would increase decrease carrying value unhedged eurodenominated debt approximately 81 million item 8item 7a quantitative qualitative disclosures market risk exposed several market risks normal business activities market risk potential loss may result market changes associated existing forecasted financial commodity transaction types market risks exposed examples commodity price risk natural gas prices change impacting forecasted sale natural gas production segment price spreads natural gas natural gas liquids change making natural gas liquids produce field services segment less valuable locational price differences natural gas change affecting ability optimize pipeline transportation capacity contracts held merchant energy segment electricity natural gas prices change affecting value natural gas contracts power contracts tolling contracts held merchant energy segment interest rate risk changes interest rates affect interest expense incur variablerate debt fair value fixedrate debt changes interest rates used estimation fair value derivative positions result increases decreases unrealized value positions foreign currency exchange rate risk weakening strengthening us dollar relative euro result increase decrease value eurodenominated debt obligations related interest costs associated debt changes foreign currencies exchange rates international investments may impact value investments earnings cash flows investments segment manages risks frequently entering contractual commitments involving physical financial settlement attempts limit amount risk opportunity related future market movements risk management activities typically involve use following types contracts forward contracts commit us purchase sell energy commodities future involving physical delivery energy commodity energy related contracts including transportation storage transmission power tolling arrangements futures contracts exchangetraded standardized commitments purchase sell commodity financial instrument make cash settlement specific price future date options convey right buy sell commodity financial instrument index predetermined price swaps require payments counterparties based upon differential two prices predetermined contractual notional quantity structured contracts may involve variety characteristics many contracts utilize risk management activities derivative financial instruments discussions accounting policies derivative instruments included item 8 financial statements supplementary data notes 2 15 commodity price risk exposed variety commodity price risks normal course business activities nature market price risks varies segment merchant energy merchant energy segment attempts mitigate exposure commodity price risk use various financial instruments including forwards swaps options futures measure risks merchant energys commodity energyrelated contracts daily basis using valueatrisk simulation allows us determine maximum expected oneday unfavorable impact fair values contracts due adverse market movements defined period time within specified confidence level monitors risk comparison established thresholds use known historical simulation technique measuring valueatrisk technique simulates potential outcomes value portfolio based marketbased price changes exposure changes fundamental prices longterm vary exposure using oneday assumption valueatrisk simulations supplement valueatrisk simulations additional fundamental marketbased price analyses including scenario analysis stress testing determine portfolios sensitivity underlying risks maximum expected oneday unfavorable impact fair values commodity energyrelated contracts measured valueatrisk based confidence level 95 percent oneday holding period 34 million december 31 2003 2002 highest lowest average month end values valueatrisk 2003 48 million 23 million 37 million actual losses fair value may exceed measured valueatrisk amounts 2002 restated reflect change accounting hedges anticipated natural gas production certain derivatives august 2004 determined hedges qualify cash flow hedges consolidated reporting level result required recorded marktomarket contracts subject commodity price risk trading contracts valueatrisk restated reflect derivatives longer qualified hedge accounting restatement merchant energy segments primary exposure commodity price risk relates natural gas positions derivative tolling contract midwest positions sensitive price changes natural gas power occurred 2003 caused significant fluctuations earnings valueatrisk period production segment attempts mitigate commodity price risk stabilize cash flows associated forecasted sales natural gas oil production use derivative natural gas oil swap contracts table presents hypothetical sensitivity changes fair values arising immediate selected potential changes quoted market prices derivative commodity instruments use mitigate market risks outstanding december 31 2003 2002 information also restated reflect derivative commodity instruments qualify accounting purposes hedges anticipated natural gas production gain loss derivative commodity instruments would substantially offset corresponding gain loss hedged commodity positions included table derivatives described hedge commodity price risk related forecasted sales natural gas production result subject commodity price risks remaining forecasted natural gas production addition entered new hedges 2004 55 tbtu anticipated natural gas production average price 564 per mmbtu 11 mmbbls anticipated crude oil production average price 3515 per bbl field services field services segment significantly utilize financial instruments mitigate exposure natural gas liquids retains processing operations since overall exposure material overall operations interest rate risk debt many debtrelated financial instruments project financing arrangements sensitive changes interest rates table shows maturity carrying amounts related weightedaverage interest rates interestbearing securities expected maturity dates fair values securities december 31 2003 2002 carrying amounts shortterm borrowings representative fair values shortterm maturity instruments fair value longterm securities estimated based quoted market prices similar issues derivatives power contract restructuring activities derivatives associated power contract restructuring business global power division merchant energy segment valued using estimated future market power prices discount rate considers appropriate us treasury rate plus credit spread specific contracts counterparty make adjustments discount rate believe market changes rates result changes value realized current transaction willing parties since september 30 2002 order provide market risk reflected increase value would result decreases us treasury rates believe resulting increase value nontrading derivatives could realized current transaction willing parties reflected actual us treasury yields december 31 2003 valuation value third party nontrading derivatives would higher approximately 125 million extent commodity price risk associated derivative contracts included valueatrisk calculation discussed exposure changes interest rates credit spreads included valueatrisk calculation december 31 2003 ten percent increase decrease discount rate used value third party positions would result increase decrease fair value derivative contracts 56 million 59 million result sale ucf 2004 pending sale cedar brakes ii 2004 sensitivity interest rate changes derivatives decrease foreign currency exchange rate risk debt exposure foreign currency exchange rates relate primarily changes foreign currency rates eurodenominated debt obligations december 31 2003 eurodenominated debt principal amount e1050 million e550 million matures 2006 e500 matures 2009 december 31 2003 2002 entered hedge transactions effectively convert e625 million e275 million debt 645 million 255 million 2004 entered cross currency hedge transactions convert e100 million fixed rate debt 121 million floating rate debt remaining principal december 31 2003 2002 e425 million e775 million subject foreign currency exchange risk sensitivity analysis hypothetical ten percent increase decrease eurousd exchange rate 12595 variables held constant december 31 2003 would increase decrease carrying value unhedged eurodenominated debt approximately 54 million power contracts several international power plants asia central america europe longterm power sales contracts denominated local countrys currencies result subject foreign currency exchange risk related power sales contracts believe exposure material operations chosen mitigate exposure item 8item 7a quantitative qualitative disclosures market risk exposed several market risks normal business activities market risk potential loss may result market changes associated existing forecasted financial commodity transaction types market risks exposed examples • commodity price risk natural gas prices change impacting forecasted sale natural gas production segment price spreads natural gas natural gas liquids change making natural gas liquids produce field services segment less valuable locational price differences natural gas change affecting ability optimize pipeline transportation capacity contracts held marketing trading segment electricity natural gas prices change affecting value natural gas contracts power contracts tolling contracts held marketing trading power segments • interest rate risk changes interest rates affect interest expense incur variablerate debt fair value fixedrate debt changes interest rates used estimation fair value derivative positions result increases decreases unrealized value positions • foreign currency exchange rate risk weakening strengthening us dollar relative euro result increase decrease value eurodenominated debt obligations related interest costs associated debt changes foreign currencies exchange rates international investments may impact value investments earnings cash flows investments manage risks frequently entering contractual commitments involving physical financial settlement attempts limit amount risk opportunity related future market movements risk management activities typically involve use following types contracts • forward contracts commit us purchase sell energy commodities future involving physical delivery energy commodity energy related contracts including transportation storage transmission power tolling arrangements • futures contracts exchangetraded standardized commitments purchase sell commodity financial instrument make cash settlement specific price future date • options convey right buy sell commodity financial instrument index predetermined price • swaps require payments counterparties based upon differential two prices predetermined contractual notional quantity • structured contracts may involve variety characteristics many contracts utilize risk management activities derivative financial instruments discussion accounting policies derivative instruments included part ii item 8 financial statements supplementary data notes 1 10 commodity price risk exposed variety commodity price risks normal course business activities nature market price risks varies segment marketing trading marketing trading segment attempts mitigate exposure commodity price risk use various financial instruments including forwards swaps options futures measure risks marketing trading segment’s commodity energyrelated contracts daily basis using valueatrisk simulation allows us determine maximum expected oneday unfavorable impact fair values contracts due adverse market movements defined period time within specified confidence level monitors risk comparison established thresholds use known historical simulation technique measuring valueatrisk technique simulates potential outcomes value portfolio based marketbased price changes exposure changes fundamental prices longterm vary exposure using oneday assumption valueatrisk simulations supplement valueatrisk simulations additional fundamental marketbased price analyses including scenario analysis stress testing determine portfolio’s sensitivity underlying risks maximum expected oneday unfavorable impact fair values commodity energyrelated contracts measured valueatrisk based confidence level 95 percent oneday holding period 16 million 34 million december 31 2004 2003 highest lowest average month end values valueatrisk 2004 82 million 16 million 38 million actual losses fair value may exceed measured valueatrisk decreased fourth quarter 2004 designation number natural gas derivative contracts hedges production segment’s natural gas production exposure derivatives natural gas price fluctuations captured production segment discussion production segment attempts mitigate commodity price risk stabilize cash flows associated forecasted sales natural gas oil production use derivative natural gas oil swap contracts table presents hypothetical sensitivity changes fair values arising immediate selected potential changes quoted market prices derivative commodity instruments use mitigate market risks outstanding december 31 2004 2003 gain loss derivative commodity instruments would substantially offset corresponding gain loss hedged commodity positions included table derivatives hedge commodity price risk related forecasted sales natural gas oil production result subject commodity price risks remaining forecasted natural gas oil production fourth quarter 2004 designated number marketing trading segment’s natural gas derivative contracts hedges production segment’s natural gas production result sensitivity derivatives production segment natural gas price changes increased marketing trading segment’s valueatrisk decreased december 31 2004 discussed additionally december 31 2004 marketing trading segment entered derivative contracts designed provide el paso price protection declines natural gas prices 2005 2006 contracts provide us floor price 600 per mmbtu 60 tbtu natural gas production 2005 120 tbtu 2006 first quarter 2005 entered additional contracts provide el paso floor price 600 per mmbtu 30 tbtu natural gas 2007 ceiling price 950 per mmbtu 60 tbtu natural gas production 2006 commodity price risk associated contracts included sensitivity analysis rather included valueatrisk calculation discussed field services field services segment significantly utilize financial instruments mitigate exposure natural gas liquids retains processing operations since exposure material overall operations interest rate risk debt many debtrelated financial instruments project financing arrangements sensitive changes interest rates table shows maturity carrying amounts related weightedaverage interest rates interestbearing securities expected maturity dates fair values securities december 31 2004 2003 carrying amounts shortterm borrowings representative fair values shortterm maturity instruments fair value longterm securities estimated based quoted market prices similar issues derivatives power contract restructuring activities derivatives associated power contract restructuring business power segment valued using estimated future market power prices discount rate considers appropriate us treasury rate plus credit spread specific contract’s counterparty make adjustments discount rate believe market changes rates result changes value realized current transaction willing parties since september 30 2002 order provide market risk reflected increase value would result decreases us treasury rates believe resulting increase value nontrading derivatives could realized current transaction willing parties extent commodity price risk associated derivative contracts included valueatrisk calculation discussed exposure changes interest rates credit spreads included valueatrisk calculation historically interest rate risk associated contracts primarily related ucf cedar brakes ii result sale ucf 2004 sale cedar brakes ii march 2005 sensitivity interest rate changes remaining restructured power contract derivatives minimal foreign currency exchange rate risk debt exposure foreign currency exchange rates relates primarily changes foreign currency rates eurodenominated debt obligations december 31 2004 eurodenominated debt principal amount 1050 million 550 million matures 2006 500 million matures 2009 december 31 2004 2003 swaps effectively converted 725 million 625 million debt 766 million 645 million remaining principal december 31 2004 2003 325 million 425 million subject foreign currency exchange risk march 2005 repurchased approximately 528 million debt maturing 2006 repurchase unhedged eurodenominated debt subject foreign currency exchange risk totaled 172 million result hypothetical ten percent increase decrease eurousd exchange rate 13188 date repurchase variables held constant would increase decrease carrying value remaining unhedged eurodenominated debt repurchase approximately 23 million power contracts several international power plants asia central america south america europe longterm power sales contracts denominated local country’s currencies result subject foreign currency exchange risk related power sales contracts believe exposure material operations chosen mitigate exposure item 8nanitem 7a quantitative qualitative disclosures market risk exposed market risks normal business activities market risk potential loss may result market changes associated existing forecasted financial commodity transaction types market risks exposed examples • commodity price risk natural gas oil price changes impacting sale natural gas oil exploration production segment gas used operations pipelines segment natural gas locational price differences change affecting ability optimize pipeline transportation capacity contracts held marketing segment electricity natural gas price changes locational pricing changes affecting value natural gas contracts remaining power contracts held marketing segment • interest rate risk changes interest rates affect interest expense incur variablerate debt fair value fixedrate debt changes interest rates used estimation fair value derivative positions result increases decreases unrealized value positions changes interest rates used discount liabilities result higher lower accretion expense time • foreign currency exchange rate risk weakening strengthening us dollar relative euro result increase decrease value eurodenominated debt obligations andor related interest costs associated debt manage risks entering contractual commitments involving physical financial settlement attempt limit exposure related future market movements timing extent risk management activities based number factors including market outlook risk tolerance liquidity risk management activities typically involve use following types contracts • forward contracts commit us purchase sell energy commodities future • futures contracts exchangetraded standardized commitments purchase sell commodity financial instrument make cash settlement specific price future date • options convey right buy sell commodity financial instrument index predetermined price • swaps require payments counterparties based upon differential two prices rates predetermined contractual notional quantity • structured contracts may involve variety characteristics many contracts use risk management activities qualify derivative financial instruments discussion accounting policies derivative instruments included part ii item 8 financial statements supplementary data notes 1 8 commodity price risk productionrelated derivatives exploration production marketing segments attempt mitigate commodity price risk stabilize cash flows associated el paso’s forecasted sales natural gas oil production use derivative natural gas oil swaps basis swaps option contracts table presents hypothetical sensitivity changes fair values arising immediate selected potential changes quoted market prices derivative commodity instruments used mitigate market risks table changed reflect current practice managing productionrelated risks exploration production marketing segments includes use productionrelated derivative contracts whether designated hedges contracts designated hedges impact earnings sale related hedged items occurs result gain loss hedging derivatives would substantially offset corresponding gain loss underlying hedged commodity sale included table contracts designated hedges impact earnings fair value derivatives changes productionrelated derivatives mitigate commodity price risk related forecasted sales natural gas oil production result subject commodity price risks remaining forecasted natural gas oil production commoditybased derivatives marketing segment also various financial instruments utilized mitigate commodity price risk associated natural gas oil production measure risks contracts daily basis using valueatrisk simulation allows us determine maximum expected oneday unfavorable impact fair values contracts due adverse market movements defined period time within specified confidence level allows us monitor risk comparison established thresholds use known historical simulation technique measuring valueatrisk technique simulates potential outcomes value portfolio based marketbased price changes exposure changes fundamental prices longterm vary exposure using oneday assumption valueatrisk simulations supplement valueatrisk simulations additional fundamental marketbased price analyses including scenario analysis stress testing determine portfolio’s sensitivity underlying risks analyses valueatrisk simulations changed exclude productionrelated derivatives included sensitivity analyses described marketing segment’s natural gas transportation related contracts accounted accrual basis accounting exploration production segment’s sales natural gas oil production maximum expected oneday unfavorable impact fair values commoditybased derivatives measured valueatrisk based confidence level 95 percent oneday holding period 6 million 29 million december 31 2006 2005 highest lowest average monthend values valueatrisk 2006 14 million 3 million 7 million valueatrisk decreased significantly 2006 primarily due assignment certain power natural gas derivatives third parties may experience changes valueatrisk future commodity prices volatile interest rate risk many debtrelated financial instruments project financing arrangements sensitive changes interest rates table shows maturity carrying amounts related weightedaverage interest rates longterm interestbearing securities expected maturity dates well total fair value securities fair value securities estimated based quoted market prices similar issues foreign currency exchange rate risk exposure foreign currency exchange rates relates primarily changes foreign currency rates eurodenominated debt obligations december 31 2006 eurodenominated debt principal amount 500 million matures 2009 december 31 2006 2005 swaps effectively converted 350 million 367 million debt 402 million 418 million remaining principal december 31 2006 2005  150 million 155 million subject foreign currency exchange risk 010 change euro us dollar exchange rate would result 15 million gain loss unhedged eurodenominated debt december 31 2006 item 8item 7a quantitative qualitative disclosures market risk exposed market risks normal business activities market risk potential loss may result market changes associated existing forecasted financial commodity transaction types market risks exposed examples • natural gas oil price changes impacting sale natural gas oil exploration production segment affecting gas used operations pipelines segment affecting fair value natural gas oil derivative contracts held marketing segment • natural gas locational price differences change affecting ability optimize pipeline transportation capacity contracts held marketing segment • electricity price changes locational pricing changes affecting value remaining power contracts held marketing segment • interest rate risk • changes interest rates affect interest expense incur variablerate debt fair value fixedrate debt • changes interest rates used estimation fair value derivative positions result increases decreases unrealized value positions • changes interest rates used discount liabilities result higher lower accretion expense time • foreign currency exchange rate risk • weakening strengthening us dollar relative euro result increase decrease value eurodenominated debt obligations andor related interest costs associated debt • weakening strengthening us dollar relative brazilian real mexican peso affect revenues expenses generated foreign pipeline exploration production power operations manage risks entering contractual commitments involving physical financial settlement attempt limit exposure related future market movements timing extent risk management activities based number factors including market outlook risk tolerance liquidity risk management activities typically involve use following types contracts • forward contracts commit us purchase sell energy commodities future • futures contracts exchangetraded standardized commitments purchase sell commodity financial instrument make cash settlement specific price future date • options convey right buy sell commodity financial instrument index predetermined price • swaps require payments counterparties based upon differential two prices rates predetermined contractual notional quantity • structured contracts may involve variety characteristics many contracts use risk management activities qualify derivative financial instruments discussion accounting policies derivative instruments included part ii item 8 financial statements supplementary data notes 1 7 commodity price risk productionrelated derivatives attempt mitigate commodity price risk stabilize cash flows associated forecasted sales natural gas oil production use derivative natural gas oil swaps basis swaps option contracts derivative contracts entered exploration production marketing segments table presents hypothetical sensitivity changes fair values arising immediate selected potential changes quoted market prices derivative commodity instruments used mitigate market risks designated certain derivatives accounting hedges contracts designated accounting hedges impact earnings related hedged production sales occur result gain loss hedging derivatives would offset gain loss sale underlying hedged commodity included table contracts designated accounting hedges impact earnings fair value derivatives changes productionrelated derivatives mitigate commodity price risks forecasted sales natural gas oil production result subject commodity price risks remaining forecasted natural gas oil production commoditybased derivatives marketing segment derivative contracts used mitigate commodity price risk associated natural gas oil production many contracts include forwards swaps options futures longterm historical contracts either intend assign third parties manage expiration measure risks contracts daily basis using valueatrisk simulation allows us determine maximum expected oneday unfavorable impact fair values contracts adverse market movements defined period time within specified confidence level allows us monitor risk comparison established thresholds measure valueatrisk use known historical simulation technique simulates potential outcomes value portfolio based marketbased price changes exposure changes fundamental prices longterm vary exposure using oneday assumption valueatrisk simulations supplement valueatrisk simulations additional fundamental marketbased price analyses including scenario analysis stress testing determine portfolio’s sensitivity underlying risks analyses valueatrisk simulations include commodity exposures related productionrelated derivatives described marketing segment’s natural gas transportation related contracts accounted accrual basis accounting exploration production segment’s sales natural gas oil production maximum expected oneday unfavorable impact fair values commoditybased derivatives measured valueatrisk based confidence level 95 percent oneday holding period 1 million 6 million december 31 2007 2006 highest lowest average monthend values valueatrisk 2007 6 million 1 million 2 million may experience changes valueatrisk future commodity prices volatile interest rate risk many debtrelated financial instruments project financing arrangements sensitive changes interest rates table shows maturity carrying amounts related weightedaverage interest rates longterm interestbearing securities expected maturity date well total fair value securities fair value securities estimated based quoted market prices similar issues estimate fair value longterm debt variable rates approximates carrying value market based nature interest rate foreign currency exchange rate risk exposure foreign currency exchange rates relates primarily changes foreign currency rates eurodenominated debt obligations december 31 2007 2006 eurodenominated debt principal amount 380 million 500 million matures 2009 december 31 2007 2006 swaps effectively convert 330 million 350 million debt 379 million 402 million remaining principal december 31 2007 2006 50 million 150 million subject foreign currency exchange risk 010 change euro us dollar exchange rate would result 5 million gain loss unhedged eurodenominated debt december 31 2007 item 8item 7a quantitative qualitative disclosures market risk exposed market risks normal business activities market risk potential loss may result market changes associated existing forecasted financial commodity transaction types market risks exposed examples • commodity price risk • changes natural gas oil prices impact sale natural gas oil exploration production segment affect gas used operations pipelines segment affect fair value natural gas oil derivative contracts held exploration production marketing segments • changes natural gas locational price differences affect ability optimize pipeline transportation capacity contracts held marketing segment • changes electricity prices locational price differences affect value remaining power contracts held marketing segment • interest rate risk • changes interest rates affect interest expense incur variablerate debt fair value fixedrate debt • changes interest rates used estimation fair value derivative positions result increases decreases unrealized value positions • changes interest rates used discount liabilities result higher lower accretion expense time • foreign currency exchange rate risk • weakening strengthening us dollar relative euro result increase decrease value eurodenominated debt obligations andor related interest costs associated debt • weakening strengthening us dollar relative brazilian real mexican peso affect revenues expenses generated foreign pipeline exploration production power operations manage risks entering contractual commitments involving physical financial settlement attempt limit exposure related future market movements timing extent risk management activities based number factors including market outlook risk tolerance liquidity risk management activities typically involve use following types contracts • forward contracts commit us purchase sell energy commodities future • futures contracts exchangetraded standardized commitments purchase sell commodity financial instrument make cash settlement specific price future date • options convey right buy sell commodity financial instrument index predetermined price • swaps require payments counterparties based upon differential two prices rates predetermined contractual notional quantity • structured contracts may involve variety characteristics many contracts use risk management activities qualify derivative financial instruments discussion accounting policies derivative instruments included part ii item 8 financial statements supplementary data notes 1 8 commodity price risk productionrelated derivatives attempt mitigate commodity price risk stabilize cash flows associated forecasted sales natural gas oil production use derivative natural gas oil swaps basis swaps option contracts impact earnings fair value derivatives changes productionrelated derivatives mitigate commodity price risks forecasted sales natural gas oil production result subject commodity price risks remaining forecasted natural gas oil production commoditybased derivatives marketing segment longterm derivative contracts include forwards swaps options futures either intend assign third parties manage expiration prior 2008 managed contracts daily basis using valueatrisk simulation 2008 began utilizing sensitivity analysis manage commodity price risk associated commoditybased derivative contracts discontinued using valueatrisk simulation based continued simplification derivative portfolio gradual discontinuance substantial majority trading activities sensitivity analysis table presents hypothetical sensitivity productionrelated derivatives commoditybased derivatives changes fair values arising immediate selected potential changes market prices primarily natural gas oil power prices basis differentials used value contracts table reflects sensitivities derivative contracts include underlying hedged commodities interest rate risk many debtrelated financial instruments project financing arrangements sensitive changes interest rates table shows maturity carrying amounts related weightedaverage effective interest rates longterm interestbearing securities expected maturity date well total fair value securities fair value securities estimated based quoted market prices similar issues foreign currency exchange rate risk exposure foreign currency exchange rates relates primarily changes foreign currency rates eurodenominated debt obligations december 31 2008 2007 eurodenominated debt principal amount 380 million matures may 2009 swaps effectively convert 330 million debt 379 million december 31 2008 december 31 2007 remaining principal 50 million december 31 2008 2007 subject foreign currency exchange risk 010 change euro us dollar exchange rate would result 5 million gain loss unhedged eurodenominated debt december 31 2008 item 8item 7a quantitative qualitative disclosures market risk exposed market risks normal business activities market risk potential loss may result market changes associated existing forecasted financial commodity transaction types market risks exposed examples • commodity price risk • changes natural gas oil prices impact amounts sell natural gas oil exploration production segment affect gas used operations pipelines segment affect fair value natural gas oil derivative contracts held exploration production marketing segments • changes natural gas locational price differences also affect amounts sell natural gas oil production fair values related derivative products affect ability optimize pipeline transportation capacity contracts held marketing segment • changes electricity prices locational price differences affect value remaining power contracts held marketing segment • interest rate risk • changes interest rates affect interest expense incur variablerate debt fair value fixedrate debt • changes interest rates result increases decreases unrealized value derivative positions • changes interest rates used discount liabilities result higher lower accretion expense time practical manage various risks entering contractual commitments involving physical financial settlement attempt limit exposure related future market movements timing extent risk management activities based number factors including market outlook risk tolerance liquidity risk management activities typically involve use following types contracts • forward contracts commit us purchase sell energy commodities future • futures contracts exchangetraded standardized commitments purchase sell commodity financial instrument make cash settlement specific price future date • options convey right buy sell commodity financial instrument index predetermined price • swaps require payments counterparties based upon differential two prices rates predetermined contractual notional quantity • structured contracts may involve variety characteristics many contracts use risk management activities qualify derivative financial instruments discussion accounting policies derivative instruments included item 8 financial statements supplementary data notes 1 8 commodity price risk productionrelated derivatives attempt mitigate commodity price risk stabilize cash flows associated forecasted sales natural gas oil production use derivative natural gas oil swaps basis swaps option contracts impact earnings fair value derivatives changes productionrelated derivatives mitigate commodity price risks forecasted sales natural gas oil production result subject commodity price risks remaining forecasted production commoditybased derivatives marketing segment longterm natural gas power derivative contracts include forwards swaps options futures either intend manage expiration seek opportunities liquidate extent economical prudent utilize sensitivity analysis manage commodity price risk associated contracts sensitivity analysis table presents hypothetical sensitivity productionrelated derivatives commoditybased derivatives changes fair values arising immediate selected potential changes market prices primarily natural gas oil power prices basis differentials used value contracts table reflects sensitivities derivative contracts include underlying hedged commodities interest rate risk many debtrelated financial instruments project financing arrangements sensitive changes interest rates table shows maturity carrying amounts related weightedaverage effective interest rates longterm interestbearing securities expected maturity date well total fair value securities fair value securities estimated based quoted market prices similar issues item 8item 7a quantitative qualitative disclosures market risk exposed market risks normal business activities market risk potential loss may result market changes associated existing forecasted financial commodity transaction types market risks exposed examples • commodity price risk • changes natural gas oil prices impact amounts sell natural gas oil exploration production segment affect value gas used operations pipelines segment affect fair value natural gas oil derivative contracts held exploration production marketing segments • changes natural gas locational price differences also affect amounts sell natural gas oil production fair values related derivative products affect ability optimize pipeline transportation capacity contracts held marketing segment • changes electricity prices locational price differences affect value remaining power contracts held marketing segment • interest rate risk • changes interest rates affect interest expense incur variablerate debt fair value fixedrate debt • changes interest rates result increases decreases unrealized value derivative positions • changes interest rates used discount liabilities result higher lower accretion expense time practical manage various risks entering contractual commitments involving physical financial settlement attempt limit exposure related future market movements timing extent risk management activities based number factors including market outlook risk tolerance liquidity risk management activities typically involve use following types contracts • forward contracts commit us purchase sell energy commodities future • futures contracts exchangetraded standardized commitments purchase sell commodity financial instrument make cash settlement specific price future date • options convey right buy sell commodity financial instrument index predetermined price • swaps require payments counterparties based upon differential two prices rates predetermined contractual notional quantity • structured contracts may involve variety characteristics many contracts use risk management activities qualify derivative financial instruments discussion accounting policies derivative instruments included item 8 financial statements supplementary data notes 1 7 commodity price risk productionrelated derivatives exploration production segment attempt mitigate commodity price risk stabilize cash flows associated forecasted sales natural gas oil production use derivative natural gas oil swaps basis swaps option contracts impact earnings fair value derivatives changes productionrelated derivatives mitigate commodity price risks forecasted sales natural gas oil production result subject commodity price risks remaining forecasted production commoditybased derivatives marketing segment longterm natural gas power derivative contracts include forwards swaps options futures either intend manage expiration seek opportunities liquidate extent economical prudent utilize sensitivity analysis manage commodity price risk associated contracts sensitivity analysis table presents hypothetical sensitivity productionrelated derivatives commoditybased derivatives changes fair values arising immediate selected potential changes market prices primarily natural gas oil power prices basis differentials used value contracts table reflects sensitivities derivative contracts include underlying hedged commodities interest rate risk many debtrelated financial instruments project financing arrangements sensitive changes interest rates table shows maturity carrying amounts related weightedaverage effective interest rates longterm interestbearing securities expected maturity date well total fair value securities fair value securities estimated based quoted market prices similar issues 1 includes current portion item 8item 7a quantitative qualitative disclosures market risk exposed market risks normal business activities market risk potential loss may result market changes associated existing forecasted financial commodity transaction types market risks exposed examples • commodity price risk • changes oil natural gas prices impact amounts sell oil natural gas exploration production segment affect fair value oil natural gas derivative contracts held exploration production marketing segments • changes locational price differences also affect amounts sell oil natural gas production fair values related derivative products affect ability optimize pipeline transportation capacity contracts held marketing segment • interest rate risk • changes interest rates affect interest expense incur variablerate debt fair value fixedrate debt • changes interest rates result increases decreases unrealized value derivative positions • changes interest rates used discount liabilities result higher lower accretion expense time practical manage various risks entering contractual commitments involving physical financial settlement attempt limit exposure related future market movements timing extent risk management activities based number factors including market outlook risk tolerance liquidity risk management activities typically involve use following types contracts • forward contracts commit us purchase sell energy commodities future • futures contracts exchangetraded standardized commitments purchase sell commodity financial instrument make cash settlement specific price future date • options convey right buy sell commodity financial instrument index predetermined price • swaps require payments counterparties based upon differential two prices rates predetermined contractual notional quantity • structured contracts may involve variety characteristics many contracts use risk management activities qualify derivative financial instruments discussion accounting policies derivative instruments included item 8 financial statements supplementary data notes 1 7 commodity price risk productionrelated derivatives exploration production segment attempt mitigate commodity price risk stabilize cash flows associated forecasted sales oil natural gas production use derivative oil natural gas swaps basis swaps option contracts impact earnings fair value derivatives change productionrelated derivatives mitigate commodity price risks forecasted sales oil natural gas production result subject commodity price risks remaining forecasted production commoditybased derivatives marketing segment longterm natural gas power derivative contracts include forwards swaps options futures either intend manage expiration seek opportunities liquidate extent economical prudent utilize sensitivity analysis manage commodity price risk associated contracts sensitivity analysis table presents hypothetical sensitivity productionrelated derivatives commoditybased derivatives changes fair values arising immediate selected potential changes market prices primarily natural gas oil power prices basis differentials used value contracts table reflects sensitivities derivative contracts include underlying hedged commodities interest rate risk many debtrelated financial instruments project financing arrangements sensitive changes interest rates table shows maturity carrying amounts related weightedaverage effective interest rates longterm interestbearing securities expected maturity date well total fair value securities fair value securities estimated primarily based quoted market prices similar issues 1 includes current portion item 8 item 8 financial statements supplementary data el paso energy corporation consolidated statements income millions except per common share amounts accompanying notes integral part consolidated financial statements el paso energy corporation consolidated balance sheets millions except common share amounts assets accompanying notes integral part consolidated financial statements el paso energy corporation consolidated statements cash flows millions accompanying notes integral part consolidated financial statements el paso energy corporation consolidated statements stockholders equity millions except per common share amounts accompanying notes integral part consolidated financial statements el paso energy corporation consolidated statements comprehensive income millions accompanying notes integral part consolidated financial statements el paso energy corporation notes consolidated financial statements 1 summary significant accounting policies basis presentation principles consolidation consolidated financial statements include accounts majorityowned controlled subsidiaries company elimination significant intercompany accounts transactions investments companies company ability exert significant influence control operating financial policies accounted using equity method financial statements previous periods include certain reclassifications made conform current year presentation reclassifications impact reported net income stockholders equity holding company reorganization effective august 1 1998 company reorganized holding company organizational structure whereby epec delaware corporation became holding company holding company organizational structure effected merger conducted pursuant section 251g delaware general corporation law provides formation holding company structure without vote stockholders epng merger el paso energy merger company delaware corporation wholly owned subsidiary epec merged epng surviving corporation virtue reorganization epng became direct wholly owned subsidiary epec epngs outstanding capital stock converted share basis capital stock epec result restructuring outstanding share 300 par value common stock epng converted one share 300 par value common stock epec onehalf outstanding preferred stock purchase right epng converted one preferred stock purchase right epec common stock right representing right purchase one twohundredth subject adjustment share series junior participating preferred stock epec reorganization companies common control stockholders equity components thereof epng became basis epec stockholders equity addition holding company formation epec assumed ownership trust defined note 3 well epngs obligations related trust see note 3 trust preferred securities discussion finally epec became successor epngs previous shelf registration amount 565 million new york stock exchange ticker symbol used epec following reorganization remains unchanged epg taxfree internal reorganization december 31 1998 company effected taxfree internal reorganization assets operations majority subsidiaries accordance private letter ruling received irs internal reorganization substantial number subsidiaries transferred company andor entities owned company taxfree internal reorganization impact presentation herein stock split january 21 1998 board approved twoforone stock split epngs common stock split subject stockholder approval amendment epngs restated certificate incorporation increase number authorized shares epngs common stock 275000000 shares amendment epngs stockholders approved amendment march 2 1998 connection amendment board increased number authorized shares epngs preferred stock designated series junior participating preferred stock 1375000 shares prior holding company reorganization designated number series junior participating preferred stock increased 2750000 stock split effected form stock dividend aggregate 60944417 shares epngs common stock paid april 11998 stockholders record march 13 1998 common shares per common share amounts adjusted give effect stock split giving effect stock split accordance adjustment provisions amended restated shareholder rights agreement dated july 23 1997 company bankboston na rights agent number rights purchase one onehundredth share series junior participating preferred stock associated share common stock adjusted become onehalf right see holding company reorganization impact holding company reorganization use estimates preparation financial statements conformity generally accepted accounting principles requires management make estimates assumptions affect reported amounts assets liabilities revenues expenses disclosure contingent assets liabilities exist date financial statements actual results likely differ estimates accounting regulated operations companys businesses subject regulations accounting requirements ferc followed accounting requirements sfas 71 accounting effects certain types regulation may differ accounting requirements companys nonregulated entities transactions recorded differently result regulatory accounting requirements include gsr costs recovered demand interruptible surcharge environmental costs recovered demand surcharge certain benefits costs taxes included expected included future rates including costs refinance debt accounting method followed prescribed allowed regulatory authority ratemaking purposes method conforms generally accepted accounting principle matching costs revenues apply cash temporary investments shortterm investments purchased original maturity three months less considered cash equivalents allowance doubtful accounts notes receivable company established provision losses accounts notes receivable well gas imbalances due shippers operators may become uncollectible collectibility reviewed regularly allowance adjusted necessary primarily specific identification method balances provision december 31 1998 1997 15 million 17 million respectively gas imbalances company values gas imbalances due shippers operators appropriate index price natural gas imbalances settled cash made inkind inventories consisting materials supplies natural gas storage valued lower cost market cost determined using average cost method property plant equipment included companys property plant equipment construction work progress approximately 392 million 276 million december 31 1998 1997 respectively allowance debt equity funds used construction regulated projects included cost companys property plant equipment accounting substantial portion property plant equipment subject regulation ferc objectives regulation ensure proper recovery capital investments rates recovery generally accomplished allowing return investment inclusion depreciation expense cost service rates also allow return net unrecovered rate base specific procedures prescribed ferc control capitalized costs depreciation disposal assets sfas 71 specifically acknowledges obligation regulated companies comply regulated accounting procedures even conflict generally accepted accounting principle pronouncements regulated property plant equipment recorded original cost construction acquisition cost first party committing asset utility services construction cost includes direct labor materials well indirect charges overheads allowance funds used construction replacements betterments major units property capitalized replacements additions minor units property expensed depreciation regulated property plant equipment calculated using composite method assets similar economic characteristics grouped depreciation rate prescribed rate settlement applied gross investment group net book value group equal salvage value currently depreciation rates vary 1 percent 33 percent results remaining economic lives groups ranging 2 36 years depreciation rates reevaluated conjunction rate making process regulated property plant equipment retired due abandonment replacement original cost plus cost retirement less salvage charged accumulated depreciation amortization gain loss recognized unless entire operating unit defined ferc retired gains losses dispositions operating units included income additional acquisition cost assigned utility plant primarily represents excess allocated purchase costs historical costs resulted december 1996 acquisition eptpc costs amortized straightline basis using ferc approved rates depreciation companys nonregulated properties provided using straight line composite method opinion management adequate allocate cost properties estimated useful lives nonregulated properties expected lives 5 40 years company evaluates impairment property plant equipment accordance sfas 121 accounting impairment longlived assets longlived assets disposed intangible assets intangible assets amortized using straightline method periods ranging 5 years 40 years accumulated amortization intangible assets 24 million 21 million 1998 1997 respectively company evaluates impairment goodwill accordance sfas 121 accounting impairment longlived assets longlived assets disposed environmental costs expenditures ongoing compliance environmental regulations relate current operations expensed capitalized appropriate expenditures relate existing condition caused past operations contribute current future revenue generation expensed liabilities recorded environmental assessments indicate remediation efforts probable costs reasonably estimated estimates liability based upon currently available facts existing technology presently enacted laws regulations taking consideration likely effects inflation societal economic factors include estimates associated legal costs available evidence considered including prior experience remediation contaminated sites companies cleanup experience data released epa organizations estimated liabilities subject revision future periods based actual costs new circumstances liabilities included balance sheets undiscounted amounts recoveries evaluated separately liability recovery assured recorded reported separately associated liability consolidated financial statements asset price risk management activities company utilizes derivative financial instruments manage market risks associated certain energy commodities interest rates commodity price risk management activities company engages trading nontrading activities trading purposes consist services provided energy sector energy trading activities including transportation capacity storage accounted using marktomarket method accounting trading activities conducted variety financial instruments including forward contracts involving cash settlement physical delivery energy commodity swap contracts require payments receipts counterparties based differential fixed variable price commodity exchangetrade options overthecounter options contractual arrangements marktomarket accounting commodity energy related contracts reflected estimated market value resulting gains losses recorded operating income consolidated statements income net gains losses recognized current period result primarily transactions originating within period impact price movements transactions originating previous periods assets liabilities resulting marktomarket accounting presented assets liabilities price risk management activities consolidated balance sheets terms regarding cash settlement contracts vary respect actual timing cash receipts payments receivables payables resulting timing differences presented accounts receivable accounts payable consolidated balance sheets cash inflows outflows associated price risk management activities recognized operating cash flow settlements transactions occur market value commodity energy related contracts reflects managements best estimate considering various factors including closing exchange overthecounter quotations time value volatility factors underlying commitments values adjusted reflect potential impact liquidating companys position orderly manner reasonable period time present market conditions derivative financial instruments also utilized connection nontrading activities company enters forwards swaps contracts hedge impact market fluctuations assets liabilities contractual commitments derivatives held nontrading price risk management activities recorded balance sheet net periodic settlements recorded gain loss operating income consolidated statements income cash inflows outflows recognized operating cash flow settlements transactions occur see note 5 discussion companys price risk management activities late 1998 emerging issues task force reached consensus supported companys accounting policy described income taxes income taxes based income reported tax return purposes along provision deferred income taxes deferred income taxes provided reflect tax consequences future years differences financial statement tax bases assets liabilities year end tax credits accounted flowthrough method reduces provision income taxes year tax credits first become available deferred tax assets reduced valuation allowance based upon managements estimates likely portion deferred tax assets realized future period estimates utilized recognition deferred tax assets subject revision future periods based new facts circumstances connection merger eptpc entered tax sharing agreement newport news shipbuilding inc new tenneco company successor epng tax sharing agreement provides among things allocation among parties tax assets liabilities arising prior result subsequent distributions generally eptpc liable taxes imposed respect periods prior consummation distributions case federal income taxes imposed combined activities old tenneco members consolidated group prior giving effect distributions new tenneco newport news shipbuilding inc liable eptpc federal income taxes attributable activities allocated agreedupon share estimated tax payments made eptpc old tenneco pursuant tax sharing agreement eptpc paid new tenneco 1997 tax benefits realized deduction 1996 taxable losses generated debt realignment accordance merger treasury stock treasury stock accounted using cost method shown reduction stockholders equity consolidated balance sheets treasury stock sold issued valued firstin firstout basis included treasury stock december 31 1998 1997 1360000 shares common stock reserved use certain companys benefit plans stockbased compensation allowed sfas 123 company elected continue apply provisions accounting principles board opinion 25 related interpretations accounting stock compensation plans company uses fixed variable plan accounting fixed variable compensation plans respectively accordingly compensation expense recognized stock options unless options granted exercise price lower market grant date new accounting pronouncements yet adopted see item 7 managements discussion analysis financial condition results operations new accounting pronouncements yet adopted incorporated herein reference 2 acquisitions deeptech august 1998 company completed acquisition deeptech merging deeptech subsidiary epec deeptechs assets include 273 percent ownership interest leviathan acquisition accounted purchase total purchase price approximately 422 million net cash acquired company recorded 214 million goodwill connection acquisition amortized using straightline method period 40 years amount allocated goodwill based estimate excess total purchase price fair value assets liabilities acquisition date amounts may adjusted final purchase price allocation management expect ultimate resolution purchase price allocation materially impact companys financial position results operations cash flows operating results deeptech included companys consolidated statements income beginning august 15 1998 components purchase price follows accordance deeptech merger agreement company executed guarantee regard deeptechs 12 senior notes due 2000 following table contains summarized financial information deeptech information twelve months ended june 30 1998 1997 1996 premerger periods information december 31 1998 postmerger period information six months ended december 31 1998 part postmerger part premerger unaudited b reflects allocation purchase price assets acquired liabilities assumed connection companys acquisition deeptech august 1998 tpc december 1997 company completed purchase gathering facilities consisting 360 miles natural gas pipeline natural gas cryogenic processing plant acquisition 100 percent stock tpc cash price approximately 195 million transaction accounted purchase gulf states october 1997 company completed acquisition gulf states gas pipeline company assets purchased include 175mile natural gas gathering intrastate transmission system northwest louisiana capacity 250 mmcfd purchase price approximately 39 million included issuance 21 million common stock company transaction accounted purchase eptpc december 12 1996 company completed acquisition eptpc transaction accounted purchase price assigned assets liabilities acquired based upon estimated fair value assets liabilities acquisition date substantially excess total purchase price historical carrying amounts net assets acquired allocated property plant equipment eptpcs interstate pipeline systems allocation confirmed independent appraisal property acquired merger old tenneco changed name eptpc prior merger old tenneco subsidiaries completed various intercompany transfers distributions restructured divided separated businesses assets liabilities assets liabilities operations related industrial business shipbuilding business spunoff old tennecos existing common stockholders distributions effected december 11 1996 pursuant distribution agreement dated november 1 1996 following distributions remaining operations old tenneco consisted primarily activities related transmission marketing natural gas results operations eptpc included companys consolidated statements income last 20 days 1996 october 30 1996 irs issued private letter ruling old tenneco ruled us federal income tax purposes distributions would taxfree old tenneco except extent cash received lieu fractional shares existing stockholders merger would constitute taxfree reorganization certain transactions effected connection merger distributions would taxfree distributions qualify taxfree distributions corporate level federal income tax would assessed consolidated group old tenneco common parent corporate level federal income tax would payable eptpc certain limited circumstances however new tenneco newport news shipbuilding inc agreed indemnify eptpc defined portion tax liabilities consideration paid company merger consisted retention merger approximately 26 billion debt preferred stock obligations old tenneco subject certain adjustments consisted part approximately 200 million public debt old tenneco outstanding effective time merger ii 21 billion debt old tenneco outstanding effective time merger 3 billion revolving credit competitive advance facility agreement dated november 4 1996 credit facility among old tenneco certain banks financial institutions chase manhattan bank agent iii 300 million old tenneco preferred stock issuance 376 million shares common stock company valued approximately 913 million based closing price per share common stock new york stock exchange 243125 december 9 1996 old tennecos existing common preferred stockholders retention approximately 600 million estimated liabilities related certain discontinued businesses old tenneco number shares companys common stock issued merger stockholders old tenneco determined pursuant formulas set forth merger agreement merger holder old tennecos common stock received 0186 share companys common stock share tenneco common stock ii holder old tennecos 740 cumulative preferred stock received 473 shares companys common stock share 740 cumulative preferred stock iii holder old tennecos 450 cumulative preferred stock received 473 shares companys common stock share 450 cumulative preferred stock december 31 1998 company owns 100 percent common equity 80 percent combined equity value eptpc remaining combined equity eptpc consists 300 million preferred stock issued public offering old tenneco november 18 1996 remains outstanding assets acquired liabilities assumed consideration received follows following unaudited pro forma information presents summary consolidated results operations would pro forma basis year ended december 31 1996 assuming eptpc acquisition effect throughout 1996 december 1996 subsequent merger tgp sold 70 percent interests two natural gas pipeline systems australia cngi australia pty limited wholly owned indirect subsidiary consolidated natural gas company four australian investors approximately 400 million inclusive related debt financing completed sale oil gas exploration production financing unit formerly known tenneco ventures approximately 105 million consideration purchase price allocation adjustments gain loss recognized transactions effective june 1996 company acquired cornerstone natural gas inc transaction accounted purchase price approximately 94 million exclusive acquisition costs financed internally generated funds shortterm borrowings acquisition costs approximately 5 million capitalized cost acquisition allocated basis estimated fair value assets acquired liabilities assumed resulting goodwill approximately 59 million amortized 40 years using straightline method results operations cornerstone natural gas inc included companys consolidated statements income beginning june 1996 3 trust preferred securities march 1998 el paso energy capital trust issued 65 million 4 34 trust convertible preferred securities trust preferred securities 325 million 317 million net issuance costs addition trust issued trust convertible common securities approximately 10 million epng net proceeds used epng pay commercial paper trust exists sole purpose issuing trust preferred securities investing proceeds 4 34 convertible subordinated debentures due 2028 trust debentures epng trusts sole asset epng executed guarantee regard trust preferred securities guarantee taken together epngs obligations trust debentures indenture pursuant trust debentures issued applicable trust document provides full unconditional guarantee trusts obligations trust preferred securities result holding company reorganization discussed note 1 epec assumed ownership trust well obligations trust debentures guarantee trusts obligations trust preferred securities results trust consolidated company therefore trust debentures eliminated trust preferred securities reflected companyobligated mandatorily redeemable convertible preferred securities el paso energy capital trust consolidated balance sheets distributions trust preferred securities included interest debt expense consolidated statements income trust preferred securities nonvoting except limited circumstances pay quarterly distributions annual rate 4 34 commencing june 30 1998 carry liquidation value 50 per security plus accrued unpaid distributions convertible companys common shares time prior close business march 31 2028 option holder rate 12022 common shares trust preferred security equivalent conversion price 4159 per common share subject adjustment certain circumstances 4 financing transactions average interest rate shortterm borrowings 58 59 december 31 1998 1997 respectively company shortterm borrowings including current maturities longterm debt december 31 1998 december 31 1997 follows longterm debt outstanding december 31 1998 1997 consisted following aggregate maturities longterm debt next 5 years total thereafter financing arrangements october 1997 epng established new 750 million fiveyear revolving credit competitive advance facility new 750 million 364day renewable revolving credit competitive advance facility connection establishment revolving credit facility eptpcs revolving credit facility also terminated outstanding balance 417 million financed fiveyear portion new revolving credit facility tgp designated borrower availability revolving credit facility expected used general corporate purposes including limited backstopping epngs tgps 1 billion commercial paper programs august 1998 epec became guarantor revolving credit facility october 1998 750 million 364day portion revolving credit facility amended extend termination date october 27 1999 addition october 1998 revolving credit facility amended permit tgp issue commercial paper provided total amount commercial paper outstanding epng tgp equal less unused capacity revolving credit facility december 1998 epec became borrower revolving credit facility interest rate 40 basis points libor spread varying based epecs longterm debt credit rating availability borrowings companys credit agreements subject specified conditions management believes company currently meets conditions include compliance financial covenants ratios required agreements absence default agreements continued accuracy representations warranties contained agreements including absence material adverse changes since specified dates companys senior debt issues given investment grade ratings standard poors moodys company must comply various restrictive covenants contained debt agreements include among others maintaining consolidated debt guarantees capitalization ratio greater 70 percent addition companys subsidiaries consolidated basis defined agreements may incur debt obligations would exceed 300 million aggregate excluding acquisition debt project financing certain refinancings december 31 1998 epecs consolidated debt guarantees capitalization ratio defined agreements 55 percent debt obligations epec subsidiaries excess permitted debt exceed 300 million consolidated basis march 1997 tgp issued 300 million aggregate principal amount 7 12 debentures due 2017 300 million aggregate principal amount 7 debentures due 2027 300 million aggregate principal amount 7 58 debentures due 2037 proceeds approximately 883 million net issuance costs used repay portion eptpcs credit facility general corporate purposes december 1997 epec filed shelf registration statement pursuant epec may offer 900 million including 250 million transferred prior shelf registrations common preferred equities various forms debt securities including convertible debt securities various types trust securities time determined market conditions march 1998 el paso energy capital trust delaware business trust sponsored company issued 65 million 4 34 trust convertible preferred securities sole assets trust approximately 335 million principal amount 4 34 convertible subordinated debentures due 2028 company result offering epec approximately 565 million capacity remaining existing shelf registration issue public securities registered thereunder september 1998 tgp filed shelf registration permitting tgp offer 600 million including 100 million carried forward prior shelf registration debt securities october 1998 tgp issued 400 million aggregate principal amount 7 debentures due 2028 proceeds tgp approximately 391 million net issuance cost approximately 300 million proceeds used repay tgps shortterm indebtedness revolving credit facility remainder used tgp general corporate purposes issuance tgp 200 million capacity remaining shelf registration march 1998 epng retired outstanding 8 58 debentures amount 17 million august 1998 eptpc retired outstanding 10 debentures amount 38 million february 1999 deeptech retired 11 senior subordinated promissory note due 2000 amount 16 million 5 financial instruments price risk management activities fair value financial instruments following disclosure estimated fair value financial instruments presented accordance requirements sfas 107 estimated fair value amounts determined company using available market information valuation methodologies december 31 1998 1997 carrying amounts certain financial instruments held company including cash equivalents shortterm borrowings investments trade receivables payables representative fair value shortterm maturity instruments fair value longterm debt variable interest rates carrying value variable nature respective debts interest rate fair value debt fixed interest rates estimated based quoted market prices similar issues project financing debt market interest rates therefore fair value project financing debt representative carrying amount fair value derivative financial instruments estimated amount management believes instruments could liquidated reasonable period time based quoted market prices current market conditions estimates obtained thirdparty brokers dealers following table reflects carrying amount estimated fair value companys financial instruments december 31 trading commodity activities company merchant services business offers integrated price risk management services energy sector services primarily relate energy related commodities including natural gas power petroleum products company provides services variety contracts entered trading purposes including forward contracts involving cash settlements physical delivery energy commodity swap contracts require payments receipt payments counterparties based differential fixed variable price commodity options contractual arrangements company recognized gross margin 40 million 17 million 1998 1997 respectively arising trading activities fair value commodity energy related contracts entered trading purposes december 31 1998 1997 average fair value instruments held years ended december 31 1998 1997 set forth december 31 1998 92 million assets price risk management activities included assets 42 million liabilities price risk management activities included liabilities consolidated balance sheets computed using net asset balance month end notional amounts terms notional amounts terms financial instruments december 31 1998 1997 set forth natural gas volumes trillions british thermal units power volumes millions megawatt hours petroleum products volumes millions british thermal units notional amounts reflect volume transactions represent amounts exchanged parties accordingly notional amounts incomplete measure companys exposure market credit risks maximum terms years detailed indicative likely future cash flows positions may offset cashedout markets time based companys risk management needs liquidity commodity markets weighted average maturity companys entire portfolio price risk management activities approximately two years december 31 1998 1997 respectively market credit risks company serves diverse customer group includes independent power producers industrial companies gas electric utilities oil gas producers financial institutions energy marketers broad customer mix generates need variety financial structures products terms diversity requires company manage portfolio basis resulting market risks inherent transactions subject parameters established companys risk management committee market risks monitored risk control committee operating independently units create actively manage risk exposures ensure compliance companys stated risk management policies company measures adjusts risk portfolio accordance marktomarket risk management methodologies utilize forward price curves energy markets estimate size probability future potential exposure credit risk relates risk loss company would incur result nonperformance counterparties pursuant terms contractual obligations company maintains credit policies regard counterparties minimize overall credit risk policies require evaluation potential counterparties financial condition including credit rating collateral requirements certain circumstances including cash advance letters credit parental guarantees use standardized agreements allow netting positive negative exposures associated single counterparty counterparties associated companys assets price risk management activities december 31 1998 1997 summarized follows investment grade primarily determined using publicly available credit ratings along consideration collateral encompass standby letters credit parent company guarantees property interest including oil gas reserves included investment grade counterparties minimum standard poors moodys rating bbb baa3 respectively minimum implied internal credit analysis standard poors equivalent rating bbb b two customers exposure december 31 1998 1997 comprise greater 5 percent assets price risk management activities customers investment grade ratings concentration counterparties may impact companys overall exposure credit risk either positively negatively counterparties may similarly affected changes economic regulatory conditions based companys policies risk exposure reserves company anticipate material adverse effect financial position results operations cash flows result counterparty nonperformance nontrading price risk management activities mpc entered interest rate swap agreements effectively convert 114 million floatingrate debt fixedrate debt see note 4 mpc makes payments counterparties fixed rates return receives payments floating rates two swap agreements entered march 1992 remaining terms approximately 1 year 3 years respectively transaction recorded using accrual accounting interest expense cash requirements 3 million higher 1998 1997 1996 respectively result swaps march 1997 company purchased 105 percent interest capsa privately held argentine company engaged power generation oil gas production approximately 57 million connection acquisition company entered equity swap transaction associated additional 185 percent capsas outstanding stock swap company pays interest counterparty quarterly basis notional amount 100 million rate libor plus 085 percent exchange company receives dividends capsa stock extent counterpartys equity interest 185 percent company also fully participates market appreciation depreciation underlying investment whereby company realize appreciation fund depreciation attributable actual sale stock upon termination expiration swap transaction initial term swap two years february 1999 extended additional two onehalf years upon maturity termination swap company right first refusal purchase counterpartys 185 percent investment capsa common stock fair value stock date later date price offered good faith buyer transaction recorded using marktomarket accounting 6 commitments contingencies see item 7 managements discussion analysis financial condition results operations commitments contingencies environmental incorporated herein reference 7 income taxes following table reflects components income tax expense years ended december 31 tax expense company differs amount computed applying statutory federal income tax rate 35 percent income taxes following table outlines reasons differences periods ended december 31 following table reflects components net deferred tax liability december 31 december 31 1998 1 million noncurrent foreign deferred income taxes included assets consolidated balance sheets cumulative undistributed earnings certain foreign subsidiaries foreign corporate joint ventures approximately 35 million december 31 1998 since earnings intended indefinitely reinvested foreign operations provision made us taxes foreign withholding taxes may applicable upon actual deemed repatriation distribution earnings made company may subject foreign withholding taxes us income taxes net allowable foreign tax credits deductions however estimate taxes practicable reasons company provided us taxes foreign currency translation adjustments recognized comprehensive income tax benefit associated exercise nonqualified stock options restricted stock well restricted stock dividends reduced taxes payable 9 million 1998 11 million 1997 benefits included additional paidin capital consolidated balance sheets december 31 1998 approximately 45 million alternative minimum tax credits available offset future regular tax liabilities alternative minimum tax credit carryovers expiration date additionally december 31 1998 approximately 1 million general business credit 102 million net operating loss 9 million capital loss carryovers available offset future tax liabilities general business credit carryovers expire years 1999 2000 approximately 57 million net operating loss carryovers expire 2012 remaining 45 million expire years 2004 2011 usage carryovers subject limitations provided sections 382 383 internal revenue code well separate return limitation year rules irs regulations company recorded valuation allowance reflect estimated amount deferred tax assets may realized due expiration net operating loss tax credit carryovers december 31 1998 1997 approximately 4 million 8 million respectively valuation allowance relates net operating loss carryovers acquired company remainder valuation allowance relates general business credit carryovers acquired company tax benefits subsequently recognized reversal valuation allowance allocated goodwill prior 1999 eptpc subsidiaries filed consolidated federal income tax return epec subsidiaries filed separate consolidated federal income tax return result taxfree reorganization described note 1 starting 1999 epec subsidiaries including eptpc subsidiaries file one consolidated federal income tax return deferred taxes corresponding allocation purchase price assets liabilities acquired eptpc reflected consolidated balance sheets december 31 1998 1997 8 capital stock common stock october 1997 approximately 8 million shares company common stock issued connection acquisition gulf states gas pipeline company shares valued approximately 21 million february 1997 approximately 6 million shares company common stock issued public offering registered securities act 1933 amended proceeds 152 million net issuance costs received used repay borrowings revolving credit facility december 1996 376 million shares company common stock issued connection acquisition eptpc shares valued approximately 913 million treasury stock time board authorized repurchase epecs outstanding shares common stock used connection epec employee stockbased compensation plans corporate purposes 1998 company repurchased 995600 common shares weighted average cost 3577 per share december 31 1998 1997 epec held 4149099 2946832 shares treasury stock respectively included balance december 31 1998 1360000 shares treasury stock used secure benefits certain companys benefit plans subject certain restrictions stock dividend january 1998 board declared twoforone stock split form 100 percent stock dividend per share basis march 1998 stockholders approved increase companys authorized common stock dividend aggregate 60944417 shares common stock paid april 1 1998 stockholders record march 13 1998 presentations herein made postsplit basis epec 25000000 shares authorized preferred stock par value 001 per share none issued 2750000 shares designated series junior participating preferred stock reserved issuance pursuant companys preferred stock purchase rights plan 9 stockbased compensation 1998 1997 1996 company granted stock options various stock option plans company applies accounting principles board opinion 25 related interpretations accounting plans 1995 financial accounting standards board issued sfas 123 accounting stockbased compensation fully adopted changes methods companies apply determining expense related stock option plans adoption expense recognition provisions sfas 123 optional company elected apply provisions sfas 123 however pro forma disclosures company adopted expense recognition provisions sfas 123 presented companys existing stock option plans company authorized issue shares common stock employees nonemployee directors pursuant awards granted incentive stock options intended qualify section 422 internal revenue code nonqualified stock options restricted stock appreciation rights sars performance units nonqualified stock options company granted nonqualified stock options 1998 1997 1996 stock option plans stock options granted periods contractual terms 10 years generally vest completion one five years continuous employment grant date options also granted nonemployee members board fair market value date grant exercisable immediately terms certain plans epec may grant sars certain holders stock options sars subject terms conditions related stock options december 31 1998 50538 sars outstanding included stock options part tandem awards stock option holder granted tandem sars elect exercise either option sar sars entitle option holder receive payment equal difference option price fair market value common stock epec date exercise sar extent sar exercised related option canceled extent option exercised related sar canceled currently sars accounted compensation expense accounting principles board opinion 25 considered purposes computing fair value outstanding options using blackscholes option pricing model described summary status companys stock options december 31 1998 1997 1996 presented fair value stock option granted estimated date grant using blackscholes optionpricing model following weightedaverage assumptions blackscholes weighted average fair value options granted 1998 1997 1996 follows options outstanding december 31 1998 summarized restricted stock companys various stockbased compensation plans limited number shares restricted company common stock may granted cost certain key officers employees shares carry voting dividend rights however sale transfer shares restricted accordance vesting procedures restricted stock awards vest specific period time andor company achieves certain performance targets restricted stock awards representing 5 million 7 million 32 million shares granted 1998 1997 1996 respectively weighted average grant date fair value 3229 2853 1882 per share respectively december 31 1998 45 million shares restricted stock outstanding value shares determined based fair market value measurement dates charged compensation expense ratably restriction period based number shares earned vesting period 1998 1997 1996 charges totaled 27 million 19 million 5 million respectively unamortized balance recorded reduction stockholders equity consolidated balance sheets performance units certain employees officers company awarded performance units payable cash stock end vesting period final value performance units may vary according plan granted usually based companys common stock price end vesting period value performance units charged ratably compensation expense vesting period periodic adjustments account fluctuation market price companys stock amounts charged compensation expense 1998 1997 1996 13 million 5 million 5 million respectively pro forma net income net income per common share compensation expense companys stockbased compensation plans determined applying provisions sfas 123 companys net income net income per common share 1998 1997 1996 would approximate pro forma amounts effects applying sfas 123 pro forma disclosure indicative future amounts sfas 123 apply awards granted prior 1995 fiscal year december 31 1998 211 million shares common stock reserved issuance pursuant existing future stock awards approximately 54 million shares remain reserved 10 retirement benefits pension benefits prior january 1 1997 company maintained defined benefit pension plan covering substantially employees epng epfs pension benefits based years credited service final 5year average compensation subject maximum limitations defined pension plan 1996 company recognized 21 million charge pension expense related early retirement window workforce reductions effective january 1 1997 plan amended provide benefits determined cash balance formula include employees added result merger acquisitions prior 1997 employees participants december 31 1996 receive greater cash balance benefits prior plan benefits accrued december 31 2001 1997 company offered special termination benefits employees added result merger least 55 years old eligible retire tenneco inc retirement plan december 31 1996 eligible employees accepting offer retiring july 1 1997 received cash balance credit based enhanced formula exceed one years base salary cost associated special termination benefits accrued december 31 1996 part liabilities assumed merger 1997 company funded 11 million special termination benefits postretirement benefits epng provides postretirement medical benefits closed group employees retired march 1 1986 limited postretirement life insurance employees retired january 1 1985 epngs obligation accrue postretirement employee benefits opeb primarily limited fixed population retirees retired march 1 1986 medical plan prefunded extent employer contributions recoverable rates extent actual opeb costs differ amounts recovered rates regulatory asset liability recorded result merger eptpc retained responsibility certain postretirement medical life insurance benefits former employees operations previously disposed old tenneco employees including tgp employees added result merger eligible retire december 31 1996 july 1 1997 medical benefits closed group retirees may subject deductibles copayment provisions limitations dollar caps amount employer costs eptpc reserved right change benefits employees retired july 1 1997 continue receive limited postretirement life insurance benefits tgps postretirement benefit plan costs prefunded extent costs recoverable rates effective february 1 1992 tgp began recovering rates opeb costs included june 2 1993 rate case settlement agreement extent actual opeb costs differ amounts funded regulatory asset liability recorded several plan amendments made effective january 1 1998 including increases deductibles increases outofpocket limits changes prescription drug provisions changes resulted 25 million decrease postretirement benefits obligation following table sets forth change benefit obligation change plan assets funded status components net periodic benefit cost pension benefits postretirement benefits 1998 company changed measurement date measuring pension opeb obligations december 31 september 30 traditionally timing receipt information limited companys ability maximize planning budgeting opportunities respect projected costs various plans company changed benefit reporting date facilitate planning process gather necessary financial reporting information timely manner management believes date change preferable method previously employed change measurement date accounted change accounting principle material cumulative effect retirement benefit expense current prior periods december 31 1998 1997 current liability portion postretirement benefits 39 million 33 million respectively benefit obligations based upon certain actuarial estimates described actuarial estimates companys postretirement benefits plans assumed weighted average annual rate increase per capita costs covered health care benefits 10 percent 2000 gradually decreasing 6 percent year 2008 assumed health care cost trends significant effect amounts reported postretirement benefit plans onepercentage point change assumed health care cost trends would following effects retirement savings plan company maintains defined contribution plan covering employees company first six months 1996 company made matching contributions equal participants basic contributions 6 percent participant fewer 10 years employment company 8 percent participant 10 years employment company february 1996 company changed matching contribution 75 percent participants basic contributions 6 percent matching contribution made company stock amounts expensed plan approximately 9 million 9 million 4 million years ended december 31 1998 1997 1996 respectively 11 employee separation asset impairment charge first quarter 1996 company adopted program reduce operating costs work force reductions improved work processes adopted sfas 121 accounting impairment longlived assets longlived assets disposed result workforce reduction program adoption sfas 121 company recorded special charge 99 million 47 million employee separation costs 52 million asset impairments first quarter 1996 employee separation charge included approximately 26 million expected severancerelated costs 21 million pension costs related special termination benefits work force reductions special charge pensionrelated costs cash impact outside normal funding companys pension plan accordance sfas 121 company determined fair value certain assets based discounted future cash flows resultant noncash charge asset impairments included approximately 44 million impairment certain natural gas gathering processing production facilities 8 million writeoff regulatory asset established upon adoption sfas 112 employers accounting postemployment benefits recoverable companys rate settlement filed ferc march 1996 12 preferred stock subsidiary november 1996 eptpc issued 6 million shares 8 14 cumulative preferred stock par value 50 per share 296 million net issuance costs preferred stock redeemable option eptpc december 31 2001 redemption price equal 50 per share plus dividends accrued unpaid date redemption 1998 1997 1996 dividends approximately 25 million 25 million 3 million respectively paid cumulative preferred stock approximately 2 million reflected 1996 minority interest 20 days eptpc included consolidated statements income 13 segment information company adopted provisions sfas 131 disclosures segments enterprise related information effective january 1 1998 accordingly company segregated business activities five segments tennessee gas pipeline segment el paso natural gas segment el paso field services segment el paso energy marketing segment el paso energy international segment segments strategic business units offer variety different energy products services managed separately business requires different technology marketing strategies tennessee gas pipeline segment includes interstate pipeline systems tgp midwestern east tennessee transports natural gas northeast midwest midatlantic sections us including states tennessee virginia georgia well new york city chicago boston metropolitan areas el paso natural gas segment includes interstate pipeline systems epng mpc transports natural gas primarily california market el paso field services segment provides natural gas gathering products extraction dehydration purification compression intrastate transmission services el paso energy marketing segment markets trades natural gas power petroleum products participates development ownership domestic power generation projects el paso energy international segment develops operates energy infrastructure facilities worldwide accounting policies individual segments company whole described note 1 certain business segments earnings largely derived earnings equity investments reported net consolidated statements income accordingly company evaluates segment performance based ebit extent practicable results operations years ended december 31 1997 1996 reclassified conform current business segment presentation although results necessarily indicative results would achieved revised business segment structure effect period reconciliations revenues reportable segments total consolidated revenues presented reconciliations net reportable segments total consolidated net presented reconciliations ebit income taxes minority interest presented reconciliations assets reportable segments total consolidated assets presented company gross revenue customer equal excess ten percent consolidated operating revenue years ended december 31 1998 1997 1996 14 inventories consisted following december 31 15 property plant equipment property plant equipment consisted following december 31 16 earnings per share march 1997 financial accounting standards board issued sfas 128 earnings per share establishes new guidelines calculating earnings per share pronouncement effective reporting periods ending december 15 1997 sfas 128 requires companies present basic diluted earnings per share amount face statement income restate prior period earnings per share amounts comply standard basic diluted earnings per share amounts calculated accordance sfas 128 presented years ended december 31 17 supplemental cash flow information following table contains supplemental cash flow information years ended december 31 see note 2 discussion noncash investing transactions related certain acquisitions 18 investment affiliated companies unaudited company holds investments various affiliates accounted equity method accounting principal equity method investments companys investments international pipelines interstate pipelines power generation plants gathering systems natural gas storage facilities summarized financial information companys proportionate share 50 percent less owned companies majority owned unconsolidated subsidiaries accounted equity method accounting follows 19 supplemental selected quarterly financial information unaudited financial information quarter summarized opinion management adjustments necessary fair presentation made report independent accountants board directors stockholders el paso energy corporation opinion consolidated financial statements listed index appearing item 14a 1 present fairly material respects consolidated financial position el paso energy corporation december 31 1998 1997 consolidated results operations cash flows three years period ended december 31 1998 conformity generally accepted accounting principles addition opinion financial statement schedule listed index appearing item 14a 2 presents fairly material respects information set forth therein read conjunction related consolidated financial statements financial statements financial statement schedule responsibility companys management responsibility express opinion financial statements financial statement schedule based audits conducted audits statements accordance generally accepted auditing standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements assessing accounting principles used significant estimates made management evaluating overall financial statement presentation believe audits provide reasonable basis opinions expressed pricewaterhousecoopers llp houston texas march 9 1999 schedule ii el paso energy corporation valuation qualifying accounts years ended december 31 1998 1997 1996 millions primarily accounts written b due acquisition gulf states gas pipeline company c primarily due acquisition eptpc item 9item 8 financial statements supplementary data el paso energy corporation consolidated statements income millions except per common share amounts accompanying notes integral part consolidated financial statements el paso energy corporation consolidated balance sheets millions except common share amounts accompanying notes integral part consolidated financial statements el paso energy corporation consolidated statements cash flows millions accompanying notes integral part consolidated financial statements el paso energy corporation consolidated statements stockholders equity millions except per common share amounts accompanying notes integral part consolidated financial statements el paso energy corporation notes consolidated financial statements 1 summary significant accounting policies basis presentation principles consolidation consolidated financial statements company include accounts majorityowned controlled subsidiaries elimination significant intercompany accounts transactions investments companies company ability exert significant influence control operating financial policies accounted using equity method consolidated financial statements previous periods include certain reclassifications made conform current year presentation reclassifications impact reported net income stockholders equity holding company reorganization effective august 1 1998 company reorganized holding company organizational structure whereby el paso became holding company transaction el paso energy merger company wholly owned subsidiary el paso merged epng surviving corporation virtue reorganization epng became direct wholly owned subsidiary el paso epngs outstanding capital stock converted share basis capital stock el paso epngs outstanding preferred stock purchase rights also exchanged onehalf outstanding preferred stock purchase right epng converted one preferred stock purchase right el paso common stock right representing right purchase one twohundredth subject adjustment share series junior participating preferred stock el paso reorganization companies common control stockholders equity components thereof epng became basis el paso stockholders equity el paso also assumed ownership trust defined note 12 epngs obligations related trust see note 12 trust preferred securities discussion finally el paso became successor epngs previous shelf registration amount 565 million new york stock exchange ticker symbol used el paso following reorganization remains unchanged epg taxfree internal reorganization december 31 1998 following companys merger sonat company effected internal reorganization assets operations certain subsidiaries reorganizations certain subsidiaries transferred el paso andor entities owned el paso internal reorganization impact presentation herein stock split january 21 1998 board approved twoforone stock split epngs common stock split stock split effected form stock dividend aggregate 60944417 shares epngs common stock paid april 1998 common shares per common share amounts presented herein reflect stock split use estimates preparation financial statements conformity generally accepted accounting principles requires management make estimates assumptions affect reported amounts assets liabilities revenues expenses disclosure contingent assets liabilities exist date financial statements actual results likely differ estimates accounting regulated operations companys interstate natural gas systems subject jurisdiction ferc accordance natural gas act 1938 natural gas policy act 1978 system operates separate ferc approved tariffs establish rates terms conditions system provides services customers companys businesses subject regulations accounting requirements ferc followed accounting requirements sfas 71 accounting effects certain types regulation may differ accounting requirements companys nonregulated entities transactions recorded differently result regulatory accounting requirements include gsr costs recovered demand interruptible surcharge environmental costs recovered demand surcharge capitalization equity return component regulated capital projects certain benefits costs taxes included expected included future rates including costs refinance debt accounting method followed prescribed allowed regulatory authority ratemaking purposes method conforms generally accepted accounting principle matching costs revenues apply changes regulatory economic environment may create point future circumstances application regulatory accounting principles longer appropriate factors could impact assessment include inability recover cost increases rate caps rate case moratoriums inability recover capitalized costs including adequate return costs ratemaking process excess capacity significant discounting rates markets served company impacts ongoing initiatives deregulation natural gas industry factors cause regulatory accounting principles longer applied amount would charged earnings extraordinary item december 31 1999 amount estimated approximately 100 million net income taxes potential charge would noncash would direct effect regulated companies ability seek recovery underlying deferred costs future rate proceedings ability collect rates set thereby cash equivalents shortterm investments purchased original maturity three months less considered cash equivalents allowance doubtful accounts notes receivable company established provision losses accounts notes may become uncollectible collectibility reviewed regularly allowance adjusted necessary primarily specific identification method december 31 1999 1998 allowance 29 million 23 million respectively gas imbalances company values gas imbalances due shippers operators appropriate index price gas imbalances represent difference gas receipts gas deliveries companys transportation storage customers gas imbalances arise customers deliver less gas pipeline take natural gas imbalances settled cash made inkind subject pipelines various terms materials supplies materials supplies valued lower cost market cost determined using average cost method property plant equipment companys regulated property plant equipment subject oversight ferc objectives regulation ensure proper recovery capital investments rates recovery generally accomplished allowing return investment inclusion depreciation expense cost service rates also allow return net unrecovered rate base specific procedures prescribed ferc control capitalized costs depreciation disposal assets sfas 71 specifically acknowledges obligation regulated companies comply regulated accounting procedures even conflict generally accepted accounting principle pronouncements regulated property plant equipment recorded original cost construction acquisition cost first party committing asset utility service construction cost includes direct labor materials well indirect charges overhead allowance debt equity funds used construction replacements betterments major units property capitalized replacements additions minor units property expensed depreciation regulated property plant equipment calculated using composite method assets similar economic characteristics grouped depreciation rate prescribed rate settlement applied gross investment group net book value group equal salvage value currently depreciation rates vary 1 percent 33 percent results remaining economic lives groups ranging 2 36 years depreciation rates reevaluated conjunction rate making process regulated property plant equipment retired due abandonment replacement original cost plus cost retirement less salvage charged accumulated depreciation amortization gain loss recognized unless entire operating unit defined ferc retired gains losses dispositions operating units included income additional acquisition cost assigned utility plant primarily represents excess allocated purchase costs historical costs facilities costs amortized straightline basis using ferc approved rates cost companys nonregulated property plant equipment based original cost construction acquisition fair value assets acquired construction costs include direct costs project well indirect charges including capitalized interest costs debt depreciation properties provided using straight line composite method opinion management adequate allocate cost properties estimated useful lives nonregulated properties expected lives 5 40 years properties retired due abandonment replacement original cost plus retirement cost less salvage charged gain loss income included companys property plant equipment construction work progress approximately 597 million 353 million december 31 1999 1998 respectively company evaluates impairment regulated nonregulated property plant equipment accordance sfas 121 accounting impairment longlived assets longlived assets disposed natural gas oil properties company uses full cost method accounting natural gas oil properties full cost method productive nonproductive costs incurred connection acquisition exploration development natural gas oil reserves capitalized amortized unitofproduction method using proved reserves costs include costs unproved properties internal costs directly related acquisition exploration activities including capitalized interest general administrative costs well production costs expensed incurred certain unevaluated properties excluded amortization base determination made existence proved reserves capitalized costs subject quarterly ceiling test limits costs aggregate present value future net revenues discounted 10 percent plus lower cost fair market value unproved properties conveyance properties treated adjustment cost natural gas oil properties gain loss recognized unless properties sold significant revenue recognition companys regulated businesses recognize revenues natural gas transportation period service provided reserves provided revenues collected subject refund appropriate revenues services transportation recorded earned revenues companys nonregulated businesses recorded various points earned including deliveries physical commodities made period services provided companys revenue recognition policy trading portfolio see discussion price risk management activities intangible assets intangible assets amortized using straightline method periods ranging 5 40 years accumulated amortization intangible assets 39 million 24 million december 31 1999 1998 respectively response fundamental shift strategy direction companys merchant energy activities company changed estimated useful life goodwill related 1995 acquisitions eastex energy inc premier gas company change made reported net loss diluted loss per share company year ended december 31 1999 would 236 million 104 respectively company evaluates impairment goodwill accordance sfas 121 accounting impairment longlived assets longlived assets disposed methodology event occurs suggest impairment may occurred company evaluates undiscounted net cash flows underlying asset entity cash flows sufficient recover value underlying asset entity plus goodwill amount cash flows discounted riskadjusted rate difference recorded impairment consolidated statements income environmental costs expenditures ongoing compliance environmental regulations relate current operations expensed capitalized appropriate expenditures relate existing condition caused past operations contribute current future revenue generation expensed liabilities recorded environmental assessments indicate remediation efforts probable costs reasonably estimated estimates liability based upon currently available facts existing technology presently enacted laws regulations taking consideration likely effects inflation societal economic factors include estimates associated legal costs amounts also consider prior experience remediating contaminated sites companies cleanup experience data released epa organizations estimated liabilities subject revision future periods based actual costs new circumstances included balance sheets undiscounted amounts recoveries evaluated separately liability recovery assured recorded reported separately associated liability consolidated financial statements asset price risk management activities company utilizes derivative financial instruments manage market risks associated certain energy commodities interest rates foreign currency exchange rates commodity price risk management activities company engages trading nontrading activities trading purposes consist services provided energy sector energy trading activities including transportation capacity storage accounted using marktomarket method trading activities conducted variety financial instruments including exchange traded futures contracts involving cash settlement forward contracts involving cash settlement physical delivery energy commodity swap contracts require payments receipts counterparties based differential fixed variable prices commodity exchangetraded overthecounter options contractual arrangements marktomarket method accounting commodity energy related contracts reflected quoted estimated market value resulting gains losses included operating income consolidated statements income net gains losses recognized period result primarily transactions originating within period impact price movements transactions originating previous periods assets liabilities resulting marktomarket accounting included consolidated balance sheets according term maturity terms regarding cash settlement contracts vary respect actual timing cash receipts payments receivables payables resulting timing differences presented accounts receivable accounts payable consolidated balance sheets cash inflows outflows associated price risk management activities recognized operating cash flow settlement transactions occurs market value commodity energy related contracts reflect managements best estimate considering various factors including closing exchange overthecounter quotations time value volatility factors underlying commitments values adjusted reflect potential impact liquidating companys position orderly manner reasonable period time present market conditions reflect types risks including model risk credit risk operational risks absence quoted market prices company utilizes valuation techniques estimate fair value use techniques requires company make estimations future prices variables including market volatility price correlation market liquidity changes estimates could significant impact underlying market valuation could materially impact estimates derivative financial instruments also utilized connection nontrading activities company enters forwards swaps contracts hedge impact market fluctuations assets liabilities contractual commitments hedge accounting applied derivative reduces risk underlying hedge item designated hedge inception expected result financial impacts inversely correlated items hedged correlation ceases exist hedge accounting terminated marktomarket accounting applied changes market value hedged transactions deferred gain loss hedged item recognized derivatives held nontrading price risk management activities recorded gain loss operating income cash inflows outflows recognized operating cash flow settlement transactions occurs see note 7 discussion companys price risk management activities income taxes income taxes based income reported tax return purposes along provision deferred income taxes deferred income taxes provided reflect tax consequences future years differences financial statement tax bases assets liabilities year end tax credits accounted flowthrough method reduces provision income taxes year tax credits first become available deferred tax assets reduced valuation allowance based upon managements estimates likely portion assets realized future period estimates utilized recognition deferred tax assets subject revision future periods based new facts circumstances treasury stock treasury stock accounted using cost method shown reduction stockholders equity consolidated balance sheets treasury stock sold issued valued firstin firstout basis included treasury stock december 31 1999 1998 1360000 shares common stock reserved use certain companys benefit plans well 5845269 shares common stock placed trust companys deferred compensation programs stockbased compensation company applies provisions accounting principles board opinion 25 related interpretations accounting stock compensation plans accordingly compensation expense recognized stock options unless options granted exercise price lower market grant date company uses fixed variable plan accounting fixed variable compensation plans respectively cumulative effect accounting change april 1998 american institute certified public accountants issued statement position 985 reporting costs startup activities statement defines startup activities requires startup organization costs expensed incurred addition requires cost exists balance sheet expensed upon adoption pronouncement company adopted pronouncement effective january 1 1999 reported charge 13 million net income taxes first quarter 1999 cumulative effect accounting change accounting derivative instruments hedging activities june 1998 statement financial accounting standards sfas 133 accounting derivative instruments hedging activities issued financial accounting standards board establish accounting reporting standards derivative instruments including certain derivative instruments embedded contracts hedging activities pronouncement requires entity classify derivatives either assets liabilities statement financial position measure instruments fair value certain conditions met derivative may specifically designated hedge exposure changes fair value recognized asset liability unrecognized firm commitment ii hedge exposure variable cash flows forecasted transaction iii hedge foreign currency exposure net investment foreign operation unrecognized firm commitment availableforsale security foreigncurrencydenominated forecasted transaction sfas 133 accounting changes fair value derivative depends intended use resulting designation standard amended sfas 137 june 1999 amendment defers effective date sfas 133 fiscal years beginning june 15 2000 company currently evaluating effects pronouncement 2 acquisitions sonat october 25 1999 company completed merger sonat diversified energy holding company engaged domestic oil natural gas exploration production transmission storage natural gas natural gas power marketing merger one share companys common stock issued exchange share sonat common stock total common shares issued merger approximately 110 million addition company retained approximately 23 billion sonat debt transaction valued approximately 68 billion based companys closing stock price october 25 1999 merger accounted pooling interests therefore consolidated financial statements financial information included annual report periods prior merger include combined historical financial results el paso sonat following table presents revenues net income loss previously separate companies combined amounts presented consolidated financial statements certain adjustments made conform accounting presentation financial information connection merger company ordered federal trade commission sell east tennessee natural gas company sea robin pipeline company onethird interest destin pipeline company proceeds sales expected approximately 618 million sales anticipated close first quarter 2000 pending federal trade commission approval company treat gains arise sales extraordinary items net taxes consolidated statements income east asia power february 1999 company acquired 46 percent ownership interest eaprc along interest convertible loan following acquisition company converted loan equity increasing ownership interest 65 percent september 1999 company acquired additional 17 percent another shareholder increasing ownership interest 82 percent december 1999 international participated eaprc rights offering increasing overall ownership 92 percent representing total investment approximately 144 million february 2000 company entered agreement party jointly equal interests eaprc company expects complete transaction prior end first quarter 2000 would reduce companys interest eaprc less 50 percent since companys control eaprc temporary investment accounted using equity method accounting eaprc owns operates seven power generation facilities philippines one plant china total generating capacity 412 megawatts electric power generated facilities supplied diversified base customers including national power corporation philippine stateowned utility private distribution companies industrial users connection acquisition eaprc company entered shortterm fully collateralized loan agreement third party agreement company placed 101 million interest bearing account financial institution loaned equal amount deposit withdrawn upon repayment loan loans interest rate libor plus 400 basis points 102 percent december 31 1999 deposit reflected current assets loan reflected accounts notes payable consolidated balance sheets ce generation march 1999 company purchased 50 percent ownership interest ce generation llc investment approximately 254 million accounted using equity method accounting ce generation llc owns ownership interests four natural gasfired cogeneration projects new york pennsylvania texas arizona eight geothermal facilities near imperial valley southern california addition two additional geothermal facilities currently construction southern california collectively 14 power projects combined electric generating capacity approximately 900 megawatts encap march 1999 company acquired encap 52 million net cash acquired purchase price included 17 million company common stock 7 million issuable upon occurrence certain events acquisition accounted purchase company recorded 45 million goodwill amortized 25 years encap institutional funds management firm specializing financing independent oil natural gas producers encap manages three separate institutional oil natural gas investment funds us serves investment advisor energy capital investment company plc publicly traded investment company united kingdom chaparral investors 1999 company contributed approximately 120 million equity capital assets newly formed limited liability company chaparral thirdparty financial investor contributed approximately 123 million earn preferred return connection transaction chaparral formed wholly owned subsidiary mesquite subsidiary company manages chaparral mesquite 1999 company issued note payable approximately 121 million chaparral note payable demand carries variable interest rate 64 percent per annum fourth quarter 1999 company also note receivable mesquite balance approximately 262 million december 31 1999 collateralized chaparrals membership interest mesquite note variable interest rate 83 percent fourth quarter 1999 payable upon demand companys investment chaparral accounted using equity method accounting january 2000 company acquired additional interest chaparral exchange 160 million contingent interest promissory note maturity date note earlier december 2019 upon occurrence certain events specified note carries variable interest rate exceed 1275 percent deeptech august 1998 company completed acquisition deeptech acquisition accounted purchase total purchase price approximately 415 million net cash acquired company recorded 207 million goodwill connection acquisition amortized using straightline method period 40 years operating results deeptech included companys consolidated statements income beginning august 15 1998 components purchase price follows accordance deeptech merger agreement company guaranteed deeptechs 12 senior notes due 2000 following table contains summarized financial information deeptech information twelve months ended june 30 1998 1997 premerger periods information december 31 1999 1998 year ended december 31 1999 postmerger period information six months ended december 31 1998 part postmerger part premerger unaudited b reflects allocation purchase price assets acquired liabilities assumed connection companys acquisition deeptech august 1998 march 1999 company acquired additional 10 percent interest samalayuca power project approximately 22 million bringing overall ownership 40 percent company also made 48 million equity contribution project replace equity financing established second quarter 1996 june 1999 company acquired 26 percent interest ppn power plant tamil nadu india 37 million approximately 11 million paid june 1999 remaining amount paid first quarter 2001 project consists 346 megawatt combined cycle power plant serve base load facility sell power stateowned tamil nadu electricity board thirtyyear power purchase agreement construction began january 1999 operations expected commence early 2001 june 1999 company increased effective ownership interest el paso energy partners approximately 27 percent approximately 35 percent transferring 49 percent interest viosca knoll gathering company el paso energy partners total consideration approximately 80 million proceeds included cash approximately 20 million balance el paso energy partners common units gain transaction limited extent thirdparty ownership el paso energy partners included net consolidated statements income 1999 sonat energy services wholly owned subsidiary company purchased agls 35 percent interests sonat marketing company lp sonat power marketing lp approximately 65 million december 31 1999 company owned 100 percent two partnerships august 1999 company acquired 100 percent interest 158 megawatt rio negro power plant located manaus brazil 110 million electricity rio negro facility sold longterm contract subsidiary brazilian federal electric utility eletronorte october 1999 company acquired 25 percent interest 762 megawatt coalfired power plant peoples republic china approximately 5 million paid october remaining 63 million paid first quarter 2001 meizhou wan power plant located fujian province expected operational first quarter 2001 january 1998 sonat completed merger zilkha energy company zilkha exchanging approximately 24 million common shares outstanding shares zilkha privately owned exploration production company transaction valued 13 billion merger accounted pooling interests therefore consolidated financial statements financial information included annual report periods prior merger include historical financial results zilkha pending mergers acquisitions january 2000 company announced entered definitive agreement merge coastal merger share coastal common stock class common stock converted taxfree basis 123 shares company common stock coastals outstanding convertible preferred stock exchanged company common stock basis preferred stock converted coastal common stock immediately prior merger total value transaction approximately 16 billion including 6 billion assumed debt preferred equity accounted pooling interests merger expected close fourth quarter 2000 subject approval stockholders companies normal regulatory approvals coastal diversified energy holding company engaged subsidiaries joint ventures natural gas transmission storage gathering processing marketing natural gas oil exploration production petroleum refining marketing distribution chemicals power production coal coastal owns interests approximately 18000 miles natural gas pipelines extending across midwestern rocky mountain areas united states proved reserves 36 tcfe coastal also international domestic interests natural gas oil producing properties power production plants crude oil refining facilities january 2000 company entered agreement purchase natural gas natural gas liquids businesses pge gas transmission texas corporation pge gas transmission teco inc total value transaction 840 million including face amount assumed debt approximately 561 million acquisition expected close midyear 2000 subject receipt certain required governmental approvals third party consents transaction accounted purchase included field services assets acquired consist 8500 miles intrastate natural gas transmission pipelines transport approximately 28 bcfd south texas area nine natural gas processing plants currently process 15 bcfd 72 bcf natural gas storage field transaction also includes significant natural gas liquids pipelines fractionation facilities 3 mergerrelated asset impairment charges 1999 company incurred 557 million charges related merger sonat well certain asset impairment charges mergerrelated costs include 294 million related benefit costs associated change control defined certain benefit plans retention termination charges 71 million transaction costs 28 million costs related conforming accounting practices policies el paso sonat 46 million mergerrelated charges primarily consisting facilities integration costs incremental fees retain seismic data mergerrelated asset impairment charges 76 million related duplicate systems facilities identified impaired following merger company also recorded asset impairment charges 42 million lower estimated recoveries certain regulatory assets related sngs pending rate case year ended december 31 1997 company incurred approximately 50 million mergerrelated charges connection merger zilkha energy 4 ceiling test charges full cost method accounting natural gas oil properties quarterly ceiling tests required ensure carrying value oil gas properties overstated march 31 1999 march 31 june 30 september 30 1998 determined capitalized costs exceeded ceiling test limits 352 million 40 million 540 million 455 million respectively writedowns included ceiling test charges consolidated statements income 5 income taxes following table reflects components income tax expense benefit years ended december 31 tax expense benefit company differs amount computed applying statutory federal income tax rate 35 percent income taxes following table outlines reasons differences periods ended december 31 following table reflects components net deferred tax liability december 31 december 31 1999 december 31 1998 4 million 2 million respectively noncurrent foreign deferred income taxes included assets consolidated balance sheets cumulative undistributed earnings certain foreign subsidiaries foreign corporate joint ventures approximately 86 million december 31 1999 since earnings intended indefinitely reinvested foreign operations provision made us taxes foreign withholding taxes may applicable upon actual deemed repatriation distribution earnings made company might subject foreign withholding taxes us income taxes net allowable foreign tax credits deductions however estimate taxes practicable reasons company provided us taxes foreign currency translation adjustments recognized comprehensive income tax benefit associated exercise nonqualified stock options vesting restricted stock well restricted stock dividends reduced taxes payable 13 million 1999 10 million 1998 15 million 1997 benefits included additional paidin capital consolidated balance sheets december 31 1999 company 69 million alternative minimum tax credit carryovers 1 million general business credit carryovers 759 million net operating loss carryovers 81 million capital loss carryovers alternative minimum tax credits carry forward indefinitely net operating loss carry forward periods end follows approximately 9 million years 2000 2005 16 million 2006 26 million 2007 24 million years 2008 2011 181 million 2012 72 million 2016 22 million 2017 239 million 2018 170 million 2019 carry forward period 74 million capital loss ends 2002 carry forward period remainder ends 2003 general business credit carry forward periods end various times years 2000 2017 usage carryovers subject limitations provided sections 382 383 internal revenue code well separate return limitation year rules irs regulations company recorded valuation allowance reflect estimated amount deferred tax assets may realized due expiration net operating loss tax credit carryovers december 31 1999 1998 approximately 4 million valuation allowance relates net operating loss carryovers acquired company remainder allowance relates general business credit carryovers exception 1 million tax benefits subsequently recognized reversal allowance allocated additional purchase cost assigned utility plant prior 1999 eptpc subsidiaries filed consolidated federal income tax return el paso subsidiaries filed separate consolidated federal income tax return result taxfree reorganization described note 1 el paso subsidiaries including eptpc subsidiaries file one consolidated federal income tax return subsidiaries sonat included el pasos consolidated return merger date connection acquisition eptpc company eptpc entered tax sharing agreement newport news shipbuilding inc new tenneco inc el paso successor epng tax sharing agreement provides among things allocation among parties tax assets liabilities arising prior result subsequent distributions new tenneco inc newport news shipbuilding inc shareholders old tenneco inc known eptpc generally eptpc liable taxes imposed respect periods prior consummation distributions case federal income taxes imposed combined activities old tenneco inc members consolidated group prior giving effect distributions new tenneco inc newport news shipbuilding inc liable eptpc federal income taxes attributable activities allocated agreedupon share estimated tax payments made eptpc old tenneco inc pursuant tax sharing agreement eptpc paid new tenneco inc 1997 tax benefits realized deduction 1996 taxable losses generated debt realignment accordance merger 6 earnings per share basic diluted earnings per share amounts calculated accordance sfas 128 earnings per share presented years ended december 31 1 addition potential average common shares outstanding 1999 1998 would reduced loss per share therefore diluted loss per share presented years 7 financial instruments price risk management activities fair value financial instruments following disclosure estimated fair value financial instruments presented accordance requirements sfas 107 sfas 119 estimated fair value amounts determined company using available market information valuation methodologies december 31 1999 1998 carrying amounts certain financial instruments held company including cash equivalents shortterm borrowings trade receivables payables representative fair value shortterm maturity instruments fair value longterm debt variable interest rates carrying value variable nature respective debts interest rates fair value debt fixed interest rates estimated based quoted market prices similar issues fair value derivative financial instruments estimated amount management believes instruments could liquidated reasonable period time based quoted market prices current market conditions estimates obtained thirdparty brokers dealers following table reflects carrying amount estimated fair value companys financial instruments december 31 1 excludes transportation capacity natural gas storage held trading purposes trading commodity activities companys merchant energy business offers integrated price risk management services energy sector services primarily relate energy related commodities including natural gas power products company provides services variety contracts entered trading purposes including exchange traded futures contracts involving cash settlement forward contracts involving cash settlements physical delivery energy commodity swap contracts require payments receipt payments counterparties based differential fixed variable price commodity options contractual arrangements company recognized gross margin 97 million 53 million 1999 1998 respectively trading activities fair value commodity energy related contracts entered trading purposes december 31 1999 1998 average fair value instruments held years ended set forth december 31 1999 1998 413 million 118 million respectively assets price risk management activities included noncurrent assets 95 million 57 million respectively liabilities price risk management activities included noncurrent liabilities consolidated balance sheets 1 computed using net asset liability balance month end notional amounts terms notional amounts terms companys energy commodity financial instruments december 31 1999 1998 set forth natural gas volumes trillions british thermal units power volumes millions megawatt hours liquids volumes millions british thermal units 1 liquids include crude oil condensate petroleum based products notional amount terms foreign currency forward purchases sales december 31 1999 follows notional amounts reflect volume transactions represent amounts exchanged parties accordingly notional amounts incomplete measure companys exposure market credit risks maximum terms years detailed indicative likely future cash flows positions may offset cashedout commodity currency markets based companys risk management needs liquidity markets weighted average maturity companys entire portfolio price risk management activities approximately six years december 31 1999 two years december 31 1998 market credit risks company serves diverse customer group includes independent power producers industrial companies gas electric utilities natural gas oil producers financial institutions energy marketers broad customer mix generates need variety financial structures products terms diversity requires company manage portfolio basis resulting market risks inherent transactions subject parameters established companys risk management committee market risks monitored risk control committee operating independently units create actively manage risk exposures ensure compliance companys stated risk management policies company measures adjusts risk portfolio accordance marktomarket risk management methodologies utilize forward price curves energy markets estimate size probability future potential exposure credit risk relates risk loss company would incur result nonperformance counterparties pursuant terms contractual obligations company maintains credit policies regard counterparties minimize overall credit risk policies require evaluation potential counterparties financial condition including credit rating collateral requirements certain circumstances including cash advance letters credit guarantees use standardized agreements allow netting positive negative exposures associated single counterparty counterparties associated companys assets price risk management activities summarized follows ainvestment grade primarily determined using publicly available credit ratings along consideration collateral encompass standby letters credit parent company guarantees property interest including natural gas oil reserves included investment grade counterparties minimum standard poors moodys rating bbb baa3 respectively minimum implied internal credit analysis standard poors equivalent rating bbb bfour two customers exposure december 31 1999 1998 respectively comprise greater 5 percent assets price risk management activities customers investment grade ratings concentration counterparties may impact companys overall exposure credit risk either positively negatively counterparties may similarly affected changes economic regulatory conditions based companys policies risk exposure reserves company anticipate material adverse effect financial position results operations cash flows result counterparty nonperformance nontrading price risk management activities company also utilizes derivative financial instruments nontrading activities mitigate market price risk associated significant physical transactions nontrading commodity activities accounted using hedge accounting provided meet hedge accounting criteria nontrading activities conducted exchange traded futures contracts swaps forward agreements third parties december 31 1999 1998 company outstanding energy commodity futures forwards swaps options purposes trading table represents notional amounts terms contracts december 31 1999 1998 january 1 1999 sonat power marketing began accounting power portfolio using mark market accounting apply provisions eitf 9810 accounting contracts involved energy trading risk management activities impact adopting mark market accounting material financial position results operations cash flows company december 31 1998 mpc party two interest rate swap agreements effectively converted 114 million floatingrate debt fixedrate debt see note 9 mpc made payments counterparties fixed rates return received payments floating rates october 1999 mpc terminated interest rate swaps cost approximately 5 million interest expense cash requirements 3 million higher 1999 1998 1997 respectively result swaps august 1999 el paso entered interest rate swap agreement notional amount 600 million termination date july 2001 agreement el paso swapped fixed interest rate july 1999 600 million aggregate principal senior notes due 2001 floating three month libor plus rate margin 1475 basis points rate swap december 31 1999 619 percent total interest expense approximately 1 million 1999 result swap agreements march 1997 company purchased 105 percent interest capsa privately held argentine company engaged power generation natural gas oil production approximately 57 million connection acquisition company entered equity swap transaction associated additional 185 percent capsas outstanding stock swap company paid interest counterparty quarterly basis notional amount 100 million rate libor plus 085 percent exchange company receives dividends capsa stock extent counterpartys equity interest 185 percent company also fully participates market appreciation depreciation underlying investment whereby company realize appreciation fund depreciation attributable actual sale stock upon termination expiration swap transaction initial term swap two years february 1999 contract extended additional two onehalf years notional amount 103 million interest rate libor plus 175 percent upon maturity termination swap company right first refusal purchase counterpartys 185 percent investment capsa common stock fair value stock date later date price offered good faith buyer transaction recorded using marktomarket accounting company also faces credit risk respect nontrading activities takes similar measures trading activities mitigate risk based upon companys policies risk exposure company anticipate material effect financial position results operations cash flows resulting counterparty nonperformance 8 property plant equipment property plant equipment consisted following december 31 9 debt credit facilities average interest rate shortterm borrowings 66 59 december 31 1999 1998 respectively company following shortterm borrowings including current maturities longterm debt december 31 longterm debt outstanding consisted following december 31 following aggregate maturities principal amounts longterm debt next 5 years total thereafter financing arrangements el paso 1250 million 364day 750 million fiveyear revolving credit facility collectively revolving credit facility 1250 million 364day renewable revolving credit competitive advance facility established august 1999 replaced el pasos 1998 750 million 364day renewable revolving credit competitive advance facility 750 million fiveyear revolving credit competitive advance facility established october 1997 epng tgp designated borrowers revolving credit facility rate revolving credit facility varies based el pasos unsecured debt rating december 31 1999 interest rate borrowing revolving credit facility equal libor plus 50 basis points amounts outstanding available credit revolving credit facility expected used general corporate purposes including limited backstopping tgps epngs combined 2 billion commercial paper program availability borrowings companys credit agreements subject specified conditions management believes company currently meets conditions include compliance financial covenants ratios required agreements absence default agreements continued accuracy representations warranties contained agreements including absence material adverse changes company companys senior debt issues given investment grade ratings standard poors moodys september 1998 tgp filed shelf registration permitting offer 600 million debt securities october 1998 tgp issued 400 million aggregate principal amount 7 debentures due 2028 issuance tgp 200 million capacity remaining shelf registration sng shelf registration provides issuance 500 million debt securities 1998 sng issued 100 million aggregate principal amount 6625 notes due 2008 result sng 400 million capacity remaining shelf registration may 1999 el paso issued 500 million aggregate principal amount 675 senior notes due 2009 proceeds approximately 496 million net issuance costs used repay shortterm debt corporate purposes 1999 company received net proceeds 960 million thirdparty investor result sale preferred interest trinity river associates llc consolidated joint venture company 20 percent interest proceeds used repay shortterm debt corporate purposes july 1999 el paso issued 600 million aggregate principal amount 6625 senior notes due 2001 100 million aggregate principal amount floating rate senior notes due 2001 proceeds approximately 697 million net issuance costs used repay shortterm borrowings corporate purposes also july sonat issued 600 million aggregate principal amount 7625 notes due 2011 proceeds approximately 590 million net issuance cost used repay shortterm borrowings august 1999 el paso filed shelf registration statement pursuant may offer 900 million including 65 million transferred prior shelf registrations common preferred equity various forms debt securities including convertible debt securities trust preferred securities may issued time determined market conditions december 1999 el paso modified registration allow 600 million 900 million used issuance mediumterm notes december 31 1999 securities issued shelf registration 1999 el paso received proceeds approximately 121 million issuance demand notes payable chaparral investors llc notes due demand variable rate libor plus 75 basis points january 2000 el paso established borrowed 250 million noncommitted line credit financial institution november 1999 bear creek capital corporation retired 816 series note 1139 series b note aggregate principal amount 42 million eptpc retired 8 notes aggregate principal 3 million february 1999 deeptech retired 11 senior promissory note due 2000 amount 16 million september 1999 epng retired outstanding 945 note principal amount 47 million august 1999 sonat retired outstanding 95 note principal amount 100 million october 1999 mpc retired variable rate nonrecourse project financing principal amount 107 million concurrently mpc also terminated associated interest rate swap cost approximately 5 million 10 commitments contingencies international project contingencies international subject various claims arise ordinary course project activities claims include among things relating project delays contractual disputes andor adverse impact uncertainties risks related unstable currencies governments arise countries international conducts business international attempts mitigate risks use indemnification clauses private public insurance denominating transactions united states dollars possible activities deems necessary losses probable estimable international establishes reserves however despite internationals efforts mitigate risks establish appropriate reserves unreserved losses occur management cannot predict certainty final outcome currently pending issues matters believes based experience date considering reserves established resolution currently pending issues matters material adverse effect companys financial position results operations cash flows company noncontrolling interest project senkang south sulawesi indonesia total investment approximately 28 million throughout 1999 project faced difficulties stemming indonesias weak economy devaluation currency currently project operating interim agreement company negotiates longterm resolutions existing past contract terms company carries political risk insurance coverage indonesian project furthermore project debt nonrecourse company believes current economic difficulties indonesia material adverse effect companys financial position results operations cash flows capital commitments december 31 1999 company capital investment commitments 497 million companys planned capital investment projects discretionary nature substantial capital commitments made advance actual expenditures purchase obligations connection financing commitments certain joint ventures tgp entered unconditional purchase obligations products services totaling 56 million december 31 1999 tgps annual obligations agreements 21 million 2000 11 million year 2001 4 million years 2002 2003 2004 12 million total thereafter excluded amounts tgps obligation purchase 30 percent output great plains coal gasification projects original design capacity july 2009 january 1997 tgp settled contract part gsr negotiations recorded related liability purchased annuity 42 million fund expected remaining monthly demand requirements contract continue january 2004 operating leases company leases certain property facilities equipment various operating leases 1995 el paso new chaco company epnc entered unconditional lease chaco plant lease term expires 2002 time epnc option obligation upon occurrence certain events purchase plant price sufficient pay amount 77 million construction financing plus interest certain expenses epnc purchase plant end lease term obligation pay residual guaranty amount equal approximately 87 percent amount financed plus interest company unconditionally guaranteed obligations epnc lease minimum annual rental commitments december 31 1999 follows aggregate minimum commitments reduced minimum sublease rentals approximately 15 million due future noncancelable subleases rental expense operating leases years ended december 31 1999 1998 1997 37 million 39 million 33 million respectively guarantees december 31 1999 company parental guarantees approximately 995 million connection international development activities various projects company also outstanding letters credit approximately 170 million december 31 1999 rates regulatory matters companys interstate natural gas pipeline companies subject regulatory jurisdiction ferc respect rates terms conditions service accounts records addition facilities abandonment services facilities curtailment gas deliveries matters interstate natural gas pipelines various pending regulatory proceedings including limited issues relating sngs august 1999 rate case filing epngs june 1995 rate case filing tgps december 1996 rate case filing rate regulatory matters fully unconditionally resolved company may either recognize additional refund obligation noncash benefit finalize previously estimated liabilities companys pipeline systems contracts covering portion firm transportation capacity various terms maturity additionally systems operate different markets regions different competitive regulatory pressures impact ability systems renegotiate renew existing contracts enter new longterm firm transportation commitments december 31 1999 tgp contracts representing 20 percent firm transportation capacity expiring november 2000 sng 43 percent firm transportation capacity due expire primarily 2003 epng portion capacity subscribed shorterterm contracts primarily 2001 companys systems aggressively pursued renegotiation renewal expiring contracts sale excess capacity firm transportation arrangements made progress efforts however uncertain future contracts terms favorable company exist currently furthermore new renewed contracts disputed customers groups certainty regulators jurisdictional bodies intercede recontracting process alter ultimate outcome efforts epngs customers except edison participate risk sharing provisions epngs rate case settlement provisions epng received continues receive cash payments risk assumed certain capacity relinquishments customers end 1997 cash received deferred epng recognizes deferral revenues ratably risk sharing period december 31 1999 company unearned risk sharing revenues approximately 127 million 54 million remaining collected customers provision epng remarkets relinquished capacity customers certain dollar levels specified risk sharing agreement may obligated refund excess customers year ended december 31 1999 epng refunded approximately 8 million customers provision accrued approximately 7 million refunds made 2000 risk sharing provisions rate settlement extend 2003 time epng risk unsubscribed excess capacity system july 1998 ferc issued notice proposed rulemaking nopr sought comments wide range initiatives change manner shortterm less one year transportation markets regulated february 9 2000 ferc issued final ruling response nopr among things rule allows pipelines file implement peak offpeak rates ii removes price cap released capacity iii requires pipelines make changes tariffs regarding customer imbalances penalties pipeline operations iv increases amount type information pipelines must make available ferc customers management cannot predict certainty final outcome timing final resolution rates regulatory matters outcome current recontracting capacity subscription efforts outcome industry trends initiatives management believes based upon experience date considering appropriate reserves established ultimate resolution pending rate regulatory matters material adverse effect companys financial position results operations cash flows legal proceedings november 1993 transamerican natural gas corporation transamerican filed complaint texas state court amended seeks approximately 75 billion actual punitive damages related 1990 settlement agreement epng transamerican others transamericans complaint amended advanced ten causes action defendants include epng coastal entities related certain present former officers directors result orders court various motions summary judgment made behalf epng affiliated entities present former officers directors six causes action dismissed entirety one partially dismissed partially dismissed claim alleges fraud claims remain pending allege breach contract bad faith violation texas antitrust act respect fraud claim court dismissed transamericans claim fraudulently induced enter settlement transaction refused dismiss remainder fraud claim transamerican alleges misrepresentations settlement documents motions summary judgment transamericans remaining claims expected heard decided court prior current trial setting april 24 2000 additionally epng filed breach contract counterclaim transamerican seeking recover epngs expenses incurred connection lawsuit transamericans motion summary judgment counterclaim denied court april 1996 former employee transamerican filed related case harris county texas vickroy e stone v godwin carlton pc et al stone seeking damages unspecified amounts related litigation consulting work allegedly performed various entities including epng cases involving transamerican june 1998 court granted epngs motion summary judgment dismissed claims stone litigation stone appealed courts ruling texas court appeals houston texas based information available time management believes claims asserted cases factual legal basis february 1998 united states state texas filed united states district court comprehensive environmental response compensation liability act cercla superfund cost recovery action fourteen companies including company certain affiliated companies relating sikes disposal pits superfund site sikes located harris county texas suit claims united states state texas expended 125 million remediating sikes seeks recover amount plus interest defendants suit although factual investigation relating sikes preliminary stages company believes amount material disposed sikes company small possibly de minimis however plaintiffs alleged defendants jointly severally liable entire remediation costs also sought declaration liability future response costs groundwater monitoring tgp party proceedings involving federal state authorities regarding past use tgp lubricant containing pcbs starting air systems tgp executed consent order epa governing remediation certain compressor stations working epa relevant states regarding remediation activities tgp also working pennsylvania new york environmental agencies regarding remediation postremediation activities pennsylvania new york stations november 1988 kentucky environmental agency filed complaint kentucky state court alleging tgp discharged pollutants waters state without permit disposed pcbs without permit agency sought injunction future discharges sought order remediate remove pcbs sought civil penalty tgp entered agreed orders agency resolve many issues raised original allegations received water discharge permits kentucky compressor stations agency continues work resolve remaining issues relevant kentucky compressor stations scheduled characterized remediated consent order epa number subsidiaries el paso wholly partially owned named defendants actions brought jack grynberg behalf us government false claims act generally complaints allege industrywide conspiracy underreport heating value well volumes natural gas produced federal indian lands thereby depriving united states government royalties company believes complaint without merit number subsidiaries el paso wholly partially owned named defendants class action suit quinque operating company v gas pipelines plaintiff alleges defendants mismeasured natural gas volumes heating content natural gas nonfederal nonnative american lands suit similar action brought jack grynberg behalf united states government company believes complaint without merit company also named defendant numerous lawsuits named party numerous governmental proceedings arising ordinary course business outcome matters discussed cannot predicted certainty management currently expect ultimate resolution matters material adverse effect companys financial position results operations cash flows environmental company subject extensive federal state local laws regulations governing environmental quality pollution control laws regulations require company remove remedy effect environment disposal release specified substances current former operating sites december 31 1999 company reserve approximately 245 million expected remediation costs including approximately 233 million associated onsite offsite groundwater technical studies approximately 12 million costs company anticipates incurring 2027 addition company estimates subsidiaries make capital expenditures environmental matters approximately 3 million 2000 capital expenditures estimated total approximately 103 million aggregate years 2001 2007 expenditures primarily relate compliance air regulations lesser extent control water discharges since 1988 tgp engaged internal project identify deal presence pcbs substances concern including substances epa list hazardous substances compressor stations facilities operated interstate intrastate natural gas pipeline systems conducting project tgp frequent contact federal state regulatory agencies informal negotiation formal entry consent orders ensure efforts meet regulatory requirements may 1995 following negotiations customers tgp filed ferc separate stipulation agreement environmental stipulation established mechanism recovering substantial portion environmental costs identified internal project environmental stipulation effective july 1 1995 december 31 1999 amounts collected thereunder refunds may required extent actual eligible expenditures less amounts collected company certain subsidiaries designated received notice could designated asked information determine whether could designated prp respect 33 sites comprehensive environmental response compensation liability act cercla superfund state equivalents company sought resolve liability prp respect superfund sites indemnification third parties andor settlements provide payment companys allocable share remediation costs december 31 1999 company estimated share remediation costs sites 76 million 94 million provided reserves believes adequate costs since cleanup costs estimates subject revision information becomes available extent remediation required cases company asserted defense liability companys estimate share remediation costs could change moreover liability federal superfund statute joint several meaning company could required pay excess pro rata share remediation costs companys understanding financial strength prps considered appropriate determination estimated liability described herein company presently believes costs associated current status entities prps superfund sites referenced material adverse effect companys financial position results operations cash flows company initiated proceedings historic liability insurers seeking payment reimbursement costs liabilities associated environmental matters proceedings company contends certain environmental costs liabilities associated various entities sites including costs associated former operating sites must paid reimbursed certain historic insurers proceedings discovery stage yet possible predict outcome matter possible new information future developments could require company reassess potential exposure related environmental matters company may incur significant costs liabilities order comply existing environmental laws regulations also possible developments increasingly strict environmental laws regulations enforcement policies thereunder claims damages property employees persons environment resulting current discontinued operations could result substantial costs liabilities future information becomes available relevant developments occur related accrual amounts adjusted accordingly still uncertainties relating ultimate costs may incurred based upon companys evaluation experience date company believes recorded reserves adequate discussion specific environmental matters see legal proceedings 11 retirement benefits pension benefits prior january 1 1997 company maintained defined benefit pension plan covering substantially employees epng epfs pension benefits based years credited service final five year average compensation subject maximum limitations defined pension plan effective january 1 1997 plan amended provide benefits determined cash balance formula include employees added result merger el paso eptpc acquisitions prior 1997 employees pension plan participants december 31 1996 receive greater cash balance benefits prior plan benefits accrued december 31 2001 following merger sonat company offered early retirement incentive program sonat employees least 50 years age 10 years service december 31 1999 terminate employment june 30 2000 total charges result early retirement program approximately 8 million effective january 1 2000 sonat pension plans merged company pension plans sonat employees participants sonat pension plan sonat merger effective date receive greater cash balance benefits sonat plan benefits accrued december 31 2004 postretirement benefits company provides postretirement medical benefits certain closed groups retired employees epng eptpc sonat limited postretirement life insurance benefits current retired employees postretirement employee benefits opeb prefunded extent costs recoverable rates extent actual opeb costs tgp epng sng differ amounts recovered rates regulatory asset liability recorded companys early retirement incentive program sonat employees participating eligible employees allowed keep postretirement medical life benefits commencing later age 55 retirement total charges associated incentive program elimination retiree benefits future retirees 29 million accrued december 31 1999 medical benefits closed group retirees may subject deductibles copayment provisions limitations dollar caps amount employer costs company reserved right change benefits following table sets forth change benefit obligation change plan assets reconciliation funded status components net periodic benefit cost pension benefits postretirement benefits 1998 company changed measurement date measuring pension opeb obligations december 31 september 30 measurement date also assumed sonat plan results included herein included pension benefits information certain plans projected benefit obligation accumulated benefit obligation pension plans accumulated benefit obligations excess plan assets 57 million 53 million december 31 1999 51 million 34 million december 31 1998 respectively current liability portion postretirement benefits 46 million december 31 1999 1998 benefit obligations based upon certain actuarial estimates described 1 reflects weighted average el paso sonat plan assumptions actuarial estimates companys postretirement benefits plans assumed weighted average annual rate increase per capita costs covered health care benefits 10 percent 2000 gradually decreasing 6 percent year 2008 1998 sonat assumed health cost trend rate 45 percent years assumed health care cost trends significant effect amounts reported postretirement benefit plans onepercentage point change assumed health care cost trend rates would following effects retirement savings plan company maintains defined contribution plan covering employees company matches 75 percent participant basic contributions 6 percent matching contribution made company stock prior merger sonat matched 100 percent participant basic contributions 6 percent amounts expensed plan approximately 16 million 16 million 11 million years ended december 31 1999 1998 1997 respectively 12 trust preferred securities march 1998 el paso energy capital trust issued 65 million 4 34 trust convertible preferred securities trust preferred securities 325 million 317 million net issuance costs addition trust issued approximately 10 million trust convertible common securities epng net proceeds used epng pay commercial paper trust exists sole purpose issuing trust preferred securities investing proceeds 4 34 convertible subordinated debentures due 2028 trust debentures epng trusts sole asset epng executed full unconditional subordinated guarantee trust preferred securities result holding company reorganization discussed note 1 el paso assumed ownership trust well obligations trust debentures guarantee trusts obligations trust preferred securities results trust consolidated company therefore trust debentures eliminated trust preferred securities reflected companyobligated mandatorily redeemable convertible preferred securities el paso energy capital trust consolidated balance sheets distributions paid trust preferred securities included minority interest consolidated statements income trust preferred securities nonvoting except limited circumstances pay quarterly distributions annual rate 4 34 carry liquidation value 50 per security plus accrued unpaid distributions convertible companys common shares time prior close business march 31 2028 option holder rate 12022 common shares trust preferred security equivalent conversion price 4159 per common share subject adjustment certain circumstances 13 minority interest trinity river 1999 company formed sabine river investors llc sabine wholly owned limited liability company separate legal entities purpose generating funds invest capital projects assets ownership sabine company contributed 250 million equity capital trinity river associates llc trinity exchange managing member interest trinity thirdparty investor contributed 980 million equity capital trinity noncontrolling preferred interest thirdparty investor entitled adjustable preferred return derived trinitys net income december 31 1999 minority interest expense recorded consolidated statements income 21 million proceeds equity contributions used trinity invest note receivable sabine collateralized certain assets company option acquire thirdparty investors interest trinity time prior june 2004 company exercise option company thirdparty investor agree extend terms agreement trinitys note receivable sabine mature portion proceeds therefrom used trinity redeem thirdparty investors interest trinity assets liabilities operations sabine trinity entities involved transaction included companys consolidated financial statements thirdparty investors interest included minority interest consolidated balance sheets preferred stock subsidiary november 1996 eptpc issued 6 million shares 825 cumulative preferred stock par value 50 per share 296 million net issuance costs preferred stock redeemable option eptpc december 31 2001 redemption price equal 50 per share plus dividends accrued unpaid date redemption 1999 1998 1997 dividends approximately 25 million paid year preferred stock preferred stock included minority interest consolidated balance sheets 14 capital stock june 1999 stockholders el paso approved amendment el pasos restated certificate incorporation authorize issuance 750 million shares common stock 50 million shares preferred stock common stock october 1999 approximately 110 million shares company common stock issued connection acquisition sonat shares valued approximately 45 billion march 1999 approximately 3 million shares company common stock valued approximately 10 million issued connection acquisition encap october 1997 approximately 8 million shares company common stock valued approximately 21 million issued connection acquisition gulf states gas pipeline company february 1997 approximately 6 million shares company common stock valued approximately 152 million issued public offering registered securities act 1933 amended treasury stock time board authorized repurchase el pasos outstanding shares common stock used connection el paso employee stockbased compensation plans corporate purposes 1998 company repurchased approximately 1052000 common shares weighted average cost approximately 36 per share july 1999 company rescinded common stock repurchase program order comply requirements treat merger sonat pooling interests generally accepted accounting principles program originally authorized el paso repurchase 10 million shares december 31 1999 1998 el paso held 8947565 5494772 shares treasury stock respectively included balance december 31 1999 5845269 shares treasury stock used secure benefits certain companys benefit plans subject certain restrictions stock dividend january 1998 board declared twoforone stock split form 100 percent stock dividend per share basis stock dividend aggregate 60944417 shares common stock paid april 1 1998 stockholders record march 13 1998 presentations herein made postsplit basis el paso 50000000 shares authorized preferred stock par value 001 per share none issued 7500000 shares designated series junior participating preferred stock reserved issuance pursuant companys preferred stock purchase rights plan 15 stockbased compensation 1999 1998 1997 company granted stock options various stock option plans company applies accounting principles board opinion 25 related interpretations accounting plans 1995 financial accounting standards board issued sfas 123 accounting stockbased compensation fully adopted changes methods companies use determining expense related stock option plans adoption expense recognition provisions sfas 123 optional company elected apply provisions however pro forma disclosures company adopted expense recognition provisions sfas 123 presented companys existing stock option plans company authorized issue shares common stock employees nonemployee directors pursuant awards granted incentive stock options intended qualify section 422 internal revenue code nonqualified stock options restricted stock appreciation rights sars phantom stock options performance units nonqualified stock options company granted nonqualified stock options 1999 1998 1997 stock option plans stock options granted periods contractual terms 10 years generally vest completion one five years continuous employment grant date options also granted nonemployee members board fair market value date grant exercisable immediately terms certain plans el paso may grant sars certain holders stock options sars subject terms conditions related stock options december 31 1999 44710 sars outstanding included stock options part tandem awards stock option holder granted tandem sars elect exercise either option sar sars entitle option holder receive payment equal difference option price fair market value common stock el paso date exercise sar extent sar exercised related option canceled extent option exercised related sar canceled currently sars accounted compensation expense accounting principles board opinion 25 considered purposes computing fair value outstanding options using blackscholes option pricing model described summary status companys stock options december 31 1999 1998 1997 presented fair value stock option granted estimated date grant using blackscholes optionpricing model following weightedaverage assumptions blackscholes weighted average fair value options granted 1999 1998 1997 1142 700 386 respectively options outstanding december 31 1999 summarized restricted stock companys various stockbased compensation plans limited number shares restricted company common stock may granted cost certain key officers employees shares carry voting dividend rights however sale transfer shares restricted accordance vesting procedures restricted stock awards vest specific period time andor company achieves certain performance targets restricted stock awards representing 14 million 6 million 8 million shares granted 1999 1998 1997 respectively weighted average grant date fair value 3510 3240 3001 per share respectively december 31 1999 11 million shares restricted stock outstanding value shares determined based fair market value measurement date charged compensation expense ratably restriction period based number shares met performance vesting target 1999 1998 1997 charges totaled 69 million 29 million 19 million respectively included 1999 amount 60 million related accelerated vesting restricted stock due change control defined certain benefit plans resulting merger sonat performance units certain employees officers company awarded performance units payable cash stock end vesting period final value performance units may vary according plan granted usually based companys common stock price end vesting period value performance units charged ratably compensation expense vesting period periodic adjustments account fluctuation market price companys stock amounts charged compensation expense 1999 1998 1997 30 million 13 million 5 million respectively included 1999 amount 22 million related accelerated vesting performance units due change control resulting merger sonat pro forma net income net income per common share compensation expense companys stockbased compensation plans determined applying provisions sfas 123 companys net income net income per common share 1999 1998 1997 would approximate pro forma amounts effects applying sfas 123 pro forma disclosure indicative future amounts sfas 123 apply awards granted prior 1995 fiscal year company reserved approximately 38 million shares common stock issuance pursuant existing future stock awards december 31 1999 approximately 14 million shares remained unissued january 2000 additional 4 million shares issued companys existing plans employee stock purchase program effective july 1999 company implemented employee stock purchase plan section 423 internal revenue code espp purchases common stock commence end quarter el paso sonat merger occurred espp affords participants right purchase common stock quarterly basis 85 percent lower market price beginning offering period end calendar quarter april 1999 company stockholders authorized issuance 2 million shares common stock plan 1999 approximately 1500 participants total contributions approximately 5 million december 31 1999 approximately 140000 shares common stock issued espp 3310 per share funds received held company respect espp may used general corporate purposes however company records liability espp withholdings yet applied towards purchase common stock company bears expenses associated administering espp except costs including applicable taxes associated participants sale common stock 16 segment information company adopted provisions sfas 131 disclosures segments enterprise related information result merger sonat company segregated business activities five segments natural gas transmission merchant energy international field services production segments strategic business units offer variety different energy products services managed separately business requires different technology marketing strategies accounting policies individual segments company whole described note 1 certain business segments earnings largely derived earnings equity investments reported net consolidated statements income accordingly company evaluates segment performance based ebit extent practicable results operations years ended december 31 1998 1997 reclassified conform current business segment presentation although results necessarily indicative results would achieved revised business segment structure effect period reconciliations revenues reportable segments total consolidated revenues presented reconciliations income reportable segments total consolidated income presented reconciliations ebit income loss preferred dividends subsidiary cumulative effect accounting change presented reconciliations assets reportable segments total consolidated assets presented company gross revenue customer equal excess ten percent consolidated operating revenue years ended december 31 1999 1998 1997 17 supplemental cash flow information following table contains supplemental cash flow information years ended december 31 see note 2 discussion noncash investing transactions related certain acquisitions 18 investment affiliated companies unaudited company holds investments various affiliates accounted equity method accounting companys principal equity method investees international pipelines interstate pipelines power generation plants gathering systems summarized financial information companys proportionate share 50 percent less owned companies majority owned unconsolidated subsidiaries accounted equity method accounting follows 1 investments unconsolidated affiliates consolidated balance sheets include amounts associated unamortized purchase price differences relating certain unconsolidated investees 19 supplemental selected quarterly financial information unaudited financial information quarter summarized opinion management adjustments necessary fair presentation made 20 supplemental natural gas oil operations unaudited december 31 1999 company interests natural gas oil properties located primarily texas louisiana oklahoma arkansas new mexico offshore louisiana texas gulf mexico production lease natural gas oil properties outside united states capitalized costs relating natural gas oil producing activities related accumulated depreciation depletion amortization follows costs incurred natural gas oil producing activities whether capitalized expensed follows presented analysis capitalized costs natural gas oil properties year expenditure amortized december 31 1999 pending determination proved reserves capitalized interest 12 million 2 million 6 million years ended december 31 1999 1998 1997 respectively included presentation projects presently excluded amortization various stages evaluation majority costs expected included amortization calculation years 2000 2003 total amortization expense per mcfe including ceiling test charges 254 481 107 1999 1998 1997 respectively excluding ceiling test charges amortization expense would 095 106 per mcfe 1999 1998 respectively net quantities proved developed undeveloped reserves natural gas liquids including condensate crude oil changes quantities follows numerous uncertainties inherent estimating quantities proved reserves projecting future rates production timing development expenditures including many factors beyond control production reserve data represents estimates reservoir engineering subjective process estimating underground accumulations natural gas oil cannot measured exact manner significant changes reserves purchases sales production due reservoir performance existing fields drilling additional wells existing fields major discoveries events favorable adverse may considered caused significant change estimated proved reserves since december 31 1999 results operations producing activities fiscal year follows standardized measure discounted future net cash flows relating proved natural gas oil reserves follows calculations preceding table estimated future cash inflows estimated future production proved reserves computed using realized natural gas oil prices december respective year following principal sources change standardized measure discounted future net cash flows report independent accountants board directors stockholders el paso energy corporation opinion consolidated financial statements listed index appearing item 14a 1 present fairly material respects consolidated financial position el paso energy corporation december 31 1999 1998 consolidated results operations cash flows three years period ended december 31 1999 conformity accounting principles generally accepted united states addition opinion financial statement schedule listed index appearing item 14a 2 presents fairly material respects information set forth therein read conjunction related consolidated financial statements financial statements financial statement schedule responsibility companys management responsibility express opinion financial statements financial statement schedule based audits consolidated financial statements give retroactive effect merger sonat inc october 25 1999 transaction accounted pooling interests described note 2 consolidated financial statements conducted audits statements accordance auditing standards generally accepted united states require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements assessing accounting principles used significant estimates made management evaluating overall financial statement presentation believe audits provide reasonable basis opinions expressed pricewaterhousecoopers llp houston texas february 16 2000 schedule ii el paso energy corporation valuation qualifying accounts years ended december 31 1999 1998 1997 millions aprimarily accounts written bprimarily liquidation positions allowance established c11 million credited additional paidin capital utilization zilkha energy company net operating loss nol carryforward 7 million credited deferred tax assets waiver gulf states gas pipeline company nol carryforward ddue acquisition gulf states gas pipeline company item 9item 8 financial statements supplementary data el paso corporation consolidated statements income millions except per common share amounts see accompanying notes el paso corporation consolidated balance sheets millions except common share amounts see accompanying notes el paso corporation consolidated statements cash flows millions see accompanying notes el paso corporation consolidated statements stockholders equity millions except per common share amounts see accompanying notes el paso corporation notes consolidated financial statements 1 summary significant accounting policies basis presentation principles consolidation consolidated financial statements include accounts majorityowned controlled subsidiaries elimination significant intercompany accounts transactions account investments companies ability exert significant influence control operating financial policies using equity method consolidated financial statements previous periods include reclassifications made conform current year presentation reclassifications impact reported net income stockholders equity use estimates preparation financial statements conformity generally accepted accounting principles requires us make estimates assumptions affect reported amounts assets liabilities revenues expenses disclosure contingent assets liabilities exist date financial statements actual results likely differ estimates accounting regulated operations interstate natural gas systems subject jurisdiction ferc accordance natural gas act 1938 natural gas policy act 1978 system operates separate ferc approved tariffs establish rates terms conditions system provides services customers businesses subject regulations accounting requirements ferc followed accounting requirements statement financial accounting standards sfas 71 accounting effects certain types regulation may differ accounting requirements nonregulated entities transactions recorded differently result regulatory accounting requirements include capitalization equity return component regulated capital projects employee related benefits costs taxes included expected included future rates including costs refinance debt accounting method followed required allowed regulatory authority ratemaking purposes method conforms generally accepted accounting principle matching costs revenues apply cash equivalents consider shortterm investments purchased original maturity less three months cash equivalents inventory consists materials supplies natural gas storage nontrading purposes optic fiber constructed sale exchange third parties value inventories lower cost market cost determined using average cost method property plant equipment regulated property plant equipment recorded original cost construction upon acquisition cost entity first placed asset service capitalize direct costs like labor materials indirect costs like overhead allowance funds used construction capitalize major units property replacements improvements expense minor ones applicable use composite group method depreciate regulated property plant equipment assets similar lives characteristics grouped depreciated one asset apply depreciation rate approved rates total cost group net book value equals salvage value currently depreciation rates vary 1 33 percent rates depreciate related assets 2 36 years reevaluate depreciation rates time redevelop transportation rates retire regulated property plant equipment charge accumulated depreciation amortization original cost plus cost retirement cost remove sell dispose less salvage value recognize gain loss unless sell entire operating unit include gains losses dispositions operating units income nonregulated record nonregulated property plant equipment original cost construction upon acquisition fair value assets acquired capitalize direct indirect costs project including interest costs related debt depreciate properties estimated useful lives using straight line composite method annual depreciation rates follows retire nonregulated properties reduce property plant equipment original cost less accumulated depreciation salvage remaining amount charged income general december 31 2000 1999 approximately 875 million 597 million construction work progress included property plant equipment evaluate impairment regulated nonregulated property plant equipment whenever events changes circumstances indicate carrying amount asset may recoverable accordance sfas 121 accounting impairment longlived assets longlived assets disposed natural gas oil properties use full cost method account natural gas oil properties full cost method productive nonproductive costs incurred connection acquisition exploration development natural gas oil reserves capitalized costs include costs unproved properties internal costs directly related acquisition exploration activities capitalized interest amortize costs using unit production method life proved reserves exclude unevaluated properties amortization base make determination existence proved reserves total capitalized costs limited ceiling present value future net revenues discounted 10 percent plus lower cost fair market value unproved properties discounted revenues equal greater total capitalized costs required writedown capitalized costs level 1999 1998 determined capitalized costs exceeded ceiling test limits total 352 million 1035 million writedowns included income statement ceiling test charges treat sale natural gas oil properties adjustment cost properties recognize gain loss sales unless properties sold significant intangible assets intangible assets consist primarily goodwill arising result mergers acquisitions amortize intangible assets using straightline method periods ranging 5 40 years accumulated amortization intangible assets 101 million 62 million december 31 2000 1999 evaluate impairment goodwill accordance sfas 121 methodology event occurs suggest impairment may occurred evaluate undiscounted net cash flows underlying asset entity cash flows sufficient recover value underlying asset entity plus goodwill amount cash flows discounted riskadjusted rate difference recorded charge income statement revenue recognition regulated businesses recognize revenues natural gas transportation period service provided reserves provided revenues collected may subject refund revenues services transportation recorded earned nonregulated businesses record revenues various points earned including deliveries physical commodities made period services provided see discussion price risk management activities revenue recognition policies trading activities fourth quarter 2000 implemented emerging issues task force issue 9919 reporting revenue gross principal versus net agent provides guidance gross versus net presentation revenues expenses result adoption revenues related costs increased 87 million 128 million 60 million 2000 1999 1998 reclassifications impact net income earnings per share environmental costs expenditures ongoing compliance environmental regulations relate current operations expensed capitalized appropriate expense amounts relate existing conditions caused past operations contribute current future revenue generation record liabilities environmental assessments indicate remediation efforts probable costs reasonably estimated estimates liabilities based upon currently available facts existing technology presently enacted laws regulations taking consideration likely effects inflation societal economic factors include estimates associated legal costs amounts also consider prior experience remediating contaminated sites companies cleanup experience data released epa organizations subject revision future periods based actual costs new circumstances included balance sheet undiscounted amounts evaluate recoveries separately liability recovery assured record report asset separately associated liability financial statements price risk management activities utilize derivative financial instruments manage market risks associated commodities sell interest rates foreign currency exchange rates engage trading nontrading commodity price risk management activities trading activities consist services provided energy sector primarily related natural gas power energy trading activities including transportation capacity storage accounted using marktomarket method accounting conduct trading activities variety financial instruments including exchange traded futures contracts involving cash settlement forward contracts involving cash settlement physical delivery energy commodity swap contracts require us make payments receive payments counterparties based difference fixed variable prices commodity exchangetraded overthecounter options contractual arrangements marktomarket method accounting commodity energy related contracts reflected quoted estimated market value resulting gains losses included income statement net gains losses recognized period result primarily impact price movements transactions originating previous periods assets liabilities resulting marktomarket accounting included balance sheets classified according term maturity reflect receivables payables arise upon actual settlement contracts separately price risk management activities balance sheet trade receivables payables cash inflows outflows associated price risk management activities recognized operating cash flows transactions settled years ended december 31 2000 1999 recognized gross margins trading activities 406 million 91 million market value commodity energy related contracts reflects best estimate considers factors including closing exchange overthecounter quotations time value volatility factors underlying contracts values adjusted reflect potential impact liquidating position orderly manner reasonable period time present market conditions reflect types risks including model risk credit risk operational risks absence quoted market prices utilize valuation techniques estimate fair value use techniques requires us make estimations future prices variables including market volatility price correlation market liquidity changes estimates could significant impact market valuations could materially impact estimates derivative financial instruments also utilized connection nontrading activities enter forwards swaps contracts hedge impact market fluctuations assets liabilities contractual commitments hedge accounting applied derivative reduces risk underlying hedged item designated hedge inception expected result financial impacts inversely correlated item hedged correlation ceases exist hedge accounting terminated marktomarket accounting applied changes market value hedged transactions deferred gain loss hedged item recognized derivatives held nontrading purposes recorded gains losses operating income cash inflows outflows recognized operating cash flows transactions settled see note 6 discussion price risk management activities income taxes report income taxes based income reported tax returns along provision deferred income taxes deferred income taxes reflect estimated future tax consequences differences financial statement tax bases assets liabilities carryovers year end account tax credits flowthrough method reduces provision income taxes year tax credits first become available reduce deferred tax assets valuation allowance based upon estimates likely portion assets realized future period estimates utilized recognition deferred tax assets subject revision future periods based new facts circumstances comprehensive income loss comprehensive income loss determined based net income loss adjusted changes accumulated comprehensive income treasury stock account treasury stock using cost method report balance sheet reduction stockholders equity treasury stock sold issued valued firstin firstout basis included treasury stock december 31 2000 1999 136 million shares common stock reserved use several benefit plans well approximately 58 million shares common stock held trust deferred compensation programs stockbased compensation apply provisions accounting principles board opinion 25 related interpretations accounting stock compensation plans accordingly compensation expense recognized stock options unless options granted exercise price lower market grant date use fixed variable plan accounting fixed variable compensation plans cumulative effect accounting change april 1998 american institute certified public accountants issued statement position 985 reporting costs startup activities statement defined startup activities required startup organization costs expensed incurred addition required cost existed balance sheet expensed upon adoption pronouncement adopted pronouncement effective january 1 1999 reported charge 13 million net income taxes cumulative effect accounting change accounting derivative instruments hedging activities june 1998 financial accounting standards board fasb issued statement financial accounting standards sfas 133 accounting derivative instruments hedging activities june 1999 fasb extended adoption date sfas 133 issuance sfas 137 deferral effective date sfas 133 june 2000 fasb issued sfas 138 accounting certain derivative instruments certain hedging activities also amended sfas 133 sfas 133 amendments interpretations establishes accounting reporting standards derivative instruments including derivative instruments embedded contracts derivative instruments used hedging activities requires measure derivative instruments fair value classify either assets liabilities balance sheet corresponding offset income comprehensive income depending designation intended use ability qualify hedges standard adopted sfas 133 january 1 2001 applied standard derivative instruments existed date except derivative instruments embedded contracts provided sfas 133 applied provisions standard derivative instruments embedded contracts issued acquired substantially modified december 31 1998 use variety derivative instruments conduct energy trading activities hedge risks associated commodity prices foreign currencies interest rates derivative instruments use commodity trading activities recorded fair value financial statements provisions emerging issues task force issue 9810 accounting contracts involved energy trading risk management activities result sfas 133 impact accounting instruments based commodity prices interest rates foreign currency exchange rates existing december 31 2000 reflect impact adoption sfas 133 january 1 2001 recording cumulative effect transition adjustment charge comprehensive income 821 million net income taxes reduction assets 37 million increase liabilities 784 million represents fair value derivative instruments designated cash flow hedges majority initial charge relates hedging forecasted sales natural gas expect produce end 2001 accounting transfers servicing financial assets extinguishments liabilities september 2000 fasb issued sfas 140 accounting transfers servicing financial assets extinguishments liabilities replaces sfas 125 statement revises standards accounting securitizations transfers financial assets collateral requires certain disclosures carries sfas 125s provisions without reconsideration standard various effective dates earliest fiscal years ending december 15 2000 pronouncement material effect financial statements 2 mergers acquisitions coastal january 2001 merged coastal accounted transaction pooling interests converted share coastal common stock class common stock taxfree basis 123 shares common stock exchanged coastals outstanding convertible preferred stock common stock basis preferred stock converted coastal common stock immediately prior merger total value transaction approximately 24 billion including 7 billion assumed debt preferred equity merger issued approximately 271 million shares common stock including 4 million shares exchange coastal stock options coastal diversified energy holding company engaged subsidiaries joint ventures natural gas transmission storage gathering processing marketing natural gas oil exploration production petroleum refining marketing distribution chemicals production power production coal mining coastal owns interests approximately 18000 miles natural gas pipelines extending across midwestern rocky mountain areas united states proved reserves 36 tcfe coastal also international domestic interests natural gas oil producing properties power production plants crude oil refining facilities presented unaudited pro forma results merger occurred january 1 1998 1 operating revenues include adjustment conform presentation coastals petroleum trading activities manner presentation texas midstream operations december 2000 completed purchase pges texas midstream operations total value transaction 887 million including assumed debt approximately 527 million transaction accounted purchase included field services segment operations acquired consisted 7500 miles intrastate natural gas transmission natural gas liquids pipelines transport approximately 28 bcfd nine natural gas processing fractionation plants currently process 15 bcfd rights 72 bcf natural gas storage capacity march 2001 sold acquired natural gas liquids transportation several fractionation assets energy partners approximately 133 million sonat october 1999 completed merger sonat diversified energy holding company engaged domestic oil natural gas exploration production transmission storage natural gas natural gas power marketing merger one share common stock issued exchange share sonat common stock total common shares issued merger approximately 110 million transaction valued approximately 7 billion based closing stock price october 25 1999 merger accounted pooling interests divestitures 2000 completed sales east tennessee natural gas company sea robin pipeline company onethird interest destin pipeline company comply federal trade commission order related merger sonat proceeds sales approximately 616 million recognized extraordinary gain 89 million net income taxes 60 million december 2000 sold interest oasis pipeline company comply federal trade commission order incurred loss transaction approximately 19 million net income taxes recorded gains losses sales extraordinary items income statement result merger coastal required federal trade commission sell midwestern system pipeline system midwest total estimated proceeds sale 90 million resulting estimated gain 50 million income taxes expect complete sale second quarter 2001 additionally first quarter 2001 energy partners sold interests several offshore assets sales consisted interests seven natural gas pipeline systems dehydration facility two offshore platforms proceeds sales assets approximately 135 million resulted loss partnership approximately 23 million consideration sales committed pay energy partners series payments totaling 29 million amount well proportional share losses sale partnerships assets recorded charge income statement first quarter 2001 anticipate impact sales material ongoing financial position operating results cash flows 3 mergerrelated costs asset impairment charges mergerrelated costs 2000 1999 1998 incurred mergerrelated charges related mergers coastal sonat merger 1998 zilkha energy company charges included following employee severance retention transition costs include direct payments benefit costs severed employees early retirees occurred result mergerrelated workforce consolidations within operating segments elimination redundant positions within merged operations costs included actual severance payments costs pension postretirement benefits settled curtailed existing benefit plans retention charges include payments employees retained following merger payments employees satisfy contractual obligations transition costs relate costs relocate employees costs severed retired employees arising severance date transition jobs ongoing workforce unpaid portion charges 7 million december 31 2000 76 million december 31 1999 transaction costs include investment banking legal accounting consulting advisory fees incurred obtain federal state regulatory approvals take actions necessary complete mergers mergerrelated asset impairments relate writeoffs writedowns capitalized costs duplicate systems redundant facilities assets whose value impaired result decisions strategic direction combined operations following mergers costs primarily consist charges conform accounting policies practices integrate facilities retain seismic data production operations conjunction coastal merger issued approximately 44 million shares common stock exchange coastal options resulted charge approximately 278 million recorded first quarter 2001 january 30 announced workforce reduction consolidation restructuring resulted reduction 3285 fulltime positions terminations early retirement majority total charges connected restructuring recorded first quarter 2001 estimated approximately 890 million asset impairment charges 2000 1999 incurred asset impairment charges 11 million 42 million 2000 charge resulted field services impairment needle mountain processing facility arizona due unrecoverability costs 1999 charges consisted impairments regulatory assets recoverable based settlement sngs rate case 4 income taxes following table reflects components income tax expense benefit included income loss extraordinary items cumulative effect accounting change three years ended december 31 tax expense benefit included income loss extraordinary items cumulative effect accounting change differs amount computed applying statutory federal income tax rate 35 percent following reasons december 31 following components net deferred tax liability december 31 december 31 2000 portion cumulative undistributed earnings foreign subsidiaries foreign corporate joint ventures recorded us income taxes approximately 178 million since earnings intended indefinitely reinvested foreign operations provision made us taxes foreign withholding taxes may applicable upon actual deemed repatriation distribution earnings made might subject foreign withholding taxes us income taxes net allowable foreign tax credits deductions however estimate taxes practicable reasons recorded provision us income taxes foreign currency translation adjustment recorded comprehensive income tax benefit associated exercise nonqualified stock options vesting restricted stock well restricted stock dividends reduced taxes payable 42 million 2000 13 million 1999 10 million 1998 benefits included additional paidin capital balance sheets december 31 2000 capital loss carryovers 21 million carryover period ends 2001 alternative minimum tax credits 71 million carryover indefinitely 2 million general business credit carryovers carryover periods end various times years 2006 2017 usage carryovers subject limitations provided sections 382 383 internal revenue code well separate return limitation year rules irs regulations table presents details net operating loss carryover periods recorded valuation allowance reflect estimated amount deferred tax assets may realize due expiration net operating loss tax credit carryovers december 31 2000 1999 approximately 1 million 4 million respectively valuation allowance relates net operating loss carryovers acquired company remainder allowance relates general business credit carryovers exception 2 million tax benefits subsequently recognized reversal allowance allocated additional acquisition cost assigned utility plant prior 1999 subsidiary el paso tennessee pipeline co subsidiaries filed separate consolidated federal income tax return consolidated return january 1 1999 result 1998 taxfree internal reorganization el paso tennessee subsidiaries joined consolidated federal income tax group subsidiaries sonat inc joined consolidated federal income tax group october 26 1999 merger coastal merger file consolidated federal income tax return coastal connection acquisition el paso tennessee entered tax sharing agreement newport news shipbuilding inc new tenneco inc el paso tennessee tax sharing agreement provides among things allocation among parties tax assets liabilities arising prior result subsequent distributions new tenneco inc newport news shipbuilding inc shareholders old tenneco inc known el paso tennessee 5 earnings per share calculated basic diluted earnings per share amounts follows 1 addition potential average common shares outstanding 1999 1998 antidilutive would reduced loss per share 6 financial instruments price risk management activities fair value financial instruments carrying amounts estimated fair values financial instruments december 31 follows 1 excludes transportation capacity tolling agreements natural gas storage held trading purposes since constitute financial instruments december 31 2000 1999 carrying amounts cash equivalents shortterm borrowings trade receivables payables representative fair value shortterm nature instruments fair value longterm debt variable interest rates approximates carrying value market based nature debts interest rates estimated fair value debt fixed interest rates based quoted market prices similar issues estimated fair value derivative financial instruments based quoted market prices current market conditions estimates obtained thirdparty brokers dealers amounts derived using valuation models trading commodity activities fair value commodity energy related contracts entered trading purposes december 31 2000 1999 average fair value instruments set forth 1 computed using net asset liability balance month end notional amounts terms notional amounts terms energy commodity financial instruments december 31 2000 1999 set forth natural gas volumes trillions british thermal units power volumes millions megawatt hours liquids volumes millions barrels weather volumes thousands degree days energy capacity volumes millions kilowatt hours 1 liquids include crude oil condensate natural gas liquids notional amount terms foreign currency forward purchases sales december 31 2000 1999 follows notional amounts reflect volume transactions represent actual amounts exchanged parties result notional amounts incomplete measure exposure market credit risks maximum terms years detailed indicative likely future cash flows positions may offset cashedout commodity currency markets based risk management needs liquidity markets weighted average maturity entire portfolio price risk management activities approximately two years december 31 2000 six years december 31 1999 market credit risks serve diverse customer group generates need variety financial structures products terms diversity requires us manage portfolio basis resulting market risks inherent transactions subject parameters established risk management committee monitor market risks risk control committee operating independently units create actively manage risk exposures ensure compliance stated risk management policies measure adjust risk portfolio accordance marktomarket risk management methodologies utilize forward price curves energy markets estimate size probability future potential exposure credit risk relates risk loss would incur result nonperformance counterparties pursuant terms contractual obligations maintain credit policies regard counterparties minimize overall credit risk policies require evaluation potential counterparties financial condition including credit rating collateral requirements certain circumstances including cash advance letters credit guarantees use standardized agreements allow netting positive negative exposures associated single counterparty counterparties associated assets price risk management activities summarized follows 1investment grade primarily determined using publicly available credit ratings along consideration collateral encompass standby letters credit parent company guarantees property interest including natural gas oil reserves included investment grade counterparties minimum standard poors moodys rating bbb baa3 respectively minimum implied internal credit analysis standard poors equivalent rating bbb 2we one customer 2000 four customers 1999 comprised greater 5 percent assets price risk management activities customers investment grade ratings concentration counterparties may impact overall exposure credit risk either positively negatively counterparties may similarly affected changes economic regulatory conditions based policies risk exposure reserves anticipate material adverse effect financial position operating results cash flows result counterparty nonperformance nontrading price risk management activities also utilize derivative financial instruments nontrading activities mitigate market price risk associated significant physical transactions nontrading commodity activities accounted using hedge accounting provided meet hedge accounting criteria nontrading activities conducted exchange traded futures contracts swaps forward agreements third parties december 31 2000 1999 notional amounts terms contracts held purposes trading follows august 1999 entered interest rate swap agreement notional amount 600 million termination date july 2001 agreement swapped fixed interest rate july 1999 600 million aggregate principal senior notes due 2001 floating three month libor plus margin 1475 basis points total interest expense less 1 million 2000 1999 result swap agreement november 2000 terminated swap termination swap material impact financial results may 2000 terminated equity swap transaction associated additional 185 percent capsas outstanding stock purchased counterpartys 185 percent interest capsa approximately 127 million capsa privately held argentine company engaged power generation natural gas oil production swap paid interest counterparty quarterly basis notional amount 103 million rate libor plus 175 percent exchange received dividends capsa stock extent counterpartys equity interest 185 percent also fully participated market appreciation depreciation underlying investment whereby realized appreciation funded depreciation attributable actual sale stock upon termination expiration swap transaction termination swap material impact financial results also face credit risk respect nontrading activities take similar measures trading activities mitigate risk based upon policies risk exposure anticipate material effect financial position operating results cash flows resulting counterparty nonperformance 7 inventory consisted following december 31 8 property plant equipment property plant equipment consisted following december 31 additional acquisition cost assigned utility plant represents excess allocated purchase costs historical costs facilities costs amortized straightline basis remaining lives facilities recover excess costs rates 9 debt credit facilities average interest rate shortterm borrowings 74 66 december 31 2000 1999 following shortterm borrowings including current maturities longterm debt december 31 longterm debt outstanding consisted following december 31 aggregate maturities principal amounts longterm debt next 5 years total thereafter follows financing arrangements december 31 2000 2 billion 364day renewable credit competitive advance facility 1 billion 3year revolving credit competitive advance facility facilities replaced 1250 million 750 million revolving credit facilities august 2000 epng tgp also designated borrowers facilities interest rate facilities varies libor plus 50 basis points december 31 2000 amounts outstanding facilities december 31 2000 october 2000 established 30 million multicurrency revolving credit facility 364day facility allows us access us dollars english pounds german marks norwegian kroner euros interest rate facility varies libor plus 50 basis points december 31 2000 amounts outstanding december 31 2000 december 2000 established 700 million floating rate bridge facility use connection acquisition pges texas midstream operations december 31 2000 455 million outstanding facility part acquisition assumed approximately 527 million debt february 2001 borrowed balance facility redeemed 340 million debt assumed use commercial paper program manage shortterm cash requirements program borrow 1 billion addition tgp epng ability individually borrow 1 billion march 2001 tgp 200 million sng 100 million shelf registration statements file securities exchange commission availability borrowings credit agreements subject specified conditions believe currently meet conditions include compliance financial covenants ratios required agreements absence default agreements continued accuracy representations warranties contained agreements including absence material adverse changes senior debt issues given investment grade ratings standard poors moodys financial activities significant longterm debt issuances retirements 2000 1999 follows issuances 1 net proceeds primarily used repay shortterm borrowings general corporate purposes retirements addition established drew upon 250 million noncommitted line credit january 2000 march 2000 repaid facility may 2000 issued preferred securities consolidated trust el paso energy capital trust iv proceeds approximately 293 million net issuance costs used general corporate purposes also received approximately 984 million thirdparty investor 2000 result sale preferred interest clydesdale associates lp consolidated joint venture 1999 received net proceeds 960 million thirdparty investor result sale preferred interest trinity river associates llc consolidated joint venture proceeds issuances used repay shortterm debt corporate purposes discussion transactions see note 10 securities subsidiaries november 2000 terminated interest rate swap notional amount 600 million termination date july 2001 swap originally put place swap 6625 fixed interest rate july 1999 600 million aggregate principal senior notes due 2001 variable interest rate termination swap material impact financial results october 1999 mojave pipeline company terminated associated interest rate swap cost approximately 5 million also entered various financing transactions unconsolidated affiliates see note 17 investments unconsolidated affiliates discussion transactions financing activities 2001 february 2001 sng issued 300 million aggregate principal amount 735 notes due 2031 proceeds approximately 297 million net issuance costs used pay 100 million sngs 8875 notes due 2001 general corporate purposes also february 2001 issued approximately 18 billion zero coupon convertible debentures due 2021 yield maturity 4 proceeds approximately 784 million net issuance costs used repay shortterm borrowings general corporate purposes debentures convertible 8456589 shares common stock based conversion rate 47872 shares per 1000 principal amount maturity rate equivalent initial conversion price 94604 per share common stock march 2001 issued e550 million approximately 510 million euro notes 575 due 2006 proceeds approximately 505 million net issuance costs used repay shortterm debt general corporate purposes reduce exposure foreign currency risk entered swap transaction exchanging euro note 510 million us dollar denominated obligation fixed interest rate 661 five year term note 10 securities subsidiaries companyobligated preferred securities march 1998 formed el paso energy capital trust issued 65 million 4 34 trust convertible preferred securities 325 million 317 million net issuance costs common securities trust used net proceeds preferred securities pay commercial paper trust exists sole purpose issuing preferred securities investing proceeds 4 34 convertible subordinated debentures due 2028 sole asset guarantee trust preferred securities trust preferred securities reflected companyobligated preferred securities consolidated trusts balance sheet distributions paid preferred securities included minority interest income statement trust preferred securities nonvoting except limited circumstances pay quarterly distributions annual rate 4 34 carry liquidation value 50 per security plus accrued unpaid distributions convertible common shares time prior close business march 31 2028 option holder rate 12022 common shares trust preferred security equivalent conversion price 4159 per common share subject adjustment certain circumstances may 2000 formed el paso energy capital trust iv issued 300 million 293 million net issuance costs preferred securities third party investor preferred securities pay cash distributions floating rate equal threemonth libor plus 75 basis points december 31 2000 floating rate 749 preferred securities must redeemed trust iv later november 30 2003 proceeds sale securities used trust iv purchase series floating rate senior debentures whose yield maturity terms mirror trust ivs preferred securities sole assets trust iv floating rate senior debentures guarantee obligations trust iv related preferred securities time trust iv issued preferred securities also agreed issue 300 million equity securities including limited common stock one public offerings prior may 31 2003 minority interests trinity river 1999 formed sabine river investors llc wholly owned limited liability company separate legal entities generate funds invest capital projects assets sabine contributed 250 million equity capital trinity river associates llc thirdparty investor contributed 980 million thirdparty investor entitled adjustable preferred return derived trinitys net income trinity used proceeds invest note receivable sabine collateralized selected assets option acquire thirdpartys interest trinity time prior june 2004 exercise option agreement extended trinitys note receivable sabine mature portion proceeds used trinity redeem thirdparty interest trinity assets liabilities operations sabine trinity entities involved transaction included consolidated financial statements clydesdale may 2000 formed clydesdale associates lp limited partnership several separate legal entities generate funds invest capital projects assets initially contributed 55 million equity capital clydesdale thirdparty investor contributed 250 million december 2000 contributed additional 200 million clydesdale thirdparty investor contributed additional 750 million thirdparty investor entitled adjustable preferred return derived clydesdales net income clydesdale used proceeds invest note receivable us thirdpartys contributions collateralized production properties rental income real estate assets notes receivable us option acquire thirdpartys interest clydesdale time prior may 2005 exercise option agreement extended note receivable mature portion proceeds used redeem thirdparty interest clydesdale assets liabilities operations entities involved transaction included consolidated financial statements preferred stock subsidiary november 1996 el paso tennessee pipeline co issued 6 million shares 825 cumulative preferred stock par value 50 per share 296 million net issuance costs preferred stock redeemable option el paso tennessee december 31 2001 redemption price equal 50 per share plus dividends accrued unpaid date redemption 2000 1999 1998 dividends approximately 25 million paid year preferred stock 11 commitments contingencies legal proceedings august 19 2000 main transmission line owned operated epng ruptured crossing pecos river near carlsbad new mexico twelve individuals site fatally injured eleven lawsuits brought behalf twelve deceased persons filed epng epec damages personal injuries wrongful death three state district court harris county texas diane heady et al v epec epng filed september 7 2000 richard heady v epec epng filed february 15 2001 geneva smith v epec epng filed october 23 2000 two federal district court albuquerque new mexico dawson v epec epng filed november 8 2000 jennifer smith v epec epng filed august 29 2000 six state district court carlsbad new mexico chapman personal representative estate amy smith heady v epec epng john cole filed february 9 2001 chapman v epec epng john cole green v epec epng john cole rackley personal representative estate glenda gail sumler v epec epng john cole rackley personal representative estate amanda sumler smith v epec epng john cole filed march 16 2001 march 2001 settled claims heady cases payments four claimants fully covered insurance national transportation safety board conducting investigation facts circumstances concerning possible causes rupture august 2000 liquidating trustee bankruptcy power corporation america pca sued el paso merchant energy several power traders us bankruptcy court connecticut claiming el paso merchant energy improperly cancelled contracts pca summer 1998 trustee alleges breached contracts damaging pca amount 120 million entered joint defense agreement defendants matter mediated second quarter 2001 related matter pca appealed fercs ruling power marketers epme give 60 days notice cancel power contracts federal power act pca appealed decision united states court appeals oral arguments heard january 2001 awaiting courts decision late 2000 several subsidiaries including el paso natural gas company el paso merchant energy named defendants four purported class action lawsuits filed state court california continental forge co v southern california gas co et al los angeles berg v southern california gas co et al los angeles john phillip v el paso merchant energy et al san diego john whk phillip v el paso merchant energy et al san diego two cases filed los angeles contend generally entities conspired unrelated companies create artificially high prices natural gas california two cases filed san diego assert companies used merchant energys acquisition capacity epng pipeline manipulate market natural gas california remanded cases federal courts california filed motions dismiss san diego actions march 20 2001 two additional lawsuits city los angeles et al v southern california gas company et al city long beach et al v southern california gas company et al filed los angeles county superior court cases seek monetary damages us several subsidiaries make similar allegations continental forge berg cases discussed 1999 number subsidiaries named defendants actions brought jack grynberg behalf us government false claims act generally complaints allege industrywide conspiracy report heating value well volumes natural gas produced federal native american lands deprived us government royalties matters consolidated pretrial purposes natural gas royalties qui tam litigation us district court district wyoming number subsidiaries named defendants action styled quinque operating company et al v gas pipelines predecessors et al filed 1999 district court stevens county kansas class action complaint alleges defendants mismeasured natural gas volumes heating content natural gas nonfederal nonnative american lands quinque complaint transferred court handling grynberg complaint sent back kansas state court proceedings february 1998 united states state texas filed us district court comprehensive environmental response compensation liability act cercla cost recovery action fourteen companies including current former affiliates related sikes disposal pits superfund site located harris county texas suit claims united states state texas spent 125 million remediating sikes seeks recover amount plus interest defendants suit epa recently indicated may seek additional amount 30 million plus interest indirect costs defendants new cost allocation methodology defendants challenging allocation policy although investigation relating sikes ongoing believe amount material disposed sikes former affiliates small possibly de minimis however plaintiffs alleged defendants jointly severally liable entire remediation costs also sought declaration liability future response costs groundwater monitoring tgp party proceedings involving federal state authorities regarding past use lubricant containing polychlorinated biphenyls pcbs starting air systems tgp executed consent order epa governing remediation compressor stations working epa relevant states regarding remediation activities tgp also working pennsylvania new york environmental agencies regarding remediation postremediation activities pennsylvania new york stations november 1988 kentucky environmental agency filed complaint kentucky state court alleging tgp discharged pollutants waters state disposed pcbs without permit agency sought injunction future discharges order remediate remove pcbs civil penalty tgp entered agreed orders agency resolve many issues raised original allegations received water discharge permits agency kentucky compressor stations continues work resolve remaining issues relevant kentucky compressor stations characterized remediated consent order epa also named defendant numerous lawsuits named party numerous governmental proceedings arising ordinary course business outcome matters discussed cannot predicted certainty expect ultimate resolution matters material adverse effect financial position operating results cash flows environmental subject extensive federal state local laws regulations governing environmental quality pollution control laws regulations require us remove remedy effect environment disposal release specified substances current former operating sites december 31 2000 reserve approximately 274 million expected remediation costs including approximately 257 million associated onsite offsite groundwater technical studies approximately 17 million costs anticipate incurring 2027 addition expect make capital expenditures environmental matters approximately 103 million aggregate years 2001 2007 expenditures primarily relate compliance air regulations since 1988 tgp engaged internal project identify deal presence pcbs substances including epa list hazardous substances compressor stations facilities operates conducting project tgp frequent contact federal state regulatory agencies informal negotiation formal entry consent orders ensure efforts meet regulatory requirements may 1995 following negotiations customers tgp filed stipulation agreement environmental stipulation ferc established mechanism recovering substantial portion environmental costs identified internal project environmental stipulation effective july 1 1995 december 31 1999 amounts collected customers refunds may required extent actual eligible expenditures less amounts collected designated received notice could designated asked information determine whether could designated potentially responsible party prp respect 29 sites comprehensive environmental response compensation liability act cercla superfund state equivalents sought resolve liability prp superfund sites indemnification third parties andor settlements provide payment allocable share remediation costs december 31 2000 estimated share remediation costs sites 59 million 194 million provided reserves believe adequate costs since cleanup costs estimates subject revision information becomes available extent remediation required cases asserted defense liability estimates could change moreover liability federal superfund statute joint several meaning could required pay excess pro rata share remediation costs understanding financial strength prps considered appropriate determination estimated liabilities presently believe costs associated superfund sites material adverse effect financial position operating results cash flows possible new information future developments could require us reassess potential exposure related environmental matters may incur significant costs liabilities order comply existing environmental laws regulations also possible developments increasingly strict environmental laws regulations claims damages property employees persons environment resulting current past operations could result substantial costs liabilities future information becomes available relevant developments occur adjust accrual amounts accordingly still uncertainties relating ultimate costs may incur based upon evaluation experience date believe recorded reserves adequate discussion specific environmental matters see legal proceedings rates regulatory matters april 2000 california public utilities commission cpuc filed complaint alleging el paso natural gas sale capacity merchant energy anticompetitive abuse affiliate relationship fercs policies cpuc served data requests us either substantially answered contested august 2000 cpuc filed motion requesting contract epng merchant energy terminated parties proceedings requested original complaint set hearings merchant energy pay back profits earned contract matter pending ferc february 2001 epng completed open season 1221 mmcfd capacity held merchant energy may 2001 capacity resubscribed contracts awarded 30 different entities including 271 mmcfd merchant energy published tariff rates contracts durations 17 months 15 years cannot predict certainty final outcome timing resolution rates regulatory matters believe ultimate resolution issues material adverse effect financial position results operations cash flows capital commitments purchase obligations december 31 2000 capital investment commitments 12 billion primarily relating production pipeline international power activities planned capital investment projects discretionary nature substantial capital commitments made advance actual expenditures connection financing commitments one joint ventures tgp entered unconditional purchase obligations products services totaling 122 million december 31 2000 tgps annual obligations agreements 21 million years 2001 2002 2003 2004 2005 17 million total thereafter operating leases lease property facilities equipment various operating leases 1995 el paso new chaco company epnc entered unconditional lease chaco plant lease term expires 2002 time epnc option obligation upon occurrence various events purchase plant price sufficient pay amount 77 million construction financing plus interest expenses epnc purchase plant end lease term obligation pay residual guaranty amount equal approximately 87 percent amount financed plus interest unconditionally guaranteed obligations epnc lease minimum annual rental commitments december 31 2000 follows aggregate minimum commitments reduced minimum sublease rentals approximately 14 million due future noncancelable subleases rental expense operating leases years ended december 31 2000 1999 1998 58 million 37 million 39 million guarantees december 31 2000 parental guarantees approximately 2 billion connection international development activities various projects including approximately 1 billion associated investments unconsolidated affiliates discussed note 17 believe parties able perform guaranteed transactions payments required losses incurred us guarantees also outstanding letters credit approximately 233 million december 31 2000 december 31 1999 parental guarantees totaled approximately 1 billion outstanding letters credit 170 million 12 retirement benefits pension benefits prior january 1 1997 maintained defined benefit pension plan covered substantially employees pension benefits based years credited service final five year average compensation subject maximum limitations defined plan effective january 1 1997 plan amended provide benefits determined cash balance formula include employees added result merger el paso tennessee acquisitions prior 1997 employees pension plan participants december 31 1996 receive greater cash balance benefits prior plan benefits accrued december 31 2001 following merger sonat offered early retirement incentive program sonat employees least 50 years age 10 years service december 31 1999 terminated employment june 30 2000 total charges result early retirement program approximately 8 million effective january 1 2000 sonat pension plan merged pension plan sonat employees participants sonat pension plan sonat merger effective date receive greater cash balance benefits sonat plan benefits accrued december 31 2004 postretirement benefits provide postretirement medical benefits certain closed groups retired employees epng el paso tennessee sonat limited postretirement life insurance benefits current retired employees postretirement employee benefits opeb prefunded extent costs recoverable rates early retirement incentive program sonat employees pges texas midstream operations participating eligible employees allowed keep postretirement medical life benefits commencing later age 55 retirement total charges associated sonat incentive program elimination retiree benefits future retirees 29 million accrued december 31 1999 total liabilities pge group 8 million accrued december 31 2000 medical benefits closed groups retirees may subject deductibles copayment provisions limitations dollar caps amount employer costs reserved right change benefits following table sets forth change benefit obligation change plan assets reconciliation funded status components net periodic benefit cost pension benefits postretirement benefits twelve month period ended september 30 included pension benefits information plans projected benefit obligation accumulated benefit obligation pension plans accumulated benefit obligations excess plan assets 37 million 31 million december 31 2000 57 million 53 million december 31 1999 current liability portion postretirement benefits 46 million december 31 2000 1999 respectively benefit obligations based upon actuarial estimates described actuarial estimates postretirement benefits plans assumed weighted average annual rate increase per capita costs covered health care benefits 10 percent 2000 gradually decreasing 6 percent year 2008 assumed health care cost trends significant effect amounts reported postretirement benefit plans onepercentage point change assumed health care cost trends would following effects retirement savings plan maintain defined contribution plan covering employees match 75 percent participant basic contributions 6 percent matching contribution made stock prior sonat merger sonat matched 100 percent participant basic contributions 6 percent amounts expensed plan approximately 14 million 16 million 16 million years ended december 31 2000 1999 1998 respectively 13 capital stock 50000000 shares authorized preferred stock par value 001 per share none issued 7500000 shares designated series junior participating preferred stock reserved issuance pursuant preferred stock purchase rights plan 14 stockbased compensation 2000 1999 1998 granted stock options various stock option plans account plans using accounting principles board opinion 25 related interpretations 1995 financial accounting standards board issued sfas 123 accounting stockbased compensation fully adopted changes methods companies use determining expense related stock option plans adoption expense recognition provisions sfas 123 optional elected apply provisions however required present following pro forma disclosures adopted sfas 123 existing stock option plans authorized issue shares common stock employees nonemployee directors pursuant awards granted incentive stock options intended qualify section 422 internal revenue code nonqualified stock options restricted stock appreciation rights sars phantom stock options performance units reserved approximately 53 million shares common stock issuance pursuant existing future stock awards december 31 2000 approximately 27 million shares remained unissued nonqualified stock options granted nonqualified stock options employees 2000 1999 1998 stock options contractual terms 10 years generally vest completion one five years continuous employment grant date also granted options nonemployee members board directors fair market value grant date exercisable immediately terms certain plans may grant sars certain holders stock options sars subject terms conditions related stock options december 31 2000 sars outstanding summary status stock options december 31 2000 1999 1998 presented fair value stock option granted estimated date grant using blackscholes optionpricing model following weightedaverage assumptions blackscholes weighted average fair value options granted 2000 1999 1998 1016 1142 700 respectively options outstanding december 31 2000 summarized pro forma net income net income per common share compensation expense stockbased compensation plans determined applying provisions sfas 123 net income net income per common share 2000 1999 1998 would approximate pro forma amounts effects applying sfas 123 pro forma disclosure indicative future amounts sfas 123 apply awards granted prior 1995 fiscal year restricted stock various stockbased compensation plans limited number shares restricted common stock may granted cost certain key officers employees shares carry voting dividend rights however sale transfer shares restricted stock awards vest specific period time andor achieve certain performance targets restricted stock awards representing 04 million 14 million 06 million shares granted 2000 1999 1998 respectively weighted average grant date fair value 3482 3510 3240 per share respectively december 31 2000 15 million shares restricted stock outstanding value shares determined based fair market value date performance targets achieved value charged compensation expense ratably required service restriction period 2000 1999 1998 charges totaled 13 million 69 million 29 million included deferred compensation december 31 2000 69 million related options converted holders election common stock end vesting period options met performance targets december 2000 performance units phantom stock options award eligible employees phantom stock options payable cash also award eligible employees officers performance units payable cash stock end vesting period final value performance units may vary according plan granted usually based common stock price end vesting period value performance units charged ratably compensation expense vesting period periodic adjustments account fluctuation market price stock amounts charged compensation expense 2000 1999 1998 25 million 30 million 13 million included 1999 amount 22 million related accelerated vesting performance units due change control resulting merger sonat march 2001 paid phantom stock options resulting charge 51 million employee stock purchase program october 1999 implemented employee stock purchase plan section 423 internal revenue code plan allows participating employees right purchase common stock quarterly basis 85 percent lower market price beginning plan period end calendar quarter two million shares common stock authorized issuance plan issued 346332 shares 3233 per share 2000 139842 shares 3310 per share 1999 funds receive may used general corporate purposes however record liability withholdings yet applied towards purchase common stock bear expenses associated administering plan except costs including applicable taxes associated participants sale common stock 15 segment information business activities segregated four segments pipelines merchant energy field services production segments strategic business units offer variety different energy products services manage segment separately business requires different technology marketing strategies 2000 combined international merchant energy segments reflect ongoing globalization merchant energys strategy operating activities prior periods restated reflect current year presentation pipeline segment provides natural gas transmission services us conduct activities five wholly owned two partially owned interstate systems along liquified natural gas terminalling facility various natural gas storage facilities merchant energy segment involved broad range activities energy marketplace including asset ownership trading risk management financial services buy sell trade natural gas power crude oil refined products coal energy commodities throughout world interests 64 power generation plants 16 countries field services segment provides natural gas gathering storage products extraction fractionation dehydration purification compression intrastate transmission services field services assets located prolific active production areas us including san juan basin east south texas louisiana gulf mexico production segment engaged exploration acquisition development production natural gas oil natural gas liquids major producing basins united states production onshore coal seam operations properties 11 states offshore operations properties federal state waters gulf mexico also exploration production rights turkey accounting policies individual segments described note 1 since earnings equity investments significant component earnings several segments evaluate segment performance based earnings interest taxes ebit instead operating income extent practicable results operations years ended december 31 1999 1998 reclassified conform current business segment presentation although results necessarily indicative results would achieved revised business segment structure effect period 1 includes corporate eliminations well telecommunications significant activity 1 includes corporate eliminations 1 includes corporate eliminations reconciliations ebit income loss extraordinary items cumulative effect accounting change presented prior current year customers whose revenues exceeded 10 percent total revenues 2000 merchant energy revenues 21 billion subsidiaries enron corp revenues excess 10 percent customer 2000 16 supplemental cash flow information following table contains supplemental cash flow information years ended december 31 see notes 2 17 discussion noncash investing transactions related acquisitions 17 investments advances unconsolidated affiliates unaudited hold investments various unconsolidated affiliates accounted using equity method accounting principal equity method investees international pipelines interstate pipelines power generation plants gathering systems investment balance includes unamortized purchase price differences 415 million 105 million december 31 2000 1999 amortized remaining life unconsolidated affiliates underlying assets investments advances unconsolidated affiliates follows equity earnings losses unconsolidated affiliates follows summarized financial information proportionate share unconsolidated affiliates follows following table shows revenues charges unconsolidated affiliates chaparral investors 1999 contributed approximately 120 million equity capital assets newly formed limited liability company chaparral thirdparty financial investor contributed approximately 123 million earn preferred return connection transaction chaparral formed wholly owned subsidiary mesquite merchant energy manages chaparral mesquite january 2000 acquired additional interest chaparral exchange 160 million contingent interest promissory note maturity date note earlier december 2019 upon occurrence events specified note carries variable interest rate exceed 1275 percent december 31 1999 note payable 121 million chaparral payable upon demand carried variable interest rate 64 note repaid 2000 also note receivable mesquite balance 262 million december 31 1999 note payable demand variable rate 83 note repaid mesquite 2000 issued note payable mesquite note payable demand balance 241 million rate 73 december 31 2000 first quarter 2000 chaparral completed acquisitions several domestic nonutility generation assets including equity interests eleven natural gasfired combined generation facilities california two natural gasfired electric generation plants located dartmouth massachusetts pawtucket rhode island outstanding shares bonneville pacific corporation owns 50 percent interest power generation facility chaparral also acquired several operating companies provide services required operate maintain newly acquired facilities natural gas service company provides fuel procurement services eight chaparrals natural gasfired combined generation facilities california chaparral acquired assets us exchange notes payable amount 385 million march 2000 chaparrals thirdparty investor increased overall investment chaparral 1027 million proceeds used chaparral repay 647 million notes us make 278 million contribution trust provided chaparral agreement invest note us fund transaction costs also march 2000 issued mandatorily convertible preferred stock trust control upon occurrence certain negative events trustee trust may required remarket preferred stock terms designed generate 1 billion distribute third party investor management agreement chaparral earn performance based management fee also reimbursed expenses incur behalf chaparral 2000 management fee related chaparral 100 million fee included 80 million performancebased component 20 million reimbursement costs incurred behalf chaparral fee collected recognized ratably throughout year management services provided also sell natural gas buy power qualifying power facilities owned chaparral photon investors 2000 contributed 44 million equity capital assets newly formed limited liability company photon investors llc acquires holds telecommunications assets thirdparty financial investor contributed 60 million earn preferred return connection transaction photon formed wholly owned subsidiary quanta investors llc subsidiary manages photon quanta 2000 entered credit agreement quanta commitment us lend 500 million approximately 94 million advanced outstanding december 31 2000 amounts evidenced subordinated promissory note payable earlier quantas liquidation date agreed parties note also demand note payable quanta balance approximately 61 million december 31 2000 credit agreement demand note carry variable interest rate 957 per annum 2000 investment photon accounted using equity method accounting el paso energy partners third quarter 2000 energy partners completed public offering 46 million common units offering reduced common units ownership interest 325 percent 278 percent transaction effect general partner interest nonmanaging member interest also third quarter received 170 million series b preference units exchange transfer natural gas storage businesses crystal gas storage inc wholly owned subsidiary energy partners preference units accrue dividends rate 10 percent cumulative basis redeemable option energy partners first quarter 2001 result merger coastal energy partners sold interest several offshore assets sales consisted interests seven natural gas pipeline systems dehydration facility two offshore platforms proceeds sales approximately 135 million resulted loss partnership approximately 23 million consideration sales committed pay energy partners series payments totaling 29 million amount well proportional share losses sale partnerships assets recorded charge income statement first quarter 2001 18 supplemental selected quarterly financial information unaudited financial information quarter summarized 1 fourth quarter 2000 restated operating revenues 1999 2000 due implementation emerging issues task force issue 9919 reporting revenue gross principal versus net agent first second third quarters 2000 operating revenues increased 26 million 23 million 38 million first second third fourth quarters 1999 operating revenues increased 23 million 50 million 34 million 21 million adjustments impact net income loss earnings per share 19 supplemental natural gas oil operations unaudited december 31 2000 leases approximately 27 million net acres 11 states including louisiana new mexico texas oklahoma arkansas well gulf mexico also exploration production rights turkey capitalized costs relating natural gas oil producing activities related accumulated depreciation depletion amortization follows costs incurred natural gas oil producing activities whether capitalized expensed follows presented analysis capitalized costs natural gas oil properties year expenditure amortized december 31 2000 pending determination proved reserves capitalized interest 9 million 12 million 2 million years ended december 31 2000 1999 1998 included presentation projects presently excluded amortization various stages evaluation majority costs expected included amortization calculation years 2001 2004 total amortization expense per mcfe including ceiling test charges 097 254 481 2000 1999 1998 excluding ceiling test charges amortization expense would 095 106 per mcfe 1999 1998 net quantities proved developed undeveloped reserves natural gas liquids including condensate crude oil changes reserves follows numerous uncertainties inherent estimating quantities proved reserves projecting future rates production timing development expenditures including many factors beyond control reserve data represents estimates reservoir engineering subjective process estimating underground accumulations natural gas oil cannot measured exact manner significant changes reserves purchases sales production due reservoir performance existing fields drilling additional wells existing fields major discoveries events favorable adverse may considered caused significant change estimated proved reserves since december 31 2000 results operations producing activities fiscal year follows standardized measure discounted future net cash flows relating proved natural gas oil reserves follows calculations preceding table estimated future cash inflows estimated future production proved reserves computed using yearend market natural gas oil prices may receive amounts different standardized measure discounted cash flow number reasons including price changes effects hedging activities following principal sources change standardized measure discounted future net cash flows report independent accountants board directors stockholders el paso corporation opinion consolidated financial statements listed index appearing item 14a 1 present fairly material respects consolidated financial position el paso corporation december 31 2000 1999 consolidated results operations cash flows three years period ended december 31 2000 conformity accounting principles generally accepted united states america addition opinion financial statement schedule listed index appearing item 14a 2 presents fairly material respects information set forth therein read conjunction related consolidated financial statements financial statements financial statement schedule responsibility companys management responsibility express opinion financial statements financial statement schedule based audits conducted audits statements accordance auditing standards generally accepted united states america require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements assessing accounting principles used significant estimates made management evaluating overall financial statement presentation believe audits provide reasonable basis opinion pricewaterhousecoopers llp houston texas march 20 2001 schedule ii el paso corporation valuation qualifying accounts years ended december 31 2000 1999 1998 millions aprimarily accounts written bprimarily liquidation positions allowance established c11 million deduction credited additional paidin capital utilization zilkha energy companys net operating loss nol carryforward 7 million credited deferred tax assets waiver gulf states gas pipeline companys nol carryforward item 9item 8 financial statements supplementary data el paso corporation consolidated statements income millions except per common share amounts see accompanying notes el paso corporation consolidated balance sheets millions except share amounts see accompanying notes el paso corporation consolidated balance sheets continued millions except share amounts see accompanying notes el paso corporation consolidated statements cash flows millions see accompanying notes el paso corporation consolidated statements stockholders equity millions see accompanying notes el paso corporation consolidated statements comprehensive income changes accumulated comprehensive income millions see accompanying notes el paso corporation notes consolidated financial statements 1 summary significant accounting policies basis presentation consolidated financial statements include accounts majorityowned controlled subsidiaries elimination significant intercompany accounts transactions financial statements prior periods include reclassifications made conform current year presentation reclassifications impact reported net income stockholders equity principles consolidation consolidate entities ability control operating financial decisions policies entity exert significant influence control policies decisions apply equity method accounting use cost method accounting unable exert significant influence entity determination ability control exert significant influence entity involves use judgment extent control influence equity owners participants entity use estimates preparation financial statements conformity us generally accepted accounting principles requires use estimates assumptions affect amounts report assets liabilities revenues expenses disclosures financial statements actual results often differ estimates accounting policies asset impairments natural gas oil properties environmental costs contingencies price risk management activities require estimates involve complex situations high degree judgment estimates often change accounting regulated operations interstate natural gas systems storage operations subject jurisdiction ferc accordance natural gas act 1938 natural gas policy act 1978 regulated interstate systems apply provisions statement financial accounting standards 71 accounting effects certain types regulation except anr cig wic discontinued application 1996 accounting businesses regulated apply provisions sfas 71 differ accounting requirements nonregulated businesses transactions recorded differently result regulatory accounting requirements include capitalization equity return component regulated capital projects employee related benefits costs taxes included expected included future rates cash equivalents consider shortterm investments original maturity less three months cash equivalents allowance doubtful accounts establish provisions losses accounts receivable natural gas imbalances due shippers operators determine collect part outstanding balance regularly review collectibility establish adjust allowance necessary using specific identification method inventory consists refined products crude oil chemicals materials supplies natural gas storage nontrading purposes coal optic fiber use firstin firstout method account refined products crude oil chemicals inventories average cost method account inventories value inventory lower cost market value optic fiber classified longterm asset since expect sell next twelve months natural gas oil imbalances natural gas oil imbalances occur actual amount natural gas oil delivered received pipeline system processing plant storage facility differs contractual amount scheduled delivered received value imbalances due shippers operators appropriate market index price based expect settle imbalance imbalances settled cash made inkind subject contractual terms settlement imbalances due others reported balance sheet either accounts receivable customers accounts receivable unconsolidated affiliates imbalances owed others reported balance sheet either trade accounts payable accounts payable unconsolidated affiliates addition imbalances classified current longterm depending expect settle property plant equipment property plant equipment recorded original cost construction upon acquisition either fair value assets acquired cost entity first placed asset service capitalize direct costs labor materials indirect costs overhead interest regulated businesses apply provisions sfas 71 equity return component capitalize major units property replacements improvements expense minor items included pipeline property balances additional acquisition costs represent excess purchase costs associated purchase business combinations allocated regulated interstate systems costs amortized straightline basis recover excess costs rates following table presents property plant equipment type depreciation method remaining useful lives depreciation rate 1 regulated interstate systems using sfas 71 use composite group method depreciate regulated property plant equipment method assets similar useful lives characteristics grouped depreciated one asset apply depreciation rate approved tariff total cost group net book value equals salvage value reevaluate depreciation rates time redevelop transportation rates file ferc increase decrease rates retire regulated property plant equipment accounted sfas 71 charge accumulated depreciation amortization original cost plus cost retirement cost remove sell dispose less salvage value recognize gain loss unless sell entire operating unit include gains losses dispositions operating units income retire regulated property plant equipment sfas 71 nonregulated properties reduce property plant equipment original cost less accumulated depreciation salvage remaining gain loss recorded income asset impairments evaluate longlived assets impairment accordance sfas 121 accounting impairment longlived assets longlived assets disposed adverse event change circumstances occurs estimate future cash flows asset grouped together lowest level separate cash flows measured determine asset impaired total undiscounted future cash flows less carrying amount assets calculate fair value assets either reference sales data similar assets estimating fair value using discounted cash flow approach cash flow estimates require us make estimates assumptions many years future pricing demand competition operating costs legal regulatory factors assumptions change either positively negatively natural gas oil properties use full cost method account natural gas oil properties full cost method substantially productive nonproductive costs incurred connection acquisition exploration development natural gas oil reserves capitalized costs include costs unproved properties internal costs directly related acquisition exploration activities capitalized interest amortize costs using unit production method life proved reserves total capitalized costs limited ceiling based present value future net revenues using current prices discounted 10 percent plus lower cost fair market value unproved properties discounted revenues equal greater total capitalized costs required writedown capitalized costs level perform ceiling test calculation quarter required writedowns included income statements ceiling test charges ceiling test calculations include effects derivative instruments designated cash flow hedges anticipated future natural gas oil production recognize gain loss sales natural gas oil properties unless properties sold significant treat sales adjustment cost properties planned major maintenance repair maintenance costs generally expensed incurred unless improve operating efficiency extend useful life asset domestic refining business repair maintenance costs planned major maintenance activities accrued liability systematic rational manner period time planned major maintenance activities occur difference accrued liability actual costs incurred performing maintenance activities charged credited expense time maintenance occurs international refineries cost major maintenance activity capitalized amortized expense systematic rational manner estimated period extending next planned major maintenance activity types costs accrue conjunction major maintenance refineries outside contractor costs materials supplies company labor outside services domestic operations accruals major maintenance 36 million 51 million december 31 2001 2000 international operations capitalized 56 million 53 million december 31 2001 2000 intangible assets intangible assets consist primarily goodwill arising result mergers acquisitions amortize intangible assets using straightline method periods ranging 5 40 years evaluate impairment goodwill accordance apb 17 intangible assets methodology event occurs suggests impairment may occurred evaluate undiscounted net cash flows asset entity goodwill relates cash flows sufficient recover value asset entity plus related goodwill cash flows discounted riskadjusted rate difference recorded charge income statement revenue recognition regulated businesses recognize revenues natural gas transportation services transportation period service provided reserves provided revenues collected may subject refund pending rate proceedings nonregulated businesses record revenues earned revenues earned deliveries physical commodities made services provided see discussion price risk management activities revenue recognition policies trading activities environmental costs contingencies expense capitalize expenditures ongoing compliance environmental regulations relate past current operations appropriate expense amounts clean existing environmental contamination caused past operations benefit future periods preventing eliminating future contamination record liabilities environmental assessments indicate remediation efforts probable costs reasonably estimated estimates liabilities based currently available facts existing technology presently enacted laws regulations taking consideration likely effects inflation societal economic factors include estimates associated legal costs amounts also consider prior experience remediating contaminated sites companies cleanup experience data released epa organizations estimates subject revision future periods based actual costs new circumstances included balance sheet current longterm liabilities undiscounted amounts evaluate recoveries insurance coverage government sponsored programs separately liability recovery assured record report asset separately associated liability financial statements recognize liabilities contingencies exposure fully analyzed indicates probable asset impaired liability incurred amount impairment loss reasonably estimated funds spent remedy contingencies charged reserve one exists expensed range probable loss estimated accrue likely amount least minimum range probable loss price risk management activities engage price risk management activities trading nontrading purposes manage market risks associated commodities purchase sell interest rates foreign currency exchange rates trading nontrading price risk management activities involve use variety derivative financial instruments including exchangetraded futures contracts involve cash settlements forward contracts involve cash settlements physical delivery commodity swap contracts require payments receipts counterparties based difference fixed variable price two variable prices commodity exchangetraded overthecounter options trading activities trading activities include services provide energy sector primarily related purchase sale energy commodities account trading activities fair market value requirements eitf issue 9810 accounting contracts involved energy trading risk management activities addition derivatives trading activities also include nonderivative instruments transportation storage capacity contracts physical natural gas actively traded reflect market values trading activities balance sheet price risk management activities classified current longterm based anticipated settlement date income statement account physical settlements result delivery commodity revenues cost products sold based whether buy sell commodity financial settlements well changes market value traded positions included revenue nontrading activities nontrading price risk management activities involve use derivative financial instruments hedge impact market price risk exposures assets liabilities contractual commitments forecasted transactions related natural gas oil production refining natural gas transmission power generation financing international business activities january 1 2001 adopted provisions sfas 133 accounting derivatives hedging activities accounting nontrading derivative instruments sfas 133 derivatives reflected balance sheet fair market value apply marktomarket method accounting contracts qualify normal purchases sales sfas 133 engage two types hedging activities hedges cash flow exposure hedges fair value exposure hedges cash flow exposure entered hedge forecasted transaction variability cash flows received paid related recognized asset liability hedges fair value exposure entered hedge fair value recognized asset liability firm commitment date enter derivative contract designate derivative either cash flow hedge fair value hedge changes derivative fair values designated cash flow hedges deferred extent effective recorded component accumulated comprehensive income hedged transactions occur recognized earnings ineffective portion cash flow hedges change value recognized immediately earnings component operating revenues income statement changes derivative fair values designated fair value hedges recognized earnings offsets changes fair values related hedged assets liabilities firm commitments required sfas 133 formally document relationships hedging instruments hedged items well risk management objectives strategies undertaking various hedge transactions methods assessing testing correlation hedge ineffectiveness hedging instruments linked hedged asset liability firm commitment forecasted transaction also assess inception hedge ongoing basis whether derivatives used hedging transactions highly effective offsetting changes cash flows fair values hedged items discontinue hedge accounting prospectively determine derivative longer highly effective hedge market value trading nontrading instruments reflects best estimate based upon exchange overthecounter quotations whenever available quoted valuations may available due location differences terms extend beyond period quotations available quotes available utilize valuation techniques models estimate market values modeling techniques require us make estimations future prices price correlation market volatility liquidity estimates also reflect factors time value volatility underlying contracts potential impact liquidating position orderly manner reasonable period time present market conditions modeling risk credit risk counterparties operational risk actual results may differ estimates differences positive negative cash inflows outflows associated settlement trading nontrading price risk management activities recognized operating cash flows receivables payables resulting settlements reported separately price risk management activities balance sheet trade receivables payables prior adoption sfas 133 applied hedge accounting nontrading derivatives derivative reduced risk underlying hedged item designated hedge inception expected result financial impacts inversely correlated item hedged correlation ceased exist hedge accounting terminated derivatives recorded fair value balance sheet changes fair value recorded income changes market value derivatives designated hedges deferred revenue expense gain loss recognized hedged transaction derivatives held nontrading purposes recorded gains losses operating income cash inflows outflows recognized operating cash flow settlement transactions occurred income taxes report income taxes based income reported tax returns along provision deferred income taxes deferred income taxes reflect estimated future tax consequences differences financial statement tax bases assets liabilities carryovers year end account tax credits flowthrough method reduces provision income taxes year tax credits first become available reduce deferred tax assets valuation allowance based estimates likely portion assets realized future period estimates utilized recognition deferred tax assets subject revision either future periods based new facts circumstances foreign currency transactions translation record currency transaction gains losses income net currency loss recorded income 2001 13 million insignificant 2000 us dollar functional currency substantially foreign operations foreign operations whose functional currency deemed us dollar assets liabilities translated yearend exchange rates included separate component comprehensive income stockholders equity cumulative currency translation loss recorded accumulated comprehensive income 97 million 64 million december 31 2001 2000 revenues expenses translated average exchange rates prevailing year treasury stock account treasury stock using cost method report balance sheet reduction stockholders equity treasury stock sold issued valued firstin firstout basis included treasury stock december 31 2001 2000 approximately 55 million shares 58 million shares common stock held trust deferred compensation programs stockbased compensation apply provisions accounting principles board opinion 25 related interpretations accounting stock compensation plans fixed variable compensation plans account plans using fixed variable accounting appropriate compensation expense variable plans including restricted stock grants measured using market price stock date number shares grant becomes determinable amortized earnings period service stock options issued fixed plan accordingly compensation expense recognized stock options unless options granted exercise price lower market grant date earnings per share basic earnings per share represents amount earnings period available share common stock outstanding period diluted earnings per share represents amount earnings period available share common stock outstanding period plus potentially dilutive common shares outstanding period differences basic diluted shares outstanding periods attributed dilutive effects restricted stock options trust preferred securities convertible debentures feline pridessm cumulative effect accounting change january 1 1999 adopted statement position 985 reporting costs startup activities statement defined startup activities required startup organization costs expensed incurred addition required cost existed balance sheet expensed upon adoption pronouncement recorded charge 13 million net income taxes cumulative effect accounting change upon adoption new accounting pronouncements issued yet adopted 2001 financial accounting standards board issued sfas 141 business combinations sfas 142 goodwill intangible assets sfas 144 accounting impairment disposal longlived assets standards required adoption date january 1 2002 sfas 141 impact manner account business combinations sfas 142 impact manner account goodwill test goodwill impairment sfas 144 impact account asset impairments accounting discontinued operations 2 mergers acquisitions divestitures coastal january 2001 merged coastal accounted transaction pooling interests converted share coastals common stock class common stock taxfree basis 123 shares common stock also exchanged coastals outstanding convertible preferred stock common stock basis preferred stock converted coastal common stock immediately prior merger issued approximately 271 million shares common stock including 4 million shares exchange coastal stock options following table presents revenues net income previously separate companies combined amounts presented audited combined financial statements several adjustments made conform accounting presentation financial information 1 conforming reclassifications primarily include grossup revenues associated coastals physical petroleum marketing trading activities consistent method reporting revenues texas midstream operations december 2000 completed purchase pacific gas electrics pges texas midstream operations total value transaction 887 million including assumed debt approximately 527 million transaction accounted purchase included field services segment operations acquired consisted 7500 miles intrastate natural gas transmission natural gas liquids pipelines transport approximately 28 bcfd nine natural gas processing fractionation plants currently process 15 bcfd rights 72 bcf natural gas storage capacity march 2001 sold acquired natural gas liquids transportation fractionation assets el paso energy partners approximately 133 million sonat october 1999 completed merger sonat diversified energy holding company engaged domestic natural gas oil exploration production transmission storage natural gas natural gas power marketing accounted merger pooling interests exchanged one share common stock issued exchange share sonat common stock total common shares issued merger approximately 110 million divestitures federal trade commission ftc order result merger coastal sold midwestern gas transmission system gulfstream pipeline project 50 percent interest stingray ut offshore pipeline systems investments empire state iroquois pipeline systems year ended december 31 2001 net proceeds sales approximately 279 million recognized extraordinary net gain approximately 26 million net income taxes approximately 27 million additionally el paso energy partners lp sold interests several offshore assets ftc order related merger coastal sales consisted interests seven natural gas pipeline systems dehydration facility two offshore platforms proceeds sales assets approximately 135 million resulted loss partnership approximately 25 million consideration sales committed pay el paso energy partners series payments totaling 29 million required contribute 40 million trust related one assets sold el paso energy partners payments recorded mergerrelated costs 2000 sold east tennessee natural gas company sea robin pipeline company onethird interest destin pipeline company comply ftc order related merger sonat net proceeds sales approximately 616 million recognized extraordinary gain 89 million net income taxes 59 million december 2000 sold interest oasis pipeline company comply ftc order incurred loss transaction approximately 19 million net income taxes recorded gains losses sales extraordinary items income statement february 2002 announced sale several midstream assets el paso energy partners total consideration 750 million assets sold include 9400 miles intrastate transmission pipelines 1300 miles gathering systems permian basin 423 percent nonoperating interest indian basin gas processing treating plant associated gathering lines 3 mergerrelated costs asset impairments incurred costs related mergers coastal sonat asset impairments three years ended december 31 follows mergerrelated costs mergerrelated costs relate mergers coastal sonat consisted following three years ended december 31 employee severance retention transition costs include direct payments benefit costs severed employees early retirees occurred result mergerrelated workforce reduction consolidation following coastal merger completed employee restructuring across operating segments resulting reduction 3285 fulltime positions combination early retirements terminations following sonat merger approximately 870 fulltime positions eliminated similar restructuring employee severance costs include actual severance payments costs pension postretirement benefits settled curtailed existing benefit plans result restructurings retention charges include payments employees retained following mergers payments employees satisfy contractual obligations transition costs relate costs relocate employees costs severed retired employees arising severance date transition jobs ongoing workforce pension postretirement benefits accrued merger date paid applicable benefit periods terminated retired employees costs expensed incurred paid also included 2001 employee severance retention transition costs charge 278 million resulting issuance approximately 4 million shares common stock date coastal merger exchange fair value coastal employees directors stock options transaction costs include investment banking legal accounting consulting advisory fees incurred obtain federal state regulatory approvals take actions necessary complete mergers items expensed periods incurred business operational integration costs include charges consolidate facilities operations business segments lease termination abandonment charges recognition marktomarket value energy trading contracts resulting changes contracts managed combined operating strategy incremental fees software seismic license agreements also included 2001 charges approximately 222 million estimated lease related costs relocate pipeline operations detroit michigan houston texas el paso texas colorado springs colorado charges accrued time completed relocations closed offices amounts accrued paid term applicable noncancelable lease agreements costs expensed incurred mergerrelated asset impairments relate writeoffs writedowns capitalized costs duplicate systems facilities assets whose value impaired result decisions strategic direction combined operations following merger coastal charges occurred merchant energy production pipelines segments assets either operations suspended continue held use charges taken based comparison cost assets estimated fair value ongoing operations based change operating strategy costs include payments made satisfaction obligations arising ftc approval merger coastal miscellaneous charges items expensed period incurred asset impairments 2001 asset impairment charges resulted writedowns investments several international power projects merchant energy segment several telecommunications investments corporate operations 2000 charges consisted impairment coal mining refining assets merchant energy segment gas processing facility field services segment 1999 charge occurred pipeline segment derived impairments regulatory assets recoverable based settlement rate case impairments periods primarily result weak changing economic conditions causing permanent declines value assets charges taken assets based comparison assets carrying value estimated fair value based future estimated cash flows assets continue held use operations suspended 4 changes accounting estimates included operation maintenance costs year ended december 31 2001 approximately 317 million costs related changes accounting estimates consist 232 million additional environmental remediation liabilities 47 million additional accrued legal obligations 38 million charge reduce value spare parts inventories reflect changes usability parts worldwide operations changes primarily result several events occurred part following merger coastal including consolidation numerous operating locations sale majority retail gas stations shutdown midwest refining operations lease corpus christi refinery changes also direct result fire aruba refinery also impacting amounts evaluation operating standards strategies plans combined company following merger charges included operating expenses income statement reduced net income extraordinary items net income year ended december 31 2001 approximately 215 million 5 ceiling test charges full cost method accounting natural gas oil properties perform quarterly ceiling tests evaluate whether carrying value natural gas oil properties exceeds present value future net revenues discounted 10 percent plus lower cost fair market value unproved properties third quarter 2001 capitalized costs exceeded ceiling limit 135 million including 87 million canadian full cost pool 28 million brazilian full cost pool 20 million international production operations primarily turkey charges based november 1 2001 daily posted oil natural gas sales prices 1999 incurred charges related us full cost pool 352 million based end period natural gas oil prices natural gas oil prices used periods adjusted oilfield gas gathering hub wellhead price differences appropriate noncash writedowns included income statement ceiling test charges use financial instruments hedge volatility natural gas oil prices impact hedges considered determination ceiling test charge 2001 factored future ceiling test calculations impact hedges included calculating 2001 ceiling test charge would materially changed since significantly hedge international production activities also mentioned 2001 charge computed based daily posted prices november 1 2001 computed charge based daily oil natural gas prices september 30 2001 charge would approximately 275 million including approximately 227 million canadian full cost pool 48 million brazilian international production operations including impact future cash flows hedging program impact hedging program excluded charges would approximately international full costs pools production operations would incurred additional charge approximately 576 million related us full cost pool 6 income taxes pretax income extraordinary items cumulative effect accounting change composed following three years ended december 31 following table reflects components income tax expense included income extraordinary items cumulative effect accounting change three years ended december 31 tax expense included income extraordinary items cumulative effect accounting change differs amount computed applying statutory federal income tax rate 35 percent following reasons three years ended december 31 following components net deferred tax liability december 31 december 31 2001 portion cumulative undistributed earnings foreign subsidiaries foreign corporate joint ventures recorded us income taxes approximately 975 million since earnings intended indefinitely reinvested foreign operations provision made us taxes foreign withholding taxes may applicable upon actual deemed repatriation distribution earnings made might subject foreign withholding taxes us income taxes net allowable foreign tax credits deductions however estimate taxes practicable reasons recorded provision us income taxes foreign currency translation adjustment recorded comprehensive income tax benefit associated exercise nonqualified stock options vesting restricted stock well restricted stock dividends reduced taxes payable 31 million 2001 60 million 2000 19 million 1999 benefits included additional paidin capital balance sheets december 31 2001 charitable contribution carryovers 24 million carryover periods end follows 1 million 2002 1 million 2003 22 million 2004 alternative minimum tax credits 225 million carryover indefinitely 2 million general business credit carryovers carryover periods end various times years 2006 2020 usage carryovers subject limitations provided sections 382 383 internal revenue code well separate return limitation year rules irs regulations table presents details net operating loss carryover periods recorded valuation allowance reflect estimated amount deferred tax assets may realize due expiration net operating loss tax credit carryovers december 31 2001 2000 approximately 1 million valuation allowance relates net operating loss carryovers acquired company remaining 2 million allowance relates general business credit carryovers 7 earnings per share calculated basic diluted earnings per share amounts follows three years ended december 31 1 due antidilutive effect earnings per share approximately 7 million shares related convertible debentures excluded 2001 diluted shares approximately 8 million shares related trust preferred securities excluded 2001 1999 8 financial instruments price risk management activities fair value financial instruments following carrying amounts estimated fair values financial instruments december 31 1 excludes physical contracts including transportation capacity tolling agreements natural gas storage held trading purposes since constitute financial instruments 2 january 1 2001 adopted sfas 133 sfas 133 derivative instruments recorded fair value financial statements december 31 2001 2000 carrying amounts cash equivalents shortterm borrowings trade receivables payables representative fair value shortterm nature instruments fair value longterm debt variable interest rates approximates carrying value marketbased nature debts interest rates estimated fair value debt fixed interest rates based quoted market prices similar issues estimated fair value derivative financial instruments based quoted market prices current market conditions estimates obtained thirdparty brokers dealers amounts derived using valuation models trading nontrading price risk management activities following table summarizes carrying value trading nontrading price risk management assets liabilities december 31 1 physical contracts include transportation capacity tolling agreements natural gas storage held trading purposes commodity trading activities recognized gross margins trading activities 690 million 418 million year ended december 31 2001 2000 fair value commodity energy related contracts entered trading purposes december 31 2001 2000 average fair value instruments set forth 1 computed using net asset liability balance end month notional amounts terms trading price risk management activities notional amounts terms energy commodity financial instruments december 31 2001 2000 set forth notional amounts included table reflect contracted notional volumes multiplied number delivery periods remaining related contracts notional amounts indicative future cash flows may decide sell contracts commodity markets future notional amount terms foreign currency forward purchases sales interest rate swaps futures december 31 2001 2000 follows weighted average maturity entire portfolio price risk management activities approximately four years december 31 2001 two years december 31 2000 market credit risks serve diverse group customers require wide variety financial structures products terms diversity requires us manage portfolio basis resulting market risks inherent transactions subject parameters established risk management committee monitor market risks risk control committee operating independently units create actively manage risk exposures ensure compliance stated risk management policies measure adjust risk portfolio accordance marktomarket risk management methodologies utilize forward price curves energy markets estimate size probability future potential exposure credit risk relates risk loss would incur result nonperformance counterparties pursuant terms contractual obligations maintain credit policies regard counterparties minimize overall credit risk policies require evaluation potential counterparties financial condition including credit rating collateral requirements certain circumstances including cash advance letters credit guarantees use standardized agreements allow netting positive negative exposures associated single counterparty counterparties associated assets trading price risk management activities summarized follows 1investment grade investment grade primarily determined using publicly available credit ratings counterparty publicly rated minimum implied credit rating internal credit analysis investment grade includes counterparties minimum standard poors rating bbb moodys rating baa3 investment grade includes counterparties credit rating meet criteria investment grade 2as december 31 2001 required collateral encompasses margins standby letters credit parent company guarantees 375 million 486 million 77 counterparties included investment grade 3we one customer comprised greater 5 percent assets price risk management activities december 31 2001 although customer considered investment grade position counterparty fully collateralized margins standby letters credit one customer comprised greater 5 percent assets price risk management activities december 31 2000 customer considered investment grade 4counterparty total include natural gas storage marketable securities held trading purposes 196 million december 31 2001 concentration counterparties may impact overall exposure credit risk either positively negatively counterparties may similarly affected changes economic regulatory conditions nontrading price risk management activities also utilize derivative financial instruments nontrading activities mitigate market price risk associated significant physical transactions nontrading commodity activities accounted using hedge accounting provided meet hedge accounting criteria nontrading activities conducted exchange traded futures contracts swaps forward agreements third parties notional amounts terms contracts held purposes trading follows december 31 march 2001 issued e550 million approximately 510 million euro notes 575 due 2006 reduce exposure foreign currency risk entered swap transaction exchanging euro note 510 million us dollar denominated obligation fixed interest rate 661 fiveyear term note fair value liability related swap 33 million december 31 2001 december 31 2001 interest rate swap transaction notional amount 240 million exchanging libor variable interest rate fixed rate 307 swap entered hedge variable interest rates loan principal amount 240 million matures march 2004 swap converts variable interest payments loan fixed rate 449 swap terminates june 2003 fair value swap immaterial december 31 2001 also face credit risk respect nontrading activities take similar measures trading activities mitigate risk based upon policies risk exposure anticipate material effect financial position operating results cash flows resulting counterparty nonperformance 9 accounting hedging activities january 1 2001 adopted provisions sfas 133 recorded cumulativeeffect adjustment 1280 million net income taxes accumulated comprehensive income recognize fair value derivatives designated hedging instruments majority initial charge related hedging cash flows anticipated sales natural gas 2001 2002 year ended december 31 2001 1063 million net income taxes initial transition adjustment reclassified earnings result hedged sales purchases year discussion hedging activities follows fair value hedges crude oil refined products inventories change value daily due changes commodity markets use futures swaps protect value inventories year ended december 31 2001 financial statement impact hedges fair value inventories immaterial cash flow hedges majority commodity sales purchases spot market forward market prices use futures forward contracts swaps limit exposure fluctuations commodity markets allow fixed cash flow stream activities december 31 2001 value cash flow hedges included accumulated comprehensive income net unrealized gain 256 million net income taxes estimate unrealized gains 272 million net income taxes reclassified accumulated comprehensive income next 12 months reclassifications occur upon physical delivery hedge commodity corresponding expiration hedge maximum term cash flow hedges 12 years however cash flow hedges expire within next 24 months accumulated comprehensive income also includes loss 23 million net income taxes representing proportionate share amounts recorded comprehensive income unconsolidated affiliates use derivatives cash flow hedges included loss 10 million loss estimate reclassified accumulated comprehensive income next 12 months maximum term cash flow hedges two years excluding hedges related interest rates variable debt year ended december 31 2001 recognized net gain 3 million net income taxes related ineffective portion cash flow hedges foreign currency hedges international activities fixed rate foreign currency denominated debt exposes us changes exchange rates foreign currency us dollar 2001 used currency swap effectively convert fixed amounts foreign currency due foreign currency denominated debt fixed us dollar amounts 10 inventory consisted following december 31 11 property plant equipment december 31 2001 2000 approximately 2271 million 2367 million construction work progress included property plant equipment june 2001 entered 20year lease agreement related corpus christi refinery related assets valero energy corporation lease valero pays us quarterly amount increases second year lease year ended december 31 2001 recorded 11 million lease income related lease addition valero option purchase plant related assets 2003 approximately 294 million similar option year thereafter annually increasing amount net book value plant related assets approximately 225 million december 31 2001 based terms lease qualified operating lease total minimum lease payments 811 million future minimum lease payments totaling 797 million 19 million 2002 37 million 2003 43 million 2004 2005 2006 total 612 million thereafter 12 debt financing obligations credit facilities december 31 2001 weighted average interest rate commercial paper shortterm credit facilities 32 december 31 2000 74 following shortterm borrowings financing obligations december 31 credit facilities use commercial paper programs manage shortterm cash requirements programs borrow 3 billion combination individual corporate tgp epng commercial paper programs 1 billion maintain 3year 1 billion revolving credit competitive advance facility conduct shortterm borrowings commercial credit transactions facility expires 2003 el paso cgp formerly coastal epng tgp designated borrowers facility june 2001 replaced existing 364day revolving credit facility renewable 3 billion 364day revolving credit competitive advance facility epng tgp also designated borrowers new facility interest rate facilities varies based libor plus 50 basis points december 31 2001 amounts outstanding facilities december 31 2001 connection acquisition pges texas midstream operations december 2000 established 700 million shortterm credit facility 455 million outstanding december 31 2000 february 2001 borrowed additional 245 million facility two separate payments march june 2001 repaid outstanding balance credit facility terminated also supplement commercial paper program smaller shortterm credit facilities used coastal prior merger terminated year april 2001 filed shelf registration statement securities exchange commission sell time total 3 billion debt securities preferred common stock medium term notes trust securities december 31 2001 approximately 920 million remaining shelf registration statement issued additional securities january 2002 december 31 2001 tgp 200 million sng 100 million shelf registration statements file securities exchange commission availability borrowings credit borrowing agreements subject specified conditions believe currently meet conditions include compliance financial covenants ratios required agreements absence default agreements continued accuracy representations warranties contained agreements senior unsecured debt issues given investment grade ratings sp moodys 2002 activities january 2002 increased shelf registration statement 920 million 110 billion issued 110 billion aggregate principal amount 775 medium term notes due 2032 net proceeds approximately 108 billion net issuance costs used repay shortterm borrowings general corporate purposes issuance used remaining capacity previous shelf registration statement february 2002 filed new shelf registration statement securities exchange commission allows us issue 3 billion registration statement issue combination debt equity instruments including trust preferred securities el paso capital trust ii el paso capital trust iii trusts wholly owned us issue securities trusts required issue full unconditional guarantees securities also january 2002 retired 100 million aggregate principal amount 785 notes 215 million aggregate principal amount 775 notes march 2002 retired 400 million floating rate notes january 2002 sng filed shelf registration statement increasing amount debt issue 100 million 300 million february 2002 sng issued 300 million aggregate principal amount 80 notes due 2032 net proceeds approximately 297 million net issuance costs used general corporate purposes issuance used remaining capacity sngs shelf registration statement longterm debt financing obligations outstanding consisted following december 31 aggregate maturities principal amounts longterm debt financing obligations next 5 years total thereafter follows millions zero coupon convertible debentures maturity value 18 billion due 2021 yield maturity 4 debentures convertible 8456589 shares common stock based conversion rate 47872 shares per 1000 principal amount maturity rate equal conversion price 94604 per share common stock october 2001 borrowed 240 million due 2004 loan agreement loan collateralized lease payments valero lease corpus christi refinery 1999 issued total 18400000 feline pridessm consisting 17000000 income prides stated value 25 1400000 growth prides stated value 25 income prides consist unit comprised senior debenture purchase contract holder obligated purchase us later august 16 2002 25 stated price number shares common stock growth prides consist unit comprised purchase contract holder obligated purchase us later august 16 2002 25 stated price number shares common stock 25 undivided beneficial interest threeyear treasury security principal amount maturity equal 1000 terms purchase contract effect prior merger coastal number shares common stock holder pride received varied 05384 06568 shares depending price coastals common stock result merger coastal terms purchase contract number shares holder pride entitled required receive upon settlement became fixed 06622 shares el paso common stock result issuance approximately 122 million shares el paso common stock financing obligations consist crude oil prepayments received third parties exchange agreement deliver fixed quantity crude oil specified delivery point future production payment received exchange delivery fixed quantity natural gas future production agreements terms settled delivery commodity entered commodity swaps effectively lockin value commitments third party upon delivery commodity continue deliver natural gas production payment agreement according terms consider agreements financing arrangements carrying cost prepayments production payment recognized interest expense income statement 13 securities subsidiaries minority interests past three years entered number transactions finance consolidated subsidiaries cases accomplished sale preferred interests entities structured financial transactions collateralized assets subsidiaries total amounts outstanding programs december 31 2001 follows millions 1 consolidated trusts composed capital trust coastal finance capital trust iv capital trust march 1998 formed el paso energy capital trust issued 65 million 4 34 trust convertible preferred securities 325 million common securities trust exists sole purpose issuing preferred securities investing proceeds 4 34 convertible subordinated debentures due 2028 sole asset provide full unconditional guarantee trust preferred securities trust preferred securities reflected companyobligated preferred securities consolidated trusts balance sheet distributions paid preferred securities included minority interest income statement trust preferred securities nonvoting except limited circumstances pay quarterly distributions annual rate 4 34 carry liquidation value 50 per security plus accrued unpaid distributions convertible common shares time prior close business march 31 2028 option holder rate 12022 common shares trust preferred security equivalent conversion price 4159 per common share december 31 2001 approximately 65 million trust preferred securities outstanding coastal finance may 1998 coastal completed public offering 12 million mandatory redemption preferred securities coastal finance business trust 300 million coastal finance holds debt securities purchased proceeds preferred securities offering cumulative quarterly distributions paid preferred securities annual rate 8375 liquidation amount 25 per preferred security preferred securities mandatorily redeemable maturity date may 13 2038 may redeemed option may 13 2003 earlier various events occur redemption price paid 25 per preferred security plus accrued unpaid distributions date redemption capital trust iv may 2000 formed el paso energy capital trust iv issued 300 million preferred securities third party investor preferred securities pay cash distributions floating rate equal threemonth libor plus 75 basis points december 31 2001 floating rate 283 preferred securities must redeemed trust iv later november 30 2003 proceeds sale securities used trust iv purchase series floating rate senior debentures whose yield maturity terms mirror trust ivs preferred securities sole assets trust iv floating rate senior debentures provide full unconditional guarantee obligations trust iv related preferred securities time trust iv issued preferred securities also agreed issue 300 million equity securities including limited common stock one public offerings prior may 31 2003 trinity river also known red river 1999 formed series companies refer trinity river trinity river formed provide financing invest various capital projects assets thirdparty investor contributed cash 980 million trinity river 1999 exchange preferred securities one consolidated subsidiaries third party entitled adjustable preferred return derived trinity rivers net income preferred interest collateralized combination notes payable us various fixed assets including mojave pipeline bear creek storage various natural gas oil production properties el paso energy partners common units option acquire thirdpartys interest trinity river time prior june 2004 exercise option agreement extended could required liquidate assets supporting transaction account investors preferred interest consolidated subsidiary minority interest balance sheet preferred return minority interest expense income statement assets liabilities operations trinity river included financial statements credit ratings downgraded investment grade sp moodys could required liquidate assets supporting transaction clydesdale also known mustang 2000 formed series companies refer clydesdale formed provide financing invest various capital projects assets thirdparty investor contributed cash 1 billion clydesdale exchange preferred securities one consolidated subsidiaries third party entitled adjustable preferred return derived clydesdales net income preferred interest collateralized combination notes payable us various fixed assets including colorado interstate gas transmission system natural gas oil properties option acquire thirdpartys interest clydesdale time prior may 2005 exercise option agreement extended could required liquidate assets supporting transaction account investors preferred interest consolidated subsidiary minority interest balance sheet preferred return minority interest expense income statement assets liabilities operations clydesdale included financial statements credit ratings downgraded investment grade sp moodys could required liquidate assets supporting transaction el paso tennessee preferred stock 1996 el paso tennessee pipeline co subsidiary issued 6 million shares publicly registered 825 cumulative preferred stock par value 50 per share 300 million preferred stock redeemable option el paso tennessee redemption price equal 50 per share plus accrued unpaid dividends time january 2002 three years ended december 31 2001 dividends approximately 25 million paid year preferred stock coastal securities company preferred stock 1996 coastal securities company limited wholly owned subsidiary issued 4 million shares preferred stock 100 million quarterly cash dividends paid preferred stock rate based libor preferred shareholders also entitled participating dividends based various refining margins coastal securities may redeem preferred stock cash liquidation price plus accrued unpaid dividends coastal oil gas resources preferred stock 1999 coastal oil gas resources inc wholly owned subsidiary issued 50000 shares preferred stock 50 million preferred shareholders entitled quarterly cash dividends rate based libor dividend rate subject renegotiation 2004 fifth anniversary thereafter event coastal oil gas resources preferred shareholders unable agree new rate coastal oil gas resources must redeem shares 1000 per share plus accrued unpaid dividends cause preferred stock registered securities exchange commission remarketed coastal oil gas resources also option redeem shares dividend rate reset date 1000 per share plus accrued unpaid preferred dividends coastal limited ventures preferred stock 1999 coastal limited ventures inc wholly owned subsidiary issued 150000 shares preferred stock 15 million preferred shareholders entitled quarterly cash dividends annual rate 6 dividend rate subject renegotiation 2004 fifth anniversary thereafter event coastal limited preferred shareholders unable agree new rate preferred shareholders may call redemption preferred shares redemption price 100 per share plus accrued unpaid preferred dividends thereon coastal limited also option redeem shares rate reset date 100 per share plus accrued unpaid preferred dividends gemstone part gemstone transaction wholly owned subsidiary topaz investors llc issued minority member interest third party investor gemstone 300 million third party investor entitled cumulative preferred return 803 interest agreements underlying transaction expire 2004 earlier sell international power assets owned indirectly topaz minority member interest redeemable liquidation value plus accrued unpaid dividends consolidated partnership december 1999 coastal limited contributed assets limited partnership exchange controlling general partnership interest limited interests partnership issued unaffiliated investors 285 million limited partners entitled cumulative priority return based libor return subject renegotiation 2004 fifth anniversary thereafter partnership maximum life 20 years may terminated sooner subject certain conditions including failure agree new rate coastal limited may terminate partnership time repayment limited partners outstanding capital plus unpaid priority returns 14 commitments contingencies legal proceedings several subsidiaries named defendants eleven purported class action municipal individual lawsuits one shareholder derivative lawsuit filed california state courts eleven suits contend entities acted improperly limit construction new pipeline capacity california andor manipulate price natural gas sold california marketplace shareholder derivative suit contends directors failed prevent conduct alleged several underlying cases consolidated nine eleven suits single san diego court proceeding expect consolidate remaining two suits near future march 2002 derivative lawsuit dismissed california refiled state court houston texas listing cases included heading cases september 2001 received civil document subpoena california department justice seeking information said relevant departments ongoing investigation high electricity prices california produced expect continue produce materials pursuant subpoena august 19 2000 main transmission line owned operated epng ruptured crossing pecos river near carlsbad new mexico twelve individuals site fatally injured june 20 2001 us department transportations office pipeline safety issued notice proposed violation epng notice alleged five probable violations regulations proposed fines totaling 25 million proposed corrective actions october 15 2001 epng filed detailed response office pipeline safety disputing alleged violations alleged five probable violations regulations department transportations office pipeline safety 1 failure perform appropriate tasks prevent corrosion associated proposed fine 500000 2 failure investigate minimize internal corrosion associated proposed fine 1000000 3 failure consider unusual operating maintenance conditions respond appropriately associated proposed fine 500000 4 failure follow company procedure associated proposed fine 500000 5 failure maintain topographical diagrams associated proposed fine 25000 cooperating national transportation safety board investigation facts circumstances concerning possible causes rupture required pay proposed fines material adverse effect financial position operating results cash flows addition number personal injury wrongful death lawsuits filed us connection rupture several suits settled payments fully covered insurance seven carlsbad lawsuits remain one seven reached contingent settlement within insurance coverage listing cases included heading cases may 1999 one subsidiaries named defendant suit filed 319th judicial district court nueces county texas individual employed one contractors rolando lopez rosanna barton v coastal refining marketing inc coastal corporation suit sought damages injuries sustained time explosion one refining plants settled august 2000 total payment 7 million 5 million covered insurance three refinery employees intervened suit sought damages injuries sustained explosion claims tried august 2000 resulting 122 million verdict insurance coverage case appealed thirteenth court appeals texas appellate briefing court completed even verdict upheld appeal material adverse effect financial position operating results cash flows 1997 number subsidiaries named defendants actions brought jack grynberg behalf us government false claims act generally complaints allege industrywide conspiracy report heating value well volumes natural gas produced federal native american lands deprived us government royalties matters consolidated pretrial purposes natural gas royalties qui tam litigation us district court district wyoming filed june 1997 may 2001 court denied defendants motions dismiss number subsidiaries named defendants quinque operating company et al v gas pipelines predecessors et al filed 1999 district court stevens county kansas class action complaint alleges defendants mismeasured natural gas volumes heating content natural gas nonfederal nonnative american lands quinque complaint transferred court handling grynberg complaint sent back kansas state court proceedings motion dismiss case pending october 1992 several property owners mcallen texas filed suit 93rd judicial district court hidalgo county texas among others one subsidiaries timely adventures inc et al v phillips properties inc et al garza v coastal mart inc suit sought damages alleged diminution property value damages related exposure hazardous chemicals arising operation service stations storage facilities july 2000 trial court entered judgment approximately 12 million actual damages property diminution approximately 100 million punitive damages judgment appealed agreement principle settle case reached expect settlement concluded march 2002 established accruals believe sufficient provide settlement material adverse effect financial position operating results cash flows compliance 1990 amendments clean air act caa use gasoline additive methyl tertiarybutyl ether mtbe gasoline also produce buy sell distribute mtbe number lawsuits filed throughout us regarding mtbes potential impact water supplies currently one several defendants five lawsuits new york costs legal exposure related lawsuits claims currently determinable addition subsidiaries affiliates named defendants numerous lawsuits governmental proceedings arise ordinary course business matters evaluate merits case exposure matter possible legal settlement strategies likelihood unfavorable outcome determine unfavorable outcome probable estimated make necessary accruals new information becomes available estimates may change impact changes may material effect results operations december 31 2001 reserves totaling 187 million outstanding legal matters outcome matters discussed cannot predicted certainty based information known date existing accruals expect ultimate resolution matters material adverse effect financial position operating results cash flows environmental matters subject extensive federal state local laws regulations governing environmental quality pollution control laws regulations require us remove remedy effect environment disposal release specified substances current former operating sites december 31 2001 reserve approximately 555 million expected remediation costs including approximately 526 million associated onsite offsite groundwater technical studies approximately 29 million costs anticipate incurring 2027 addition expect make capital expenditures environmental matters approximately 333 million aggregate years 2002 2006 expenditures primarily relate compliance clean air regulations accrued amounts december 31 2001 include change estimated environmental remediation liabilities result several events occurred 2001 evaluation operations following coastal merger see discussion change estimate changes accounting estimates november 1988 kentucky environmental agency filed complaint kentucky state court alleging tgp discharged pollutants waters state disposed polychlorinated biphenyls pcbs without permit agency sought injunction future discharges order remediate remove pcbs civil penalty tgp entered agreed orders agency resolve many issues raised complaint received water discharge permits agency kentucky compressor stations relevant kentucky compressor stations characterized remediated 1994 consent order environmental protection agency epa despite remediation efforts agency may raise additional technical issues require additional remediation work future may 1999 march 2001 coastal eagle point oil company received several administrative orders notices civil administrative penalty assessment new jersey department environmental protection assessments related alleged noncompliance new jersey air pollution control act pertaining excess emissions first quarter 1998 fourth quarter 2000 reported eagle point refinery westville new jersey new jersey department environmental protection assessed penalties totaling approximately 11 million alleged violations eagle point refinery granted administrative hearing issues raised assessments concurrently negotiations settle assessments february 2002 received notice violation epa alleging noncompliance epas fuel regulations 1996 1998 notice proposes penalty 165000 alleged violations investigating allegations preparing response since 1988 tgp engaged internal project identify deal presence pcbs substances including epa list hazardous substances compressor stations facilities operates conducting project tgp frequent contact federal state regulatory agencies informal negotiation formal entry consent orders ensure efforts meet regulatory requirements may 1995 following negotiations customers tgp filed stipulation agreement ferc established mechanism recovering substantial portion environmental costs identified internal project stipulation agreement effective july 1 1995 refunds may required extent actual eligible expenditures less amounts collected tgp party proceedings involving federal state authorities regarding past use pcbs starting air systems tgp executed consent order 1994 epa governing remediation relevant compressor stations working epa relevant states regarding remediation activities tgp also working pennsylvania new york environmental agencies regarding remediation postremediation activities pennsylvania new york stations designated received notice could designated asked information determine whether could designated potentially responsible party prp respect 57 active sites cercla state equivalents sought resolve liability prp cercla sites appropriate indemnification third parties settlements provide payment allocable share remediation costs december 31 2001 estimated share remediation costs sites 66 million 205 million provided reserves believe adequate costs since cleanup costs estimates subject revision information becomes available extent remediation required cases asserted defense liability estimates could change moreover liability federal cercla statute joint several meaning could required pay excess pro rata share remediation costs understanding financial strength prps considered appropriate determination estimated liabilities presently believe based existing reserves information known date impact costs associated cercla sites material adverse effect financial position operating results cash flows possible new information future developments could require us reassess potential exposure related environmental matters may incur significant costs liabilities order comply existing environmental laws regulations also possible developments increasingly strict environmental laws regulations claims damages property employees persons environment resulting current past operations could result substantial costs liabilities future information becomes available relevant developments occur adjust accrual amounts accordingly still uncertainties relating ultimate costs may incur based upon evaluation experience date believe recorded reserves adequate rates regulatory matters april 2000 california public utilities commission cpuc filed complaint ferc alleging sale approximately 12 bcfd california capacity epng el paso merchant energy company whollyowned subsidiaries anticompetitive abuse affiliate relationship fercs policies parties proceeding requested original complaint set hearing merchant energy pay back profits earned contract march 2001 ferc established hearing administrative law judge address issue whether epng andor merchant energy market power exercised october 2001 administrative law judge issued proposed decision finding el paso exercise market power market power portion cpucs complaint dismissed decision found el paso violated fercs marketing affiliate regulations judges proposed decision briefed effective approved ferc october 30 2001 market oversight enforcement moe section fercs office general counsel filed comments proceeding stating record development trial inadequate conclude epng complied fercs regulation filed motion strike moes pleading december 2001 ferc denied motion remanded proceeding administrative law judge supplemental hearing availability capacity el pasos california delivery points hearing set commence march 20 2002 two groups epngs customers within california east california filed complaints epng ferc july 13 2001 twelve parties composed california customers natural gas producers natural gas marketers filed complaint alleging epngs full requirements contracts customers east california converted contracts specific volumetric entitlements epng required expand interstate pipeline system firm shippers experience reductions nominated gas volumes awarded demand charge credits also july 17 2001 ten parties east california fullrequirement contract customers filed complaint epng ferc alleging epng violated natural gas act 1938 breached contractual obligations failing expand system order serve needs fullrequirement contract shippers complainants requested ferc require epng show cause required augment system capacity september 10 2001 july 17 2001 complainants filed motion partial summary disposition complaint epng responded september 25 2001 addition november 13 2001 one july 17 2001 complainants submitted type settlement proposal parties opposed march 13 2002 public meeting ferc staff made presentation ferc commissioners recommending ferc address capacity allocation issues raised related epng proceedings among things eliminating full requirements provisions epngs contracts except small customer category converting contracts specific volumetric entitlements staff also recommended scheduling technical conference ferc authorized staff provide notice technical conference attended commissioners expected conference held later spring year june 2001 western australia regulators issued draft rate decision lower expected levels dampiertobunbury pipeline owned epic energy australia trust 33 percent ownership interest total investment including financial guarantees approximately 182 million epic energy australia appealed variety issues related draft decision western australia supreme court appeal heard western australia supreme court november 2001 decision court expected middle 2002 draft decision rates implemented new rates adversely impact future operating results liquidity debt capacity possibly reducing value investment 122 million september 2001 ferc issued notice proposed rulemaking nopr proposes apply standards conduct governing relationship interstate pipelines marketing affiliates energy affiliates proposed regulations adopted ferc would dictate energy affiliates conduct business interact interstate pipelines december 2001 filed comments ferc addressing concerns proposed rules cannot predict outcome nopr adoption regulations substantially form proposed would minimum place additional administrative operational burdens us cannot predict certainty final outcome timing resolution rates regulatory matters believe ultimate resolution issues based information known date material adverse effect financial position results operations cash flows matters december 2001 enron corp number subsidiaries including enron north america corp enron power marketing inc filed chapter 11 bankruptcy protection united states bankruptcy court southern district new york contracts enron north america enron power marketing enron subsidiaries among things transportation natural gas natural gas liquids trading physical gas power petroleum financial derivatives established reserves potential losses related receivables transportation contracts well positions receivables marketing trading contracts believe adequate addition terminated trading related contracts result enrons bankruptcy filings analyzing damage claims arising enron bankruptcy proceedings affiliates enron hold shortterm longterm capacity several pipeline systems result enrons bankruptcy filing uncertain intent maintain release capacity also ability honor terms contracts future revenue related capacity contracts depend upon outcome enrons bankruptcy proceedings ability remarket subsequently released pipeline capacity expect remarket capacity favorable terms cannot time predict successful effort rates receive high currently earn foreign investments subject risks unforeseen obstacles many cases beyond control ability manage attempt manage limit risks due diligence partner selection processes denomination foreign transactions possible us dollars maintaining insurance coverage whenever economical obtainable currently three power plants pakistan total investment including financial guarantees projects approximately 271 million aware specific threats actions power plants events region including possible retaliation american military actions could impact projects related investments time believe combination commercial insurance political insurance rights contractual obligations financial exposure pakistan acts war hostility terrorism political instability material possible however new information future developments region inability party parties fulfill contractual obligations could cause us reassess potential exposure also investments oil natural gas power pipeline projects argentina aggregate investment including financial guarantees approximately 381 million economic conditions argentina significantly deteriorated 2001 argentine government recently defaulted public debt obligations addition government imposed several changes law first quarter 2002 including repeal onetoone exchange rate argentine peso us dollar ii mandate contracts obligations previously denominated us dollars renegotiated denominated argentine pesos iii tax imposed hydrocarbon potentially electric power exports argentine peso devaluation combined new law changes effectively convert projects contracts us dollars argentine pesos result significant reduction value investments argentina monitoring situation closely pursue options available us political risk insurance policies international arbitration provisions united states argentina bilateral investment treaty despite current actions project management options available us may mitigate exposure may required write investment substantial amount first quarter 2002 cases california cases discussed five filed superior court los angeles county continental forge company et al v southern california gas company et al filed september 25 2000 berg v southern california gas company et al filed december 18 2000 county los angeles v southern california gas company et al filed january 8 2002 city los angeles et al v southern california gas company et al city long beach et al v southern california gas company et al filed march 20 2001 two filed superior court san diego county john whk phillip v el paso merchant energy john phillip v el paso merchant energy filed december 13 2000 three filed superior court san francisco county sweeties et al v el paso corporation et al filed march 22 2001 philip hackett et al v el paso corporation et al filed may 9 2001 california dairies inc et al v el paso corporation et al filed may 21 2001 one filed superior court state california county alameda dry creek corporation v el paso natural gas company et al filed december 10 2001 shareholder derivative suit dismissed styled clark et al v allumbaugh et al superior court orange county filed august 23 2001 six remaining carlsbad lawsuits discussed follows one filed district court harris county texas geneva smith et al v epec epng filed october 23 2000 five filed state district court carlsbad new mexico chapman personal representative estate amy smith heady v epec epng john cole filed february 9 2001 chapman personal representative estate dustin wayne smith v epec epng john cole chapman personal representative estate terry wayne smith v epng epec john cole rackley personal representative estate glenda gail sumler v epec epng john cole rackley personal representative estate amanda sumler smith v epec epng john cole filed march 16 2001 reached contingent settlement additional case dawson personal representative kirsten janay sumler v epec epng filed november 8 2000 capital commitments purchase obligations december 31 2001 capital investment commitments 24 billion primarily relating production pipeline international power activities planned capital investment projects discretionary nature substantial capital commitments made advance actual expenditures pipelines entered unconditional purchase obligations products services totaling 346 million december 31 2001 annual obligations agreements 34 million 2002 32 million 2003 34 million years 2004 2005 2006 178 million total thereafter operating leases maintain operating leases ordinary course business activities leases include office space operating facilities office operating equipment terms agreements vary 2002 2053 december 31 2001 total commitments operating leases approximately 677 million several leases provided residual value guarantees lessor guarantees either choose purchase asset end lease term specified amount typically equal outstanding loan amounts owed lessor choose assist sale leased asset third party asset sold price equals exceeds amount guarantee would obligated shortfall levels residual value guarantees range 860 percent 899 percent original cost leased assets total outstanding residual value guarantees operating leases december 31 2001 see residual value guarantees minimum annual rental commitments december 31 2001 follows aggregate minimum commitments reduced minimum sublease rentals approximately 16 million due future noncancelable subleases rental expense operating leases years ended december 31 2001 2000 1999 147 million 198 million 157 million lines credit commitment loan mesquite subsidiary chaparral affiliate 725 million december 31 2001 mesquite borrowed 552 million facility resulting undrawn commitment 173 million interest rate facility based libor plus margin 264 december 31 2001 letters credit enter letters credit ordinary course operating activities december 31 2001 outstanding letters credit 465 million related marketing trading activities domestic power development operating activities guarantees involvement joint ventures project level construction finance results issuance financial nonfinancial guarantees business activities also guarantee performance contractual commitments companies within consolidated group various events circumstances may require us perform guarantees including nonpayment guaranteed party noncompliance covenants transactions guaranteed party noncompliance us provision guarantees crossacceleration transactions december 31 2001 approximately 15 billion guarantees connection international development operating activities consolidated balance sheet approximately 19 billion guarantees connection domestic development operating activities consolidated balance sheet amounts approximately 950 million relates gemstone investment 10 billion relates chaparral investment residual value guarantees december 31 2001 738 million residual value guarantees supporting operating leases expire 2002 2006 commercial commitments may october 2001 entered agreements time charter four separate ships secure transportation developing liquefied natural gas business agreements provide deliveries vessels 2003 2005 time charter 20year term commencing vessels delivered possibility two 5year extensions total commitment four time charter agreements 18 billion 15 retirement benefits pension benefits maintain defined benefit pension plan covers substantially us employees provides benefits cash balance formula employees participating el pasos defined benefit pension plan december 31 1996 receive greater cash balance benefits prior plan benefits accrued december 31 2001 effective january 1 2000 sonats pension plan merged pension plan sonat employees participants sonat pension plan december 31 1999 receive greater cash balance benefits sonat plan benefits accrued december 31 2004 prior merger coastal provided noncontributory pension plans covering substantially us employees april 1 2001 coastals primary plan merged existing plan coastal employees participants coastals primary plan march 31 2001 receive greater cash balance benefits coastal plan benefits accrued march 31 2006 following mergers coastal sonat offered early retirement incentive program eligible employees organizations programs offered enhanced pension benefits individuals elected early retirement charges incurred connection sonat program 8 million connection coastal program 152 million plan assets coastals pension plan included coastals common stock class common stock amounting total 89 million shares conversion december 31 2000 1999 addition coastals primary pension plan separate plans provided employees coal convenience store operations also participate several multiemployer pension plans benefit employees union members contributions plans material 2001 2000 retirement savings plan maintain defined contribution plan covering us employees match 75 percent participant basic contributions 6 percent matching contribution made plans stock fund participants elect move matching contribution time seven remaining funds leave stock fund prior merger coastal matched 100 percent basic contributions 8 percent matching contributions made coastal stock amounts expensed combined plans approximately 30 million 35 million 36 million years ended december 31 2001 2000 1999 postretirement benefits provide postretirement medical benefits anr coal closed groups retired employees epng el paso tennessee sonat coastal limited postretirement life insurance benefits current retired employees postretirement employee benefits opeb prefunded extent costs recoverable rates extent actual opeb costs tgp epng sng differ amounts recovered rates regulatory asset liability recorded early retirement incentive program coastal employees participating eligible employees allowed keep postretirement medical life benefits commencing later age 50 retirement total charges associated coastal incentive program elimination retiree benefits future retirees 65 million early retirement incentive program employees pges texas midstream operations participating eligible employees allowed keep postretirement medical life benefits commencing later age 55 retirement total liabilities incentive program 8 million medical benefits closed groups retirees may subject deductibles copayment provisions limitations dollar caps amount employer costs reserve right change benefits following table sets forth change benefit obligation change plan assets reconciliation funded status components net periodic benefit cost pension benefits postretirement benefits presented computed twelve months ended september 30 coastals 2000 2001 disclosure information determined twelve months ended december 31 2000 september 30 2001 included information plans projected benefit obligation accumulated benefit obligation pension plans accumulated benefit obligations excess plan assets 51 million 47 million december 31 2001 50 million 41 million december 31 2000 accrued benefit costs related plans years ended december 31 2001 2000 61 million 51 million current liability portion postretirement benefits 46 million december 31 2001 2000 benefit obligations based upon actuarial estimates described assumptions differed average rates presented actuarial estimates postretirement benefits plans assumed weighted average annual rate increase per capita costs covered health care benefits 95 percent 2001 gradually decreasing 6 percent year 2008 assumed health care cost trends significant effect amounts reported postretirement benefit plans onepercentage point change assumed health care cost trends would following effects 16 capital stock december 2001 issued 203 million shares common stock approximately 863 million net issuance costs 50000000 shares authorized preferred stock par value 001 per share 7500000 shares designated series junior participating preferred stock reserved issuance pursuant preferred stock purchase rights plan march 2000 issued 200000 shares el paso series b mandatorily convertible single reset preferred stock connection issuance chaparral third party notes november 2001 also issued 190000 shares el paso series c mandatorily convertible single reset preferred stock connection issuance gemstone third party notes chaparral gemstone preferred stock issuances separate share trusts therefore reflected preferred stock issuances financial statements 17 stockbased compensation grant stock awards various stock option plans account stock option plans using accounting principles board opinion 25 related interpretations employee plans may issue incentive stock options common stock intended qualify section 422 internal revenue code nonqualified stock options restricted stock appreciation rights sars phantom stock options performance units nonemployee director plans may issue nonqualified stock options deferred shares common stock reserved approximately 74 million shares common stock existing future stock awards december 31 2001 approximately 26 million shares remained unissued nonqualified stock options granted nonqualified stock options employees 2001 2000 1999 stock options contractual terms 10 years generally vest completion one five years continuous employment grant date also granted options nonemployee members board directors fair market value grant date exercisable immediately summary stock options stock options outstanding december 31 2001 2000 1999 presented fair value stock option granted estimated date grant using blackscholes optionpricing model following weightedaverage assumptions blackscholes weighted average fair value options granted 2001 2000 1999 1575 1016 1142 pro forma net income net income per common share compensation expense stockbased compensation plans determined applying provisions sfas 123 net income net income per common share 2001 2000 1999 would approximate pro forma amounts effects applying sfas 123 pro forma disclosure indicative future amounts sfas 123 apply awards granted prior 1995 fiscal year restricted stock stockbased compensation plans limited number shares restricted common stock may granted officers employees shares carry voting dividend rights however sale transfer shares restricted stock awards vest specific period time andor achieve established performance targets restricted stock awards representing 23 million 04 million 14 million shares granted 2001 2000 1999 weighted average grant date fair value 6210 3482 3510 per share december 31 2001 43 million shares restricted stock outstanding value restricted shares subject performance vesting determined based fair market value date performance targets achieved value charged compensation expense ratably required service restriction period value time vested restricted shares determined issuance date cost amortized compensation expense period service 2001 2000 1999 charges totaled 144 million 13 million 69 million included deferred compensation december 31 2000 69 million related options converted automatically common stock end vesting period options met performance targets december 2000 performance units phantom stock options award eligible employees phantom stock options payable cash also award eligible employees officers performance units payable cash stock end vesting period final value performance units may vary according plan granted usually based common stock price end vesting period total shareholder return vesting period value performance units charged ratably compensation expense vesting period periodic adjustments account fluctuation market price stock changes expected total shareholder return amounts charged compensation expense 2001 2000 1999 64 million 25 million 30 million 2001 expense includes 51 million charge pay outstanding phantom stock options included 1999 amount 22 million related accelerated vesting performance units due change control resulting merger sonat employee stock purchase program october 1999 implemented employee stock purchase plan section 423 internal revenue code plan allows participating employees right purchase common stock quarterly basis 85 percent lower market price beginning plan period end calendar quarter two million shares common stock authorized issuance plan following table presents number shares issued price per share quarter year ended december 31 1 since many employees reached maximum contribution imposed section 423 internal revenue code third quarter 2001 excluded participating fourth quarter 2001 funds receive program may used general corporate purposes however record liability withholdings yet applied towards purchase common stock bear expenses associated administering plan except costs including applicable taxes associated participants sale common stock 18 segment information business activities segregated four segments pipelines merchant energy production field services segments strategic business units offer variety different energy products services manage segment separately business requires different technology marketing strategies pipelines segment provides natural gas transmission services us internationally conduct activities seven wholly owned eight partially owned interstate transmission systems along six underground natural gas storage facilities lng terminalling facility pipeline operations also include access us based systems canada mexico well interests three operating natural gas transmission systems australia merchant energy segment involved broad range energyrelated activities including asset ownership customer origination marketing trading financial services buy sell trade natural gas power crude oil refined products coal energy commodities throughout world interests 95 power generation plants 20 countries production segment engaged exploration acquisition development production natural gas oil natural gas liquids primarily north america production onshore coal seam operations properties 19 states offshore operations properties federal state waters gulf mexico internationally exploration production rights australia bolivia brazil canada hungary indonesia turkey field services segment provides wellheadtomainline services including natural gas gathering products extraction fractionation dehydration purification compression transportation natural gas natural gas liquids field services assets located san juan basin rocky mountains east south texas midcontinent permian basin gulf mexico louisiana accounting policies individual segments described note 1 since earnings equity investments significant component earnings several segments chosen evaluate segment performance based earnings interest taxes ebit instead operating income extent practicable results operations years ended december 31 2000 1999 reclassified conform current business segment presentation although results necessarily indicative results would achieved revised business segment structure effect period 1 includes corporate eliminations well retail operations june 2001 telecommunications operations significant activity sold majority retail operations 2001 2 increase intersegment revenue 2000 2001 production segment primarily due consolidation engage september 2000 1 includes corporate eliminations well retail operations telecommunications operations significant activity 1 includes corporate eliminations well retail operations reconciliations ebit income extraordinary items cumulative effect accounting change presented three years ended december 31 customers whose revenues exceeded 10 percent total revenues 2001 2000 1999 19 supplemental cash flow information following table contains supplemental cash flow information years ended december 31 see note 2 discussion noncash investing transactions related acquisitions 20 investments advances unconsolidated affiliates hold investments various unconsolidated affiliates accounted using equity method accounting principal equity method investees international pipelines interstate pipelines power generation plants gathering systems investment balance includes unamortized purchase price differences 393 million 402 million december 31 2001 2000 amortized remaining life unconsolidated affiliates underlying assets net ownership interest investments advances unconsolidated affiliates follows december 31 1 mesquite investors llc included chaparral 2 citrus corporation owns 100 percent florida gas transmission system 3 ownership interest consists one percent general partner interest 26 percent partnerships common units preferred units 143 million liquidation value 4 denotes investments less 50 million 5 contributed gemstone 2001 earnings unconsolidated affiliates follows three years ended december 31 discussed note 2 divested ownership interest empire state iroquois stingray ut offshore pipeline systems october 2000 terminated engage joint venture formed 1997 result operations divided separate entities owned operated independently former joint venture partner summarized financial information proportionate share unconsolidated affiliates includes affiliates hold less 50 percent interest well hold greater 50 percent interest proportional shares unconsolidated affiliates hold greater 50 percent interest net income 38 million 48 million december 31 2001 2000 total assets 766 million 589 million december 31 2001 2000 following table shows revenues charges unconsolidated affiliates 1 decrease 2001 affiliated revenue cost sales due primarily consolidation engage september 2000 chaparral 1999 formed series companies thirdparty financial investor refer chaparral also known electron formed obtain low cost financing fund growth unregulated domestic power generation related businesses chaparral acquired currently owns equity interests 39 natural gasfired generation facilities arizona california colorado connecticut florida massachusetts nevada new jersey new york pennsylvania rhode island chaparral also owns several operating companies provide services required operate maintain facilities natural gas service company provides fuel procurement services eight chaparrals natural gasfired generation facilities california total third party capital chaparral 115 billion including 012 billion contributed 1999 103 billion contributed 2000 10 billion debt raised 2000 third party investor note issuance matures march 2003 entered various financing transactions chaparral subsidiaries year include capital contributions debt issuances advances following table summarizes presentation transactions balance sheet december 31 millions account equity investment chaparral using equity method accounting since ability exercise control entity debt securities notes payable receivable revolving credit facility contingent interest promissory notes included current longterm receivables payables unconsolidated affiliates appropriate related interest income expense income statement debt securities payable chaparral payable demand carry fixed interest rate 7443 notes payable receivable chaparral payable demand carry various fixed interest rates credit facility established 1999 allows chaparral borrow 725 million us variable interest rate 26 december 31 2001 contingent interest promissory notes carry variable interest rate exceed 1275 mature 2019 2021 interest payments contingent cash flow distributions five power plant investments principal repayment guaranteed us sell investments maturity date notes may accelerated chaparral used funds raised thirdparty financial investors acquire domestic power generation related businesses described cases chaparral acquired power generation assets us chaparral acquired power generation assets us value 276 million 659 million 2001 2000 determined fair reasonable amount recognize gains losses transactions addition financing transactions described also entered various contractual agreements chaparral related management trading activities serve manager chaparral management agreement expires 2006 compensated services provide annual performancebased management fee amounted 147 million 2001 80 million 2000 performancebased management fee calculated based value chaparrals assets determined using cash flow techniques also receive fixed fee reimbursement outofpocket thirdparty expenses incurred behalf chaparral 20 million 2001 2000 merchant energy segment also enters various contractual agreements chaparral operating subsidiaries conjunction chaparrals operations include agreements supply natural gas fuels power chaparrals facilities ii purchase portion power produced chaparrals facilities iii provide power supply chaparral obligated provide fulfill agreements third parties iv purchase tolling rights v provide services chaparral related operations account agreements trading price risk management activities recognized revenues 266 million 119 million 2001 2000 costs sales 121 million 42 million 2001 2000 related transactions additional credit support chaparrals notes issued mandatorily convertible preferred stock aggregate liquidation preference 1 billion share trust control upon occurrence negative events including decline stock price 2707 ten consecutive trading days coupled downgrades credit ratings investment grade could required remarket preferred stock terms designed generate sufficient amount cash repay third party investors debt gemstone november 2001 formed thirdparty financial investor series companies refer gemstone formed provide financing vehicle fund development growth power generation merchant energy related businesses brazil third party financial investor contributed gemstone 50 million capital raised additional 950 million note issuance matures october 2004 proceeds used gemstone acquire brazilian power investment invest 300 million preferred securities one consolidated subsidiaries temporarily invest excess proceeds 462 million shortterm notes us debt securities outstanding balance 346 million december 31 2001 payable demand carry fixed interest rate 525 preferred securities subsidiary entitle gemstone preferred return 803 contributed 280 million cash well several brazilian investments total value 274 million exchange interest gemstone received approximately 762 million cash issuance debt securities preferred securities gemstone used acquire interest electric generation assets brazil general corporate purposes investment gemstone december 31 2001 555 million account investment using equity method accounting since ability exercise control entity shortterm notes issued included shortterm borrowings balance sheet related interest expense income statement account investors preferred interest consolidated subsidiary minority interest balance sheet preferred return minority interest expense income statement management agreement gemstone earn costbased management fee significant 2001 also entered participation agreement one gemstones power generation interests whereby earn fee managing constructing operating related facilities marketing distributing energy produced facilities fee significant 2001 additional credit support gemstones notes issued mandatorily convertible preferred stock aggregate liquidation preference 950 million share trust control upon occurrence negative events including decline stock price 3616 ten consecutive trading days coupled downgrades credit ratings investment grade could required remarket preferred stock terms designed generate sufficient amount cash repay third party investors debt photon 2000 contributed 44 million equity capital assets series companies refer photon acquired held telecommunications assets third party financial investor contributed 60 million photon earned preferred return subordinated promissory note receivable photon demand note payable photon net receivable balance approximately 33 million december 31 2000 paid 2001 acquired thirdparty interest fair value 63 million accounted acquisition purchase reflecting carrying amount photons assets liabilities consolidated financial statements el paso energy partners third quarter 2000 el paso energy partners completed public offering 46 million common units offering reduced common units ownership interest 325 percent 278 percent transaction effect general partner interest nonmanaging member interest also third quarter received 170 million series b preference units exchange sale natural gas storage businesses crystal gas storage inc wholly owned subsidiary el paso energy partners preference units accrue dividends rate 10 cumulative basis redeemable option el paso energy partners 2001 result merger coastal el paso energy partners sold interest several offshore assets including seven natural gas pipeline systems dehydration facility two offshore platforms proceeds sales approximately 135 million resulted loss partnership approximately 25 million consideration sales committed pay el paso energy partners series payments totaling 29 million required contribute 40 million trust related one assets sold el paso energy partners payments recorded mergerrelated costs march 2001 el paso energy partners issued 23 million common units reducing ownership interest common units 26 percent october 2001 partnership issued 56 million common units purchased 15 million units maintaining common unit ownership interest 26 percent also october 2001 partnership redeemed 50 million liquidation value series b preference units received crystal transaction december 31 2001 liquidation value remaining series b preference units 143 million general partner perform substantially daily operations provide strategic direction el paso energy partners management agreement operating agreements el paso energy partners provide reimbursement various operational financial accounting administrative services perform partnership management agreement expires june 30 2002 may terminated thereafter upon 90day notice either party recorded total reimbursements 34 million 22 million 2001 2000 addition activities described enter transactions el paso energy partners normal course business sale natural gas services transportation fractionation storage processing types operational services activities based terms nonaffiliates recognized revenues 34 million 17 million 2001 2000 cost sales 56 million 26 million 2001 2000 21 supplemental selected quarterly financial information unaudited financial information quarter summarized 1 adjustments made conform accounting presentation coastal presentation include reclassifications conform current presentation reclassifications impact net income retained earnings 1 adjustments made conform accounting presentation coastal presentation include reclassifications conform current presentation reclassifications impact net income retained earnings 22 supplemental natural gas oil operations unaudited december 31 2001 interests natural gas oil properties 19 states offshore operations properties federal state waters gulf mexico internationally limited number natural gas oil properties brazil canada indonesia well exploration production rights australia bolivia brazil canada hungary indonesia turkey purposes supplemental natural gas oil operations disclosure presented reserves standardized measure discounted future net cash flows related changes standardized measure separately natural gas systems operations includes regulated natural gas oil properties owned colorado interstate gas company subsidiaries supplemental natural gas oil operations disclosure include value natural gas systems storage gas liquids volumes managed pipeline segment capitalized costs relating natural gas oil producing activities related accumulated depreciation depletion amortization follows december 31 millions 1 includes international operations brazil indonesia costs incurred natural gas oil producing activities whether capitalized expensed follows december 31 millions 1 includes international operations brazil indonesia presented analysis capitalized costs natural gas oil properties year expenditure amortized december 31 2001 pending determination proved reserves capitalized interest 51 million 25 million 2 million years ended december 31 2001 2000 1999 included presentation millions projects presently excluded amortization various stages evaluation majority costs expected included amortization calculation years 2002 2005 total amortization expense per mcfe including ceiling test charges 122 100 164 2001 2000 1999 excluding ceiling test charges amortization expense would 104 091 per mcfe 2001 1999 depreciation depletion amortization excludes provisions impairment international projects 15 million 2000 10 million 1999 proved properties exception proved reserves brazil indonesia located north america us canada net quantities proved developed undeveloped reserves natural gas liquids including condensate crude oil changes reserves presented reserves include 124158 197782 259342 mmcfe production delivery commitments financing arrangements extend 2005 total proved reserves fields dedicated production 1981239 mmcfe addition table excludes productions 50 percent interest unopaso pescada brazil merchant energys 50 percent equity interest sengkang indonesia merchant energys 45 percent 2475 percent equity interest capsa capex argentina field services 27 percent equity interest el paso energy partners combined proved reserve balances equity interests include natural gas reserves 361997 mmcf liquids reserves 44711 mbbls net ownership interests 1 includes international operations brazil indonesia 2 includes natural gas oil properties owned colorado interstate gas company subsidiaries 3 net proved reserves exclude royalties interests owned others reflects contractual arrangements royalty obligations effect time estimate 1 includes oil condensate natural gas liquids 2 includes international operations brazil indonesia 3 includes natural gas oil properties owned colorado interstate gas company subsidiaries 4 net proved reserves exclude royalties interests owned others reflects contractual arrangements royalty obligations effect time estimate numerous uncertainties inherent estimating quantities proved reserves projecting future rates production timing development expenditures including many factors beyond control reserve data represents estimates reservoir engineering subjective process estimating underground accumulations natural gas oil cannot measured exact manner significant changes reserves purchases sales production due reservoir performance existing fields drilling additional wells existing fields major discoveries events favorable adverse may considered caused significant change estimated proved reserves since december 31 2001 results operations producing activities fiscal year follows december 31 millions 1 includes international operations brazil indonesia standardized measure discounted future net cash flows relating proved natural gas oil reserves follows december 31 millions 1 includes international operations brazil indonesia 2 includes natural gas oil properties owned colorado interstate gas company subsidiaries calculations preceding table estimated future cash inflows estimated future production proved reserves computed using yearend market natural gas oil prices may receive amounts different standardized measure discounted cash flow number reasons including price changes effects hedging activities rely upon standardized measure making investment operating decisions based various factors including probable proved reserves different price cost assumptions actual economic conditions corporate investment criteria following principal sources change standardized measure discounted future net cash flows millions 1 includes operations united states canada brazil indonesia 2 includes natural gas oil properties owned colorado interstate gas company subsidiaries report independent accountants board directors stockholders el paso corporation opinion based upon audits report auditors consolidated financial statements listed index item 14a1 present fairly material respects financial position el paso corporation subsidiaries december 31 2001 2000 results operations cash flows three years period ended december 31 2001 conformity accounting principles generally accepted united states america addition opinion based audits report auditors financial statement schedule listed index item 14a2 presents fairly material respects information set forth therein read conjunction related consolidated financial statements financial statements financial statement schedule responsibility companys management responsibility express opinion financial statements financial statement schedule based audits consolidated financial statements financial statement schedule give retroactive effect merger el paso cgp company formerly coastal corporation january 29 2001 transaction accounted pooling interests described note 2 consolidated financial statements audit financial statements financial statement schedule el paso cgp company december 31 2000 two years period ended statements reflect total assets 19066 million december 31 2000 total revenues 26936 million 16596 million two years period ended december 31 2000 statements audited auditors whose report thereon furnished us opinion expressed herein insofar relates amounts included el paso cgp company december 31 2000 two years ended based solely report auditors conducted audits statements accordance auditing standards generally accepted united states america require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements assessing accounting principles used significant estimates made management evaluating overall financial statement presentation believe audits report auditors provide reasonable basis opinion described notes 1 9 company adopted statement financial accounting standards 133 accounting derivatives hedging activities january 1 2001 pricewaterhousecoopers llp houston texas march 6 2002 schedule ii el paso corporation valuation qualifying accounts years ended december 31 2001 2000 1999 millions 1primarily accounts written 2in 2001 finalized purchase price adjustment legal reserves related pge acquisition 3of amount 232 million relates additional environmental remediation liabilities recorded connection events described note 14 4we accrued 23 million 2001 reversed 24 million reserves corpus christi refinery leased valero june 5of amount 53 million legal reserve acquired connection purchase pges texas midstream operations recorded additional 159 million legal reserves related purchase price adjustments pge acquisition item 9item 8 financial statements supplementary data index financial statements notes contained item 8 financial statements supplementary data el paso corporation consolidated statements income millions except per common share amounts see accompanying notes el paso corporation consolidated balance sheets millions except share amounts see accompanying notes el paso corporation consolidated balance sheets continued millions except share amounts see accompanying notes el paso corporation consolidated statements cash flows millions see accompanying notes el paso corporation consolidated statements stockholders equity millions see accompanying notes el paso corporation consolidated statements comprehensive income millions see accompanying notes el paso corporation notes consolidated financial statements 1 summary significant events accounting policies significant events overview industry developments 2002 experienced dramatic changes industry well financial markets rely response industry events credit rating agencies including moodys standard poors reevaluated ratings companies involved energy trading activities result ratings many largest participants energy trading industry including us downgraded investment grade also impacting us preliminary decision reached ferc administrative law judge alj one subsidiaries withheld pipeline capacity california market 2000 2001 reacting changes market leverage preliminary decision ferc california matters moodys standard poors initiated series ratings actions lowering senior unsecured debt rating caa1 b investment grade ratings remain negative outlook several negative outcomes resulted downgrades first cash generated 2002 sales assets originally identified debt reductions instead required posted additional cash collateral connection commercial trading activities paid meet financial guarantees used meet arrangements additionally access capital markets commercial paper markets became restricted lower credit ratings finally credit downgrades resulted net cash generated assets two minority interest financing arrangements largely unavailable us general corporate purposes instead required use cash redeem preferred securities issued connection arrangements operation businesses collateralize arrangements march 2003 redeemed outstanding amounts one financing arrangements partially freeing cash usage restrictions discussion see note 19 liquidity developments rely cash generated operations primary source liquidity also expect rely borrowings available credit facilities bank financings asset sales issuance longterm debt preferred equity securities provide liquidity needed overall flexibility believe future working capital needs capital expenditures longterm debt repayments dividends financing activities continue provided sources liquidity since fourth quarter 2001 taken number actions address liquidity issues made progress plans meet demands liquidity strengthen capital structure accomplishments included sale 25 billion equity equityrelated securities completion announcement 55 billion asset sales removal 4 billion rating triggers investment financing programs would resulted issuance common stock accelerated repayment obligations announcement plan exit trading business minimize involvement lng business february 5 2003 announced 2003 operational financial plan based five key principles preserving enhancing value core natural gas pipeline businesses exiting noncore businesses quickly prudently strengthening simplifying balance sheet maximizing liquidity aggressively pursuing additional cost reductions continuing work diligently resolve litigation regulatory matters march 2003 made progress accomplishing objectives plan including finalization new 12 billion term loan allowed us retire trinity river preferred interest financing arrangement eliminate cash restrictions accelerated amortization requirements arrangement ii repayment 19 billion financial obligations including electron trinity river iii issuance 700 million bonds two wholly owned subsidiaries iv announcement agreement principle settle principal claims asserted us western energy crisis 2001 believe accomplishment announced plan enable us address liquidity issues simplify improve capital structure however number factors could influence timing ultimate outcome efforts significant accounting policies basis presentation consolidated financial statements include accounts majorityowned controlled subsidiaries elimination significant intercompany accounts transactions financial statements prior periods include reclassifications made conform current year presentation reclassifications impact reported net income stockholders equity principles consolidation consolidate entities ability control operating financial decisions policies entity exert significant influence control policies decisions apply equity method accounting use cost method accounting unable exert significant influence entity determination ability control exert significant influence entity involves use judgment extent control influence equity owners participants entity discussed part new accounting principles issued yet adopted standard effective impact consolidation principles use estimates preparation financial statements conformity us generally accepted accounting principles requires use estimates assumptions affect amounts report assets liabilities revenues expenses disclosures financial statements actual results often differ estimates accounting regulated operations interstate natural gas systems storage operations subject regulations accounting procedures ferc accordance natural gas act 1938 natural gas policy act 1978 interstate systems including tgp epng sng mpc apply provisions statement financial accounting standards sfas 71 accounting effects certain types regulation anr cig wic discontinued application sfas 71 1996 accounting regulated businesses apply provisions sfas 71 differs accounting requirements regulated businesses apply sfas 71 transactions recorded differently result regulatory accounting requirements include capitalization equity return component regulated capital projects employee related benefits depreciation costs taxes included expected included future rates application sfas 71 based current regulatory environment current tariff rates future regulatory developments rate cases could impact accounting things may influence assessment inability recover cost increases due rate caps rate case moratoriums inability recover capitalized costs including adequate return costs ratemaking process ferc proceedings excess capacity discounting rates markets serve impacts ongoing initiatives deregulation natural gas industry continue evaluate application regulatory accounting principles based ongoing changes regulatory economic environment cash equivalents consider shortterm investments original maturity less three months cash equivalents maintain cash deposit banks insurance companies pledged particular use restricted support potential liability classify balances current noncurrent assets balance sheet based expect cash used december 31 2002 2001 reported 124 million 17 million current assets 212 million 75 million noncurrent assets allowance doubtful accounts establish provisions losses accounts receivable natural gas imbalances due shippers operators determine collect part outstanding balance regularly review collectibility establish adjust allowance necessary using specific identification method inventory consists refined products crude oil chemicals materials supplies natural gas storage coal optic fiber also hold power turbines inventory classify inventory current noncurrent based whether sold used next twelve months report noncurrent inventory part noncurrent assets balance sheets use firstin firstout average cost methods account refined products crude oil chemicals inventories average cost method account inventories value inventory lower cost market value october 1 2002 adopted provisions emerging issues task force eitf issue 023 required us reclassify physical commodity inventory used trading activities net assets price risk management activities inventory balance sheet adjust inventory lower cost market see price risk management activities discussion accounting change natural gas oil imbalances exchanges natural gas oil imbalances occur actual amount natural gas oil delivered received pipeline system processing plant storage facility differs contractual amount scheduled delivered received natural gas exchange transactions involve receiving delivering natural gas inventory made inkind value imbalances exchanges due shippers operators appropriate market index price imbalances exchanges settled cash made inkind subject contractual terms settlement tariffs imbalances exchanges due others reported balance sheet either accounts receivable customers accounts receivable unconsolidated affiliates imbalances exchanges owed others reported balance sheet either trade accounts payable accounts payable unconsolidated affiliates addition imbalances exchanges classified current longterm depending expect settle october 1 2002 adopted provisions eitf issue 023 required us reclassify natural gas exchanges resulting trading activities net assets price risk management activities accounts receivable accounts payable balance sheet see price risk management activities discussion accounting change property plant equipment property plant equipment recorded original cost construction upon acquisition either fair value assets acquired cost entity first placed asset service capitalize direct costs labor materials indirect costs overhead interest regulated businesses apply provisions sfas 71 equity return component capitalize major units property replacements improvements expense minor items included pipeline property balances additional acquisition costs represent excess purchase costs associated purchase business combinations allocated regulated interstate systems costs amortized straightline basis recover excess costs rates following table presents property plant equipment type depreciation method remaining useful lives depreciation rate 1 regulated interstate systems apply sfas 71 use composite group method depreciate property plant equipment method assets similar useful lives characteristics grouped depreciated one asset apply depreciation rate approved tariff total cost group net book value equals salvage value reevaluate depreciation rates time redevelop transportation rates file ferc increase decrease rates retire regulated property plant equipment accounted sfas 71 charge accumulated depreciation amortization original cost plus cost remove sell dispose less salvage value recognize gain loss unless sell entire operating unit include gains losses dispositions operating units income retire regulated property plant equipment accounted sfas 71 nonregulated properties reduce property plant equipment original cost less accumulated depreciation salvage value remaining gain loss recorded income capitalize carrying cost funds invested construction longlived assets carrying cost consists interest cost investment financed debt applies regulated nonregulated transmission businesses ii return investment financed equity applies regulated transmission businesses apply sfas 71 debt portion calculated based average cost debt interest cost debt amounts capitalized years ended december 31 2002 2001 2000 33 million 65 million 82 million amounts included reduction interest expense income statements equity portion calculated using recent ferc approved equity rate return equity amounts capitalized years ended december 31 2002 2001 2000 8 million 8 million 2 million amounts included nonoperating income statement capitalized carrying cost debt equity reflected increase cost asset balance sheet asset impairments apply provisions sfas 144 accounting impairment disposal longlived assets account asset impairments standard evaluate asset impairment events circumstances indicate longlived assets carrying value may recovered events include market declines changes manner intend use asset decisions sell asset adverse changes legal business environment adverse actions regulators decide exit sell longlived asset group assets adjust carrying value assets downward necessary estimated sales price less costs sell also reclassify asset assets either held sale discontinued operations depending whether independently determinable cash flows natural gas oil properties use full cost method account natural gas oil properties full cost method substantially productive nonproductive costs incurred connection acquisition exploration development natural gas oil reserves capitalized amounts include costs unproved properties internal costs directly related acquisition development exploration activities capitalized interest amortize costs using unit production method life proved reserves quarter calculate unit production depletion rate based estimated production estimate proved reserves capitalized costs associated unproved properties excluded amortizable costs properties evaluated future development costs dismantlement restoration abandonment costs net estimated salvage values included costs subject amortization capitalized costs net related income tax effects limited ceiling based present value future net revenues using end period spot prices discounted 10 percent plus lower cost fair market value unproved properties net related income tax effects discounted revenues equal greater total capitalized costs required writedown capitalized costs level perform ceiling test calculation quarter required writedowns included income statement ceiling test charge ceiling test calculations include effects derivative instruments designated cash flow hedges anticipated future natural gas oil production recognize gain loss sales natural gas oil properties unless sales would significantly alter relationship capitalized costs proved reserves treat sales proceeds nonsignificant sales adjustment cost properties planned major maintenance repair maintenance costs generally expensed incurred unless improve operating efficiency extend useful life asset domestic refining business repair maintenance costs planned major maintenance activities accrued liability systematic rational manner period time planned major maintenance activities occur difference accrued liability actual costs incurred performing maintenance activities charged credited expense time maintenance occurs international refineries cost major maintenance activity capitalized amortized expense systematic rational manner estimated period extending next planned major maintenance activity types costs accrue conjunction major maintenance refineries outside contractor costs materials supplies company labor outside services domestic operations accruals major maintenance 40 million 36 million december 31 2002 2001 international operations capitalized 75 million 51 million years ended december 31 2002 2001 goodwill intangible assets intangible assets consist goodwill resulting acquisitions intangible assets apply sfas 141 business combinations sfas 142 goodwill intangible assets account intangibles standards recognize goodwill separately intangible assets addition goodwill intangibles indefinite lives amortized also goodwill indefinite lived intangible assets periodically tested impairment least annually whenever event occurs indicates impairment may occurred adopted standards january 1 2002 stopped amortizing goodwill also recognized pretax aftertax gain 154 million related elimination negative goodwill reported gain cumulative effect accounting change income statement sfas 142 requires perform impairment tests upon adoption standard january 1 2002 least annually thereafter initial impairment tests performed january 1 2002 indicated impairment goodwill impairment tests performed december 31 2002 however indicated pretax impairment goodwill associated merchant energy segments financial services businesses encap enerplus 44 million impairment recorded 2002 result combined effects weak financial services industry conditions decision continue invest capital financial services businesses net carrying amounts goodwill january 1 2002 december 31 2002 reported net intangible assets balance sheets changes net carrying amounts goodwill year ended december 31 2002 segments follows intangible assets consist customer lists general partnership interest el paso energy partners lp miscellaneous intangible assets amortize intangible assets straightline basis estimated useful life excluding excess investment general partnership interest el paso energy partners determined indefinite life following gross carrying amounts accumulated amortization intangible assets december 31 amortization expense intangible assets subject amortization 9 million year ended december 31 2002 year ended december 31 2001 amortization intangible assets including goodwill 55 million based current amount intangible assets subject amortization estimated amortization expense approximately 2 million next five years amounts may vary result future acquisitions dispositions recorded impairments following table presents income continuing operations extraordinary items cumulative effect accounting changes net income earnings per common share years ended december 31 2001 2000 goodwill indefinitelived intangibles amortized periods compared amounts reported year ended december 31 2002 1 amounts include reclassification results coal business discontinued operations pension postretirement benefits maintain several pension postretirement benefit plans require us make contributions fund benefits paid plans contributions invested benefits paid plan participants record benefit expense income statement benefit expense function many factors including benefits earned year plan participants function employees salary level benefits provided plan actuarial assumptions passage time expected return plan assets recognition certain deferred gains losses well plan amendments compare benefits earned accumulated benefit obligation plans fair value assets annual basis extent plans accumulated benefit obligation exceeds fair value plan assets record minimum pension liability balance sheet equal difference two amounts adjust minimum liability less liability already accrued plan difference greater pension liability recorded balance sheet however record additional liability amount comprehensive loss net income taxes financial statements revenue recognition business segments provide number services sell variety products revenue recognition policies segment follows pipelines revenues pipelines segment derives revenues primarily transportation storage services sales gas sales contracts transportation storage services recognize reservation revenues firm contracted capacity ratably contract period interruptible volumetric based services record revenues complete delivery natural gas agreed upon delivery point natural gas injected withdrawn storage facility revenues natural gas sales contracts recognized physical deliveries commodities made agreed upon delivery point revenues services generally based thermal quantity gas delivered subscribed price specified contract tariff subject ferc regulations result revenues collect may possibly refunded final order pending future rate proceeding result rate settlement established reserves potential refunds production revenues production segments revenues derived principally physical sales natural gas oil natural gas liquids produced revenues sales products recorded upon passage title using sales method net royalty interests profit interests produced product actual natural gas sales volumes exceed entitled share sales volumes overproduced imbalance occurs extent overproduced imbalance exceeds share remaining estimated proved natural gas reserves given property record liability costs associated transportation delivery production included cost sales field services revenues field services segment derives revenues principally gathering transportation processing services sale commodities retained providing services two general types service feebased makewhole feebased services recognize revenues time service rendered based upon volume gas gathered treated processed contracted fee makewhole services fee consists retainage natural gas liquids byproducts result processing recognize revenues services time sell products generally coincides provide service merchant energy revenues merchant energy derives revenues number sources including physical sales natural gas power petroleum products revenues physical sales recognized based volumes delivered contracted market price recognized time commodity delivered specified delivery point revenues commodities sold part merchant energys energy trading division reflected net cost sales energy trading division merchant energy also enters derivative transactions recorded fair value see discussion income recognition policies derivatives price risk management activities corporate revenue producing activities corporate segment consist principally revenues telecommunications business recognize revenues metro transport collocation crossconnect services month services actually used customer environmental costs contingencies record liabilities environmental assessments indicate remediation efforts probable costs reasonably estimated recognize current period expense liability cleanup efforts benefit future periods capitalize costs benefit one accounting period except instances separate agreements legal regulatory guidelines dictate otherwise estimates liabilities based currently available facts existing technology presently enacted laws regulations taking consideration likely effects inflation societal economic factors include estimates associated legal costs amounts also consider prior experience remediating contaminated sites companies cleanup experience data released epa organizations estimates subject revision future periods based actual costs new circumstances included balance sheet current longterm liabilities undiscounted amounts evaluate recoveries insurance coverage government sponsored programs separately liability recovery assured record report asset separately associated liability financial statements recognize liabilities contingencies exposure fully analyzed indicates probable asset impaired liability incurred amount impairment loss reasonably estimated funds spent remedy contingencies charged reserve one exists expensed range probable loss estimated accrue likely amount least minimum range probable loss price risk management activities engage price risk management activities manage market risks associated commodities purchase sell interest rates foreign currency exchange rates price risk management activities include trading activities enter objective generating profits exposure shifts changes market prices nontrading activities related power investment generation power contract restructuring activities nontrading activities involve hedging market price risk exposures assets liabilities contractual commitments forecasted transactions business segments trading nontrading price risk management activities involve use variety derivative financial instruments including exchangetraded futures contracts involve cash settlements forward contracts involve cash settlements physical delivery commodity swap contracts require payments receipts counterparties based difference fixed variable price two variable prices commodity exchangetraded overthe counter options account trading nontrading derivative instruments sfas 133 accounting derivatives hedging activities sfas 133 derivatives reflected balance sheet fair value price risk management activities classify price risk management activities either current noncurrent assets liabilities based overall position counterparty anticipated settlement date cash inflows outflows associated settlement price risk management activities recognized operating cash flows receivables payables resulting settlements reported separately price risk management activities balance sheet trade receivables payables accounting revenues expenses associated price risk management activities varies based whether activities trading activities nontrading activities see note 13 description price risk management activities 2002 adopted dig issue c16 scope exceptions applying normal purchases sales exception contracts combine forward contract purchased option contract dig issue c16 requires fixedprice fuel supply contract allows buyer purchase option additional quantities fixedprice contract derivative must recorded fair value one unconsolidated affiliates midland cogeneration venture limited partnership recognized gain one fuel supply contract upon adoption new rules recorded gain 14 million net income taxes cumulative effect accounting change income statement proportionate share gain 2002 also adopted provisions eitf issue 023 issues related accounting contracts involved energy trading risk management activities prior eitf issue 023 accounted nonderivative trading instruments contracts transportation storage capacity physical natural gas inventory exchanges actively traded part trading business fair value eitf issue 9810 accounting contracts involved energy trading risk management activities eitf issue 023 rescinded eitf issue 9810 reached two general conclusions contracts meet definition derivative sfas 133 marked fair market value revenues costs associated trading activities shown net income statement whether physically settled result adoption eitf issue 023 adjusted carrying value nonderivative trading instruments principally transportation storage capacity contracts zero account using accrual basis accounting also adjusted physical natural gas inventory exchanges used trading business actual cost lower market expected settlement amounts reclassified amounts inventory accounts receivable payable balance sheet adoption eitf issue 023 following impacts financial statements elimination marktomarket value contracts meet definition derivative 225 million reported cumulative effect change accounting principle adjustment carrying value natural gas inventory weighted average cost value exchanges expected settlement price assuming accounted basis since acquisition 118 million reported cumulative effect change accounting principle balance sheet reclassification natural gas inventory exchanges price risk management assets inventory accounts receivable payable 254 million total recorded cumulative effect accounting change income statement 343 million 222 million net income taxes adoption eitf issue 023 also began report trading activity net basis revenues net expenses physically settled purchases component revenues effective july 1 2002 applied guidance prior periods impact previously reported net income stockholders equity revenues costs periods prior adoption eitf issue 023 revised follows income taxes report current income taxes based taxable income provide deferred income taxes reflect estimated future tax payments receipts deferred taxes represent tax impacts differences financial statement tax bases assets liabilities carryovers year end account tax credits flowthrough method reduces provision income taxes year tax credits first become available reduce deferred tax assets valuation allowance based estimates likely portion assets realized future period estimates utilized recognition deferred tax assets subject revision either future periods based new facts circumstances maintain tax accrual policy record regular alternative minimum taxes companies included consolidated federal income tax return policy provides among things company taxable income position accrue current expense equivalent federal income tax ii company tax loss position accrue benefit extent deductions including general business credits utilized consolidated return pay federal income taxes directly irs separate tax billing agreement may bill refund subsidiaries portion income tax payments foreign currency transactions translation record currency transaction gains losses income gains losses classified income statement based upon nature transaction gives rise currency gain loss sales purchases commodities goods gains losses included operating revenue expense gains losses arising equity investees record gains losses equity earnings gains losses foreign denominated debt include gains losses component interest expense 2002 net currency gain recorded operating income less 1 million net currency losses recorded operating income 2001 2000 13 million less 1 million incurred currency losses 2002 approximately 95 million eurodenominated debt included interest expense gains losses minimal foreign denominated debt 2001 2000 us dollar functional currency majority foreign operations foreign operations whose functional currency deemed us dollar assets liabilities translated yearend exchange rates included separate component comprehensive income stockholders equity cumulative currency translation loss recorded accumulated comprehensive income 115 million 97 million december 31 2002 2001 revenues expenses translated average exchange rates prevailing year treasury stock account treasury stock using cost method report balance sheet reduction stockholders equity treasury stock sold issued valued firstin firstout basis included treasury stock december 31 2002 2001 approximately 17 million shares 55 million shares common stock held trust deferred compensation programs stockbased compensation apply provisions accounting principles board opinion 25 apb 25 related interpretations account stockbased compensation plans fixed variable compensation plans account plans using fixed variable accounting appropriate compensation expense variable plans including restricted stock grants measured using market price stock date number shares grant becomes determinable measured expense amortized income period service grant earned stock options issued fixed plan accordingly compensation expense recognized stock options unless options granted exercise price lower market grant date accounted stock option grants using sfas 123 accounting stockbased compensation rather provisions apb 25 income per share impacts stockbased compensation financial statements stockbased compensation would different following shows impact net income earnings per share applied provisions sfas 123 accounting debt extinguishments apply provisions sfas 145 rescission fasb statements 4 44 64 amendment fasb statement 13 technical corrections account debt extinguishments sfas 145 required evaluate gains losses incurred retire debt early determine whether extraordinary nature whether included ordinary income continuing operations income statement third quarter 2002 retired debt totaling 94 million resulted gain 21 million believe continue retire debt near term reported gains income continuing operations part income new accounting pronouncements issued yet adopted december 31 2002 number accounting standards interpretations issued yet adopted us discussion significant standards could impact us accounting asset retirement obligations june 2001 financial accounting standards board fasb issued sfas 143 accounting asset retirement obligations statement requires companies record liability estimated retirement removal costs longlived assets used business liability recorded fair value corresponding asset depreciated remaining useful life longlived asset liability relates ongoing expense also recognized changes value liability result passage time provisions sfas 143 effective fiscal years beginning june 15 2002 expect record charge cumulative effect accounting change approximately 23 million net income taxes upon adoption sfas 143 january 1 2003 also expect record noncurrent retirement assets 184 million noncurrent retirement liabilities 214 million january 1 2003 liability relates primarily obligations plug abandoned wells production pipelines segments next one 101 years accounting costs associated exit disposal activities july 2002 fasb issued sfas 146 accounting costs associated exit disposal activities statement require us recognize costs associated exit disposal activities incurred rather commit exit disposal plan examples costs covered guidance include lease termination costs employee severance costs associated restructuring discontinued operations plant closings exit disposal activities statement effective fiscal years beginning december 31 2002 impact exit disposal activities initiate january 1 2003 accounting guarantees november 2002 fasb issued fasb interpretation fin 45 guarantors accounting disclosure requirements guarantees including indirect guarantees indebtedness others interpretation requires companies record liability guarantees issued january 31 2003 including financial performance fair value guarantees liability recorded fair value upon issuance affect existing guarantees issued january 31 2003 standard also requires expanded disclosures existing guarantees december 31 2002 included required disclosures note 20 consolidation variable interest entities january 2003 fasb issued fin 46 consolidation variable interest entities interpretation arb 51 interpretation defines variable interest entity legal entity whose equity owners sufficient equity risk andor controlling financial interest entity standard requires companies consolidate variable interest entity allocated majority entitys losses andor returns including fees paid entity provisions fin 46 effective variable interest entities created january 31 2003 effective july 1 2003 variable interest entities created january 31 2003 financial interests several entities anticipate considered variable interest entities fall three categories operating leases residual value guarantees consolidated subsidiaries preferred interests held third party financial investors equity investments operating leases residual value guarantees two operating leases provide guarantee lessor residual value facilities lease leases following facilities lakeside technology center telecommunications facility provides collocation crossconnect services facility aruba refinery believe consolidate lessors arrangements july 1 2003 equity investment third party investors banks less 10 percent total capitalization company leases facilities us ii guarantee significant portion funds borrowed lessor buy facilities us consolidate lessors facilities assets owned lessors debt supports assets consolidated financial statements addition assets consolidated subject impairment testing sfas 144 based preliminary analysis believe impact financial statements follows millions consolidated subsidiaries preferred interests held third party investors currently interests consolidate several entities third party investors hold preferred interests preferred interests held third party investors reflected balance sheet preferred securities consolidated subsidiaries third party investors capitalized three percent equity held banks arrangements 97 percent debt believe would consolidate third party investors arrangements equity investment third party investors less specified 10 percent total capitalization investors ii rights third party investors expected residual returns arrangements limited consolidate third party investors minority interest currently classified preferred securities consolidated subsidiaries classified longterm debt clydesdale coastal securities company limited consolidated subsidiaries impacted standard redeemed trinity river financing arrangement march 2003 would also impacted standard believe impact financial statements millions discussion consolidated subsidiaries potentially impacted pronouncement see note 19 equity investments equity investments chaparral gemstone power investments involve disproportionate allocation income losses relative capital investments made equity holders determine whether would required consolidate entities evaluated expected future losses entities losses would allocated owners determined would exposed greatest level expected future losses would consolidate entities based analysis determined likely consolidate investments guarantee debt third party investors exposes us greater level loss however anticipate consolidate investments prior effective date fin 46 expect purchase third party investors interests investments discussion equity investments hold see note 26 2 western energy settlement march 20 2003 entered agreement principle western energy settlement various public private claimants including states california washington oregon nevada resolve principal litigation claims regulatory proceedings us subsidiaries relating sale delivery natural gas electricity september 1996 date settlement see note 20 discussion matter western energy settlement resulted charge fourth quarter 2002 899 million tax approximately 650 million tax amounts represent present value components settlement discounted 10 percent settlement include initial payment cash issuance common stock payment cash delivery natural gas period 20 years settlement become payable beginning execution definitive settlement agreement components settlement allocated among pipelines merchant energy corporate segments based nature component segments ability perform agreement components follows cash payment 100 million settling parties 2 million cash payment officer bonus pool issuance approximately 264 million shares common stock delivery california border 45 million worth natural gas annually 20 years beginning 2004 reduction pricing longterm power supply contracts california department water resources 125 million remaining term contracts run end 2005 payment settling parties 22 million year cash option cash stock 20 years period five years epng make available california delivery points 3290 mmcfd capacity primary delivery point basis period five years affiliate subject restrictions subscribing new capacity epng system admission wrongdoing settlement subject review approval state courts ferc total obligation settlement reflected balance sheet 09 billion represents notional amount approximately 17 billion less discount rate 10 percent approximately 08 billion components obligation settlement follows discount amortized interest expense annually amount based constant rate interest 10 percent applied declining obligation balance amortization expected approximately 47 million 2003 income taxes 3 mergers divestitures coastal merger january 2001 merged coastal accounted transaction pooling interests converted share coastals common stock class common stock taxfree basis 123 shares common stock also exchanged coastals outstanding convertible preferred stock common stock basis preferred stock converted coastal common stock immediately prior merger issued approximately 271 million shares common stock including 4 million shares exchange coastal stock options following table presents revenues net income previously separate companies combined amounts presented audited combined financial statements year ended december 31 2000 millions several adjustments made conform accounting presentation financial information 1 conforming reclassifications primarily include grossup revenues associated coastals physical petroleum marketing trading activities consistent method reporting revenues 2 combined revenues take account adoption consensus reached eitf issue 023 requires us report physical sales energy commodities energy trading activities net basis component revenues impact eitf issue 023 reported 2000 revenues reduction combined amounts 294 billion amounts also consider reclassification 276 million revenues related coal mining properties reclassified financial statements discontinued operations 2002 see notes 1 10 discussion matters divestitures 2002 2003 completed announced number asset sales order rationalize business address liquidity issues changing market conditions sales occurred business segments follows 1 recognize gains losses completed sales natural gas oil properties individually significantly alter relationship capitalized costs proved reserves time sold 2 proceeds 735 million consisted 539 million cash common units el paso energy partners fair value 6 million partnerships interest prince tension leg platform including nine percent overriding royalty interest prince production field combined fair value 190 million 3 proceeds sales 766 million consisted 416 million cash 350 million series c units new nonvoting class limited partnership interest el paso energy partners 4 2002 recorded impairment charges 185 million since carrying value higher estimated net sales proceeds properties presented financial statements discontinued operations see note 10 discussion 1 sales announced completed subject customary regulatory approvals conditions 2 anticipate recognizing gains losses sales natural gas oil properties individually significantly alter relationship capitalized costs proved reserves time sold 3 2002 recorded impairment charges 74 million resulting expected sale ownership interests 4 amount includes 25 million receivable 5 proceeds 59 million consisted 35 million cash 24 million notes receivable december 2002 reclassified several field services small gathering systems located wyoming merchant energys florida petroleum terminals tug barge operations assets held sale also classified petroleum asphalt operations lease crude business held sale total assets sold net book value property plant equipment approximately 134 million reclassified assets current assets december 31 2002 since plan sell next twelve months federal trade commission order result january 2001 merger coastal sold midwestern gas transmission system gulfstream pipeline project 50 percent interest stingray ut offshore pipeline systems investments empire state iroquois pipeline systems year ended december 31 2001 net proceeds sales approximately 279 million recognized extraordinary net gains approximately 26 million net income taxes approximately 27 million 2000 sold east tennessee natural gas company sea robin pipeline company onethird interest destin pipeline company comply ftc order related merger sonat net proceeds sales approximately 616 million recognized extraordinary gain 89 million net income taxes 59 million december 2000 sold interest oasis pipeline company comply ftc order incurred loss transaction approximately 19 million net income taxes 9 million recorded gains losses sales extraordinary items income statement february 2003 announced would exit noncore businesses including substantially petroleum business except aruba refinery since making announcement identifying potential buyers petroleum assets time cannot determine amount gain loss incurred continue evaluate whether assets treated accounting purposes assets held sale possibly discontinued operations 4 restructuring mergerrelated costs three years ended december 31 incurred restructuring costs mergerrelated costs asset impairment charges follows restructuring costs restructuring costs incurred connection organizational restructurings connection balance sheet liquidity enhancement actions taken 2002 segment charges follows december 2001 announced plan strengthen balance sheet reduce costs focus activities core natural gas businesses 2002 completed employee restructuring across operating segments resulted reduction approximately 772 fulltime positions terminations result actions incurred 41 million employee severance termination costs 30 million paid december 31 2002 also incurred paid fees 40 million eliminate stock price credit rating triggers related chaparral gemstone investments mergerrelated costs years ended 2001 2000 incurred mergerrelated costs connection merger coastal completed january 2001 follows employee severance retention transition costs include direct payments benefit costs severed employees early retirees occurred result mergerrelated workforce reduction consolidation following coastal merger completed employee restructuring across operating segments resulting reduction 3285 fulltime positions combination early retirements terminations employee severance costs include actual severance payments costs pension postretirement benefits settled curtailed existing benefit plans result restructurings retention charges include payments employees retained following mergers payments employees satisfy contractual obligations transition costs relate costs relocate employees costs severed retired employees arising severance date transition jobs ongoing workforce employee severance retention transition costs 2001 approximately 838 million included pension postretirement benefits 214 million accrued merger date paid applicable benefit periods terminated retired employees costs expensed incurred paid also included 2001 employee severance retention transition costs charge 278 million resulting issuance approximately 4 million shares common stock date coastal merger exchange fair value coastal employees directors stock options restricted stock total 339 employees 11 directors received shares transaction costs include investment banking legal accounting consulting advisory fees incurred obtain federal state regulatory approvals take actions necessary complete mergers items expensed periods incurred business operational integration costs include charges consolidate facilities operations business segments total charges 2001 383 million 153 million related charge resulting marktomarket loss energyrelated contract transportation capacity alliance pipeline prior merger contract managed coastals production segment following merger determined contract managed trading group consistently energyrelated pipeline capacity contracts result transferred merchant energy charge reflects estimated realizable value contract energyrelated trading contract integration costs also include incremental fees software seismic license agreements 15 million recorded production segment additional integration costs included approximately 222 million estimated leaserelated costs relocate pipeline operations detroit michigan houston texas el paso texas colorado springs colorado 13 million recorded impairment assets incurred pipelines corporate segments charges accrued time completed relocations closed offices amounts accrued paid term applicable noncancelable lease agreements costs expensed incurred costs include payments made satisfaction obligations arising ftc approval merger coastal miscellaneous charges part ftc order related merger coastal el paso energy partners lp required sell interests seven natural gas pipeline systems dehydration facility two offshore platforms proceeds sales assets approximately 135 million resulted loss partnership approximately 25 million consideration sales committed pay el paso energy partners series payments totaling 29 million required contribute 40 million trust related one assets sold el paso energy partners expensed items time committed pay 5 gain loss longlived assets gain loss longlived assets consist realized gains losses sales longlived assets impairments longlived assets years ended december 31 gains losses longlived assets follows realized gain loss realized gain loss sales longlived assets years ended december 31 2002 2001 2000 267 million 5 million 29 million 2002 gains primarily result asset sales enhance liquidity related sales san juan gathering assets natural buttes ouray gathering system dragon trail processing plant texas new mexico midstream assets field services segment see note 3 discussion divestitures 2001 losses related miscellaneous asset sales across segments 2000 gains related sales portion montreal paraxylene plant merchant energy segment nonregulated pipeline assets pipelines segment asset impairments years ended december 31 incurred asset impairment charges business segments follows impairment charges based reducing carrying value assets estimated fair value fair value determined combination estimating proceeds sale asset less anticipated selling costs intend sell asset discounted estimated cash flows asset based current anticipated future market conditions intend hold asset 6 accounting changes accounting principle year ended december 31 2002 recorded cumulative effects income changes accounting principles follows millions discussion accounting principles adopted 2002 see note 1 changes accounting estimate included operation maintenance costs year ended december 31 2001 approximately 316 million costs related changes accounting estimates consist 232 million additional environmental remediation liabilities 47 million additional accrued legal obligations 37 million charge reduce value spare parts inventories reflect changes usability parts worldwide operations change estimated environmental remediation liabilities due number events including 109 million resulting sale majority retail gas stations 31 million related closure gulf coast chemical midwest refining operations 10 million associated lease corpus christi refinery valero 82 million associated conforming coastals methods environmental identification assessment remediation strategies processes historical practices following merger coastal accounted remainder change estimated obligations change estimate legal obligations result review process assess legal exposures strategies plans following merger coastal finally charge related spare parts inventories primarily result several events occurred part following merger coastal including consolidation numerous operating locations sale majority retail gas stations shutdown midwest refining operations lease corpus christi refinery changes also direct result fire aruba refinery whereby portion plant rebuilt following fire rendering many parts unusable also impacting amounts evaluation operating standards strategies plans combined company following merger changes estimates included operating expenses income statement reduced net income extraordinary items net income year ended december 31 2001 approximately 215 million 7 ceiling test charges full cost method accounting natural gas oil properties perform quarterly ceiling tests evaluate whether carrying value natural gas oil properties exceeds present value future net revenues discounted 10 percent plus lower cost fair market value unproved properties net related income tax effects year ended december 31 2002 recorded ceiling test charges 269 million 33 million charged first quarter 234 million charged second quarter 2 million charged fourth quarter writedown includes 226 million canadian full cost pool 24 million turkish full cost pool 10 million brazilian full cost pool 9 million international production operations primarily australia charge canadian full cost pool primarily resulted low daily posted price natural gas june 30 2002 approximately 143 per mmbtu year ended december 31 2001 recorded ceiling test charges 135 million including 87 million canadian full cost pool 28 million brazilian full cost pool 20 million international production operations primarily turkey 2001 charges based daily posted natural gas oil prices november 1 2001 adjusted oilfield natural gas gathering hub wellhead price differences appropriate computed third quarter 2001 ceiling test charges based upon daily posted natural gas oil prices september 30 2001 would incurred ceiling test charge 275 million amount would included 227 million canadian full cost pool 48 million brazilian full cost pool international production operations primarily turkey use financial instruments hedge volatility natural gas oil prices impact hedges considered determining ceiling test charges factored future ceiling test calculations impact hedges included calculating third quarter 2001 ceiling test charges would incurred third quarter charge 576 million september 30 2001 relating domestic full cost pool charges international cost pools would materially changed since significantly hedge international production activities 8 income expenses following components income expenses three years ended december 31 1 impaired investment costanera power plant 2002 various telecommunication investments 2001 9 income taxes pretax income loss continuing operations extraordinary items cumulative effect accounting change composed following three years ended december 31 following table reflects components income tax expense benefit included income continuing operations extraordinary items cumulative effect accounting change three years ended december 31 tax expense benefit included income loss continuing operations extraordinary items cumulative effect accounting change differs amount computed applying statutory federal income tax rate 35 percent following reasons three years ended december 31 following components net deferred tax liability related continuing operations december 31 december 31 2002 portion cumulative undistributed earnings foreign subsidiaries foreign corporate joint ventures recorded us income taxes approximately 1309 million since earnings intended indefinitely reinvested foreign operations provision made us taxes foreign withholding taxes may applicable upon actual deemed repatriation distribution earnings made might subject foreign withholding taxes us income taxes net allowable foreign tax credits deductions however estimate taxes practicable reasons recorded provision us income taxes foreign currency translation adjustment recorded comprehensive income tax benefit associated exercise nonqualified stock options vesting restricted stock well restricted stock dividends reduced taxes payable 15 million 2002 31 million 2001 60 million 2000 benefits included additional paidin capital balance sheets december 31 2002 charitable contribution carryovers 27 million carryover periods end follows 1 million 2003 22 million 2004 4 million 2006 alternative minimum tax credits 281 million carryover indefinitely 2 million general business credit carryovers carryover periods end various times years 2009 2021 table presents details federal net operating loss carryover periods usage carryovers subject limitations provided sections 382 383 internal revenue code well separate return limitation year rules irs regulations december 31 2002 1129 million state net operating loss carryovers expire varying amounts period 2003 2021 also 73 million foreign net operating loss carryovers carryover indefinitely recorded valuation allowance reflect estimated amount deferred tax assets may realize due uncertain availability future taxable income expiration net operating loss tax credit carryovers december 31 2002 approximately 14 million valuation allowance relates foreign deferred tax assets ceiling test charges 22 million relates foreign net operating loss carryovers 1 million relates us federal general business credit carryovers december 31 2001 approximately 1 million valuation allowance relates us federal net operating loss carryovers acquired company 2 million relates us federal general business credit carryovers 10 discontinued operations june 2002 board directors authorized sale coal mining operations historically included merchant energy segment consist fifteen active underground two surface mines located kentucky virginia west virginia following authorization sale board directors compared carrying value underlying assets estimated sales proceeds net estimated selling costs based bids received sales process second third quarters 2002 carrying value higher estimated net sales proceeds recorded impairment charges 148 million second quarter 2002 37 million third quarter 2002 december 2002 sold substantially reserves properties west virginia kentucky affiliate natural resources partners lp 57 million cash january 2003 sold remaining coal operations consists mining operations businesses properties reserves kentucky west virginia subsidiaries alpha natural resources llc affiliate first reserve corporation 59 million includes 35 million cash 24 million notes receivable coal mining operations classified discontinued operations financial statements periods presented addition reclassified assets liabilities remaining coal mining operations december 31 2002 current assets liabilities summarized financial results discontinued operations three years ended december 31 follows 11 earnings per share calculated basic diluted earnings per share amounts follows three years ended december 31 1 due antidilutive effect earnings per share approximately 7 million shares related convertible debentures excluded 2001 dilutive shares approximately 8 million shares related trust preferred securities excluded 2001 2 due antidilutive effect earnings per share approximately 1 million shares related stock options approximately 8 million shares related convertible debentures approximately 8 million shares related trust preferred securities excluded 2002 12 financial instruments following carrying amounts estimated fair values financial instruments december 31 1 include 1055 million nonderivative contracts december 31 2001 including transportation capacity tolling agreements natural gas storage held trading purposes since constitute financial instruments december 31 2002 2001 carrying amounts cash equivalents shortterm borrowings trade receivables payables representative fair value shortterm nature instruments fair value longterm debt variable interest rates approximates carrying value marketbased nature debts interest rates estimated fair value debt fixed interest rates based quoted market prices similar issues estimated fair value derivative financial instruments based quoted market prices current market conditions estimates obtained thirdparty brokers dealers amounts derived using valuation models 13 price risk management activities following table summarizes carrying value trading nontrading price risk management assets liabilities december 31 1 trading contracts entered purposes generating profit benefiting movements market prices 2 net assets price risk management activities include current noncurrent assets current noncurrent liabilities price risk management activities balance sheet included derivatives december 31 2002 968 million derivative contracts related power restructuring activities consolidated subsidiaries amount 878 million relates power restructuring occurred first quarter 2002 eagle point cogeneration power plant 90 million relates power restructuring capitol district energy center cogeneration associates plant remaining balance derivatives unrealized loss 9 million relates derivative positions longer qualify cash flow hedges sfas 133 designated hedges anticipated future production natural gas oil properties sold 2002 trading activities contracts trading activities include services provide energy sector enter objective generating profits benefiting movements market prices primarily related purchase sale energy commodities fourth quarter 2002 announced intent exit trading activities pursue orderly liquidation trading price risk management activities 2004 derivative instruments use trading activities either traded active exchanges new york mercantile exchange valued using exchange prices third party pricing data valuation techniques incorporate specific contractual terms statistical simulation analysis present value concepts actions limit trading activities exit trading business accessibility reliable forward market data purposes estimating fair value significantly limited late 2002 result obtained valuation assistance third party valuation specialist determining fair value trading nontrading price risk management activities december 31 2002 based upon specialists input estimates fair value based upon price curves derived actual prices observed market pricing information supplied specialist independent pricing sources models rely forward pricing information estimates also reflect factors time value volatility underlying contracts potential impact liquidating position orderly manner reasonable time present market conditions modeling risk credit risk counterparties operational risks needed discontinued applying tenyear liquidity valuation allowance instituted first quarter 2002 circumstances uncertainty related forward prices less liquid markets extent forward market data received third party specialist indicates value beyond ten years include value fair value trading nontrading price risk management activities reflected trading portfolio estimated fair value amount contracts portfolio could bought sold current transaction willing buyers sellers however value ultimately receive settlement trading activities may less fair value estimates disclosed previously actively liquidating trading portfolio includes approximately 40000 transactions december 31 2002 believe net realizable value trading portfolio may less currently estimated fair value belief based recent transactions completed values estimated fair value bids received transactions also fair value additionally adoption eitf issue 023 portion transactions plan liquidate accounted accrual method recorded balance sheet pay counterparties assume transactions future losses result complete exit energy trading business continue serve diverse group customers require wide variety financial structures products terms diversity requires us manage portfolio basis resulting market risks inherent trading price risk management activities subject parameters established risk management committee monitor market risks risk control committee operating independently units create actively manage risk exposures ensure compliance stated risk management policies measure adjust risk accordance marktomarket risk management methodologies utilize forward price curves energy markets estimate size probability future potential exposure credit risk relates risk loss would incur result nonperformance counterparties pursuant terms contractual obligations maintain credit policies regard counterparties trading nontrading price risk management activities minimize overall credit risk policies require evaluation potential counterparties financial condition including credit rating collateral requirements certain circumstances including cash advance letters credit guarantees use standardized agreements allow netting positive negative exposures associated single counterparty following table presents summary counterparties net asset exposure trading nontrading price risk management activities 1investment grade investment grade primarily determined using publicly available credit ratings counterparty publicly rated minimum implied credit rating internal credit analysis investment grade includes counterparties minimum standard poors rating bbb moodys rating baa3 investment grade includes counterparties credit rating meet criteria investment grade 2as december 31 2002 required collateral encompasses margins standby letters credit 170 million 303 million 56 percent counterparties included investment grade 3net asset exposure price risk management activities prepared netting assets liabilities counterparties contractual right offset positions netted include current noncurrent amounts result amounts agree total assets price risk management activities balance sheet addition 2001 counterparty total include assets natural gas storage marketable securities held trading purposes 196 million tables one customer comprised greater 5 percent net asset exposure price risk management activities december 31 2002 2001 customer december 31 2002 public service electric gas company comprised approximately 41 percent net asset exposure price risk management activities counterparty considered investment grade company december 31 2002 concentration counterparties may impact overall exposure credit risk either positively negatively counterparties may similarly affected changes economic regulatory conditions nontrading activities derivatives designated hedges use derivative financial instruments hedge impact market price risk exposures assets liabilities contractual commitments forecasted transactions related natural gas oil production refining natural gas transmission power generation financing international business activities engage two types hedging activities hedges cash flow exposure hedges fair value exposure hedges cash flow exposure entered hedge forecasted transaction variability cash flows received paid related recognized asset liability hedges fair value exposure entered hedge fair value recognized asset liability firm commitment date enter derivative contract designate derivative either cash flow hedge fair value hedge changes derivative fair values designated cash flow hedges deferred extent effective recorded component accumulated comprehensive income hedged transactions occur recognized earnings ineffective portion cash flow hedges change value recognized immediately earnings component operating revenues income statement changes derivative fair values designated fair value hedges recognized earnings offsets changes fair values related hedged assets liabilities firm commitments required sfas 133 formally document relationships hedging instruments hedged items well risk management objectives strategies undertaking various hedge transactions methods assessing testing correlation hedge ineffectiveness hedging instruments linked hedged asset liability firm commitment forecasted transaction also assess inception hedge ongoing basis whether derivatives used hedging transactions highly effective offsetting changes cash flows fair values hedged items discontinue hedge accounting prospectively determine derivative longer highly effective hedge decide discontinue hedging relationship fair value hedging instruments reflects best estimate based exchange overthecounter quotations available quoted valuations may available due location differences terms extend beyond period quotations available quotes available utilize valuation techniques models estimate market values modeling techniques require us make estimations future prices price correlation market volatility liquidity actual results may differ estimates differences positive negative january 1 2001 adopted provisions sfas 133 recorded cumulativeeffect adjustment 1280 million net income taxes accumulated comprehensive income recognize fair value derivatives designated hedging instruments majority initial charge related hedging cash flows anticipated sales natural gas 2001 2002 year ended december 31 2001 1063 million net income taxes initial transition adjustment reclassified earnings result hedged sales purchases year discussion hedging activities follows fair value hedges crude oil refined products inventories change value daily due changes commodity markets use futures swaps protect value inventories years ended december 31 2002 2001 financial statement impact hedges fair value inventories immaterial cash flow hedges majority commodity sales purchases spot market forward market prices use futures forward contracts swaps limit exposure fluctuations commodity markets allow fixed cash flow stream activities december 31 2002 2001 value cash flow hedges included accumulated comprehensive income net unrealized loss 377 million net unrealized gain 256 million net income taxes estimate unrealized losses 124 million net income taxes reclassified accumulated comprehensive income 2003 reclassifications occur upon physical delivery hedge commodity corresponding expiration hedge maximum term cash flow hedges 10 years however cash flow hedges expire within next 24 months net liability price risk management activities 500 million december 31 2002 net asset price risk management activities 459 million december 31 2001 associated cash flow hedges net change 959 million 2002 resulted net settlements 222 million 2002 decrease fair value 737 million cash flow hedge positions 2002 accumulated comprehensive income december 31 2002 2001 also includes loss 65 million 23 million net income taxes representing proportionate share amounts recorded comprehensive income unconsolidated affiliates use derivatives cash flow hedges included loss 7 million loss estimate reclassified accumulated comprehensive income 2003 maximum term cash flow hedges two years excluding hedges related interest rates variable debt years ended december 31 2002 2001 recognized net loss 15 million net gain 3 million net income taxes related ineffective portion cash flow hedges may 2002 announced plan reduce volumes natural gas hedged production segment removed hedging designation derivatives fair value loss 105 million december 31 2002 amount net income taxes 38 million reflected accumulated comprehensive income reclassified income original hedged transactions settled 2004 net loss 67 million accumulated comprehensive income estimate unrealized losses 42 million net income taxes related derivatives reclassified income next twelve months foreign currency hedges international activities fixed rate foreign currency denominated debt exposes us changes exchange rates foreign currency us dollar 2002 2001 used currency swaps effectively convert fixed amounts foreign currency due foreign currency denominated debt us dollar amounts december 2002 decided reduce volumes foreign currency exchange risk hedged debt removed hedging designation derivatives net fair value loss 1 million december 31 2002 amount 14 million loss net income taxes 5 million reflected accumulated comprehensive income 8 million gain reflected unamortized discount longterm debt amounts reclassified income interest principal debt settled 2009 net loss 9 million included accumulated comprehensive income 8 million deferred gain included longterm debt estimate unrealized losses 1 million unrealized gains 2 million related derivatives reclassified income next twelve months nontrading activities power restructuring activities merchant energy segments power restructuring activities involved amending terminating power plants existing power purchase contract eliminate requirement plant provide power generation regulated utility replacing requirement ability provide power utility wholesale power market conjunction power restructuring activities generally entered new marketbased contracts third parties provide power utility wholesale power market effectively locks margin restructuring transaction difference contracted rate restructured contract wholesale market rates time prior restructuring power plant related power purchase contract generally accounted historical cost either cost construction acquired acquisition cost revenues expenses prior restructuring cases accounted accrual basis power generated sold utility following restructuring accounting treatment power purchase agreement must change restructured contract meets definition derivative therefore required marked fair value sfas 133 addition since power plant longer exclusive right provide power original dedicated power purchase contract operates peaking merchant plant generating power economical significant change use fair value plant may less historical value changes may also require us terminate amend related fuel supply steam agreements enter third party intercompany contracts transportation agreements associated operations facility power restructuring activities following effects financial statements restructured contract meets definition derivative shown asset price risk management activities balance sheet difference fair value restructured contract carrying value original contract shown operating revenues income statement subsequent changes fair value also recorded operating revenues new third party wholesale power supply contracts recorded fair value assets liabilities price risk management activities balance sheet subsequent changes fair value also recorded operating revenues carrying value underlying power plant related intangible assets evaluated impairment required written fair value merchant power plant recorded operating expenses income statement contract termination fees closing costs also recorded operating expenses income statement purchase power wholesale power supply contracts record cost power purchase operating expenses income statement sell power utility restructured contract record amounts received contract operating revenues classify restructured contracts nontrading price risk management activities disclosures classify third party contracts trading price risk management activities actively managed trading operations historically conducted majority power restructuring activities unconsolidated affiliate chaparral therefore share revenues expenses activities recognized earnings unconsolidated affiliates 2002 completed power restructuring eagle point cogeneration facility consolidate applied accounting described transaction power restructuring activities also involve contract terminations result cash payment utility cancel underlying power contract mount carmel transaction also employed principles power restructuring business reaching settlement 2002 dispute nejapa power contract included cash payment us recorded payments operating revenues year ended december 31 2002 consolidated power restructuring activities following effects consolidated financial statements millions fair value derivatives related power restructuring activities determined based expected cash receipts payments contracts using future power prices compared contractual prices contracts discount cash flows interest rate commensurate term contract credit risk contracts counterparty make adjustments discount rate believe market changes rates result changes fair values realized future power prices based forward pricing curve appropriate power delivery receipt points applicable power market forward pricing curve derived available market data pricing information supplied third party timing cash receipts payments based expected timing power delivered contracts fair value derivatives may change period based changes actual projected market prices fluctuations credit ratings counterparties significant changes interest rates changes assumed timing deliveries result credit downgrades decision exit energy trading business disruptions capital markets unlikely pursue additional power restructurings near term 14 inventory consisted following december 31 effective october 1 2002 adopted provisions eitf issue 023 eitf issue 023 requires among things account inventory used trading activities lower cost fair value rather using marktomarket accounting previously allowed eitf issue 9810 effective october 1 2002 adjusted fair value inventories balance sheet historical cost using weighted average cost methodology reclassified amounts price risk management activities inventory natural gas storage see note 1 discussion impact eitf 023 15 regulatory assets liabilities regulatory assets included current noncurrent regulatory assets regulatory liabilities included current noncurrent regulatory liabilities balances presented balance sheets gross basis details regulatory assets liabilities represent regulated interstate systems apply provisions sfas 71 december 31 1 amounts included rate base earn current return 2 amounts recovered remaining depreciable lives property plant equipment 3 amount recovered future rate proceeding 16 assets liabilities detail current noncurrent assets liabilities balance sheets december 31 17 property plant equipment december 31 2002 2001 approximately 1865 million 2330 million construction work progress included property plant equipment june 2001 entered 20year lease agreement related corpus christi refinery related assets valero lease valero pays us quarterly amount increases second year lease years ended december 31 2002 2001 recorded 19 million 11 million lease income related lease february 2003 valero exercised option purchase plant related assets 289 million cash recorded gain 8 million december 31 2002 tgp epng anr excess purchase costs associated acquisition total excess costs pipelines approximately 5 billion accumulated depreciation approximately 1 billion excess costs amortized life related pipeline assets amortization expense 2002 approximately 71 million adoption sfas 142 impact amounts since included part property plant equipment rather goodwill recorded result acquisitions anr cig goodwill 723 million december 31 2002 310 million accumulated amortization conjunction adoption sfas 142 january 1 2002 ceased amortization goodwill performed required impairment tests goodwill impairment goodwill indicated january 1 2002 december 31 2002 18 debt financing obligations credit facilities december 31 2002 weighted average interest rate commercial paper shortterm credit facilities 269 december 31 2001 32 following shortterm borrowings financing obligations december 31 credit facilities historically used commercial paper programs manage shortterm cash requirements programs borrow 3 billion combination individual corporate tgp epng commercial paper programs 1 billion however result credit downgrade currently issuing commercial paper meet liquidity needs may 2002 renewed existing 364day 3 billion revolving credit competitive advance facility epng tgp also designated borrowers new facility jointly severally liable amounts outstanding facility matures may 2003 provides amounts outstanding date due may 2004 also maintain 3year 1 billion revolving credit competitive advance facility conduct shortterm borrowings commercial credit transactions june 2002 amended facility permit us issue 500 million letters credit adjust pricing terms facility matures august 2003 el paso cgp formerly coastal epng tgp subsidiaries designated borrowers facility jointly severally liable amounts outstanding interest rate facilities varies based senior unsecured debt rating december 31 2002 borrowings facilities rate libor plus 100 plus 025 utilization fee december 31 2002 15 billion outstanding 3 billion facility issued approximately 456 million letters credit 1 billion facility february 2003 borrowed 500 million 1 billion facility availability borrowings credit borrowing agreements subject specified conditions currently meet conditions include compliance financial covenants ratios required agreements absence default agreements continued accuracy representations warranties contained agreements restrictive covenants subsidiaries entered debt instruments guaranty agreements contain covenants restrictions debt levels restrictions liens securing debt guarantees restrictions mergers sales assets capitalization requirements dividend restrictions crosspayment default crossacceleration provisions breach covenants could result acceleration debt financial obligations subsidiaries revolving credit facilities significant debt covenants cross defaults ratio consolidated debt guarantees capitalization excluding certain project financing securitization programs miscellaneous items defined agreement cannot exceed 70 percent b consolidated debt guarantees excluded items subsidiaries cannot exceed greater 600 million 10 percent consolidated net worth c principal subsidiaries cannot permit liens equity interest principal subsidiaries create liens assets material consolidated operations securing debt guarantees excluded items exceeding greater 300 million 10 percent consolidated net worth subject certain permitted exceptions occurrence event default nonpayment principal interest premium respect debt excluded items aggregate principal amount 200 million occurrence event default respect debt results acceleration thereof compliance covenants date filing including ratio debt capitalization defined agreements 632 percent year end december 31 2002 15 billion outstanding 3 billion facility issued approximately 456 million letters credit 1 billion facility february 2003 borrowed 500 million 1 billion facility also issued various guarantees securing financial obligations subsidiaries unconsolidated affiliates similar covenants credit facilities respect guarantees issued subsidiaries significant debt covenant addition covenants discussed el paso cgp must maintain minimum net worth 12 billion breached amounts guaranteed guaranty agreements could accelerated guaranty agreements also 30 million crossacceleration provision el paso cgps net worth december 31 2002 43 billion addition three subsidiaries indentures associated public debt contain 5 million crossacceleration provisions longterm debt financing obligations outstanding consisted following december 31 1 company holding notes merged el paso corporation 2002 2 collateralized lease payments valero lease corpus christi refinery valero loan repaid february 2003 3 secured agreement deliver fixed quantity crude oil specified delivery point future december 31 2002 crude oil prepayment obligations paid aggregate maturities principal amounts longterm debt financing obligations next 5 years total thereafter follows millions zero coupon convertible debentures maturity value 18 billion due 2021 yield maturity 4 holders cause us repurchase option years 2006 2011 2016 time elect settle cash common stock debentures convertible 8456589 shares common stock based conversion rate 47872 shares per 1000 principal amount maturity rate equal conversion price 94604 per share common stock june 2002 issued 518 million shares common stock public offering price 1995 per share net proceeds offering approximately 1 billion june 2002 issued 115 million 9 equity security units equity security units consist two securities purchase contract pay quarterly contract adjustment payments annual rate 286 requires holder buy common stock settled august 16 2005 ii senior note due august 16 2007 principal amount 50 per unit pay quarterly interest payments annual rate 614 beginning august 16 2002 senior notes issued total principal value 575 million pledged secure holders obligation purchase shares common stock purchase contracts purchase contracts settled 2005 issue common stock time proceeds allocated common stock additional paidin capital number common shares issued depend prior consecutive 20trading day average closing price common stock determined third trading day immediately prior stock purchase date issue minimum approximately 24 million shares maximum 288 million shares settlement date depending average stock price recorded approximately 43 million noncurrent liabilities reflect present value quarterly contract adjustment payments required make units annual rate 286 stated amount 50 per purchase contract offsetting reduction additional paidin capital quarterly contract adjustment payments allocated liability recognized date issuance additional paidin capital based constant rate term purchase contracts fees expenses incurred connection equity security units offering allocated senior notes purchase contracts based respective fair values issuance date amount allocated senior notes recognized interest expense term senior notes amount allocated purchase contracts recorded additional paidin capital july 2002 utility contract funding issued 829 million 7944 senior secured notes due 2016 financing nonrecourse el paso companies independently supported cash flows contracts utility contract funding including obligations public service electric gas restructured power contract morgan stanley power supply agreement connection credit enhancement provided morgan stanleys participation paid 36 million consideration entering supply agreement july 2002 entered two crosscurrency swap transactions effectively hedged e400 million euro currency risk e500 million eurodenominated debt first transaction e250 million 7125 fixed rate swapped 2525 million floating rate debt rate sixmonth libor plus spread 2195 second transaction swapped e150 million 7125 fixed rate euro based debt 1515 million 708 fixed dollar based debt december 2002 terminated crosscurrency swap transactions effectively hedged e675 million euro currency risk e275 million exposure remains hedged effective rate 659 maturity 2006 august 2002 issued 12184444 shares common stock satisfy purchase contract obligations feline pridessm program return issuance stock received approximately 25 million cash maturity zero coupon bond return 435 million existing 6625 senior debentures due august 2004 issued 1999 zero coupon bond senior debentures held collateral purchase contract obligations 25 million received maturity zero coupon bond used retire additional senior debentures total debt reduction issuance common stock approximately 460 million january 2003 retired various debt obligations approximately 47 million february 2003 el paso cgp retired 240 million 307 longterm debt related valero lease march 2003 subsidiaries southern natural gas anr pipeline issued senior notes concurrent offerings totaling 700 million southern natural gas company issued 400 million 8 78 senior unsecured notes due 2010 raising net proceeds 385 million proceeds offering used part repay intercompany obligations 290 million southern natural gas retained 95 million net proceeds fund future capital expenditures anr pipeline company issued 300 million 8 78 senior unsecured notes due 2010 raising net proceeds 288 million anr used 263 million cash proceeds offering reduce existing intercompany payables anr also retained 25 million fund future capital expenditures march 2003 closed 12 billion twoyear term loan used proceeds retire approximately 913 million net balance trinity river financing trinity river also known red river formed 1999 invest capital projects assets new 12 billion loan scheduled payments 300 million june 2004 300 million september 2004 600 million balance march 2005 loan facility collateralized direct pledge natural gas oil properties previously trinity river financing loan facility carries floating interest rate libor plus 425 floating interest rate based libor rate less 350 additionally loan facility requires us pay facility fee equal 2 per annum average daily aggregate outstanding principal amount loan natural gas oil properties collateralize financing agreement reserves approximately 23 tcfe available capacity shelf registration statements april 2001 filed shelf registration statement securities exchange commission sec sell time total 3 billion debt securities preferred common stock medium term notes trust securities december 31 2001 approximately 920 million remaining shelf registration statement issued additional securities january 2002 fully utilizing remaining capacity february 2002 filed new shelf registration statement sec allows us issue 3 billion securities registration statement issue combination debt equity instruments including trust preferred securities two wholly owned trusts el paso capital trust ii el paso capital trust iii issue securities trusts required issue full unconditional guarantees securities december 31 2002 818 million remaining capacity shelf registration statement december 31 2002 tgp sng available capacity shelf registration statements file sec 19 preferred interests consolidated subsidiaries past entered financing transactions accomplished sale preferred interests consolidated subsidiaries total amounts outstanding programs december 31 2002 2001 follows millions 1 consolidated trusts composed capital trust coastal finance capital trust iv november 2002 repurchased preferred securities capital trust iv 300 million plus accrued unpaid dividends 2 preferred interest redeemed march 2003 proceeds 12 billion debt facility scheduled maturities 300 million june 2004 300 million september 2004 600 million march 2005 capital trust march 1998 formed el paso energy capital trust wholly owned subsidiary issued 65 million 4 34 trust convertible preferred securities 325 million common securities trust exists sole purpose issuing preferred securities investing proceeds 4 34 convertible subordinated debentures issued due 2028 sole asset trust sole source income interest earned debentures interest income used pay obligations trust preferred securities provide full unconditional guarantee trust preferred securities distributions paid preferred securities included return preferred interests consolidated subsidiaries income statement trust preferred securities nonvoting except limited circumstances pay quarterly distributions annual rate 4 34 carry liquidation value 50 per security plus accrued unpaid distributions convertible common shares time prior close business march 31 2028 option holder rate 12022 common shares trust preferred security equivalent conversion price 4159 per common share december 31 2002 approximately 65 million trust preferred securities outstanding coastal finance coastal finance indirect wholly owned business trust formed may 1998 coastal finance completed public offering 12 million mandatory redemption preferred securities 300 million coastal finance holds subordinated debt securities issued wholly owned subsidiary el paso cgp purchased proceeds preferred securities offering cumulative quarterly distributions paid preferred securities annual rate 8375 liquidation amount 25 per preferred security coastal finance source income interest earned subordinated debt securities interest income used pay obligations coastal finance preferred securities preferred securities mandatorily redeemable maturity date may 13 2038 may redeemed option may 13 2003 earlier various events occur redemption price paid 25 per preferred security plus accrued unpaid distributions date redemption el paso cgp provides guarantee payment obligations coastal finance related preferred securities extent coastal finance funds available el paso obligation provide funds coastal finance payment redemption preferred securities outside obligation pay interest principal subordinated debt securities capital trust iv may 2000 formed el paso energy capital trust iv wholly owned subsidiary issued 300 million preferred securities affiliate banc america preferred securities paid cash distributions floating rate equal threemonth libor plus 75 basis points december 31 2001 floating rate 283 november 2002 purchased preferred securities trust iv 300 million plus accrued unpaid dividends terminated obligations issue equity securities agreement trinity river also known red river 1999 formed series companies refer trinity river trinity river subsidiary formed provide financing invest various capital projects assets red river investors llc entity owned three investors west lb stonehurst ambac raised funds consortium banks contributed cash 980 million trinity river 1999 exchange preferred securities red river investors entitled adjustable preferred return derived trinity rivers net income preferred interest limited voting rights collateralized combination notes payable us various el paso entities including mojave pipeline company bear creek storage company various natural gas oil properties 575 million el paso energy partners common units assets liabilities operations trinity river included financial statements account investors preferred interest consolidated subsidiary preferred interests consolidated subsidiaries balance sheet preferred return preferred securities subsidiary income statement result el pasos subsidiaries credit rating downgrades moodys standard poors restrictions resulted use excess cash generated operating businesses purposes operating needs redeem preferred interests trinity river first quarter 2003 redeemed preferred interests trinity river eliminating cash restrictions clydesdale also known mustang 2000 formed series companies refer clydesdale subsidiary formed provide financing invest various capital projects assets mustang investors llc entity owned two investors west lb ambac raised funds consortium banks contributed cash 1 billion clydesdale exchange preferred securities mustang entitled adjustable preferred return derived clydesdales net income preferred interest limited voting rights collateralized combination notes payable us production payment us various natural gas oil properties various companies including ownership colorado interstate gas company option acquire mustang investors interest clydesdale time prior june 2006 exercise option agreement extended could required liquidate assets supporting transaction assets liabilities operations clydesdale included financial statements account investors preferred interest consolidated subsidiary preferred interests consolidated subsidiaries balance sheet preferred return preferred stock consolidated subsidiaries income statement july 2002 completed amendments clydesdale agreements remove rating trigger could required us liquidate assets supporting transaction event downgraded investment grade standard poors moodys result el pasos subsidiaries credit rating downgrades moodys standard poors restrictions resulted use excess cash generated assets purpose operating needs redeem preferred interests clydesdale portion funds used redeem preferred interests clydesdale including 50 million december 31 2002 additional 189 million february march 2003 payments reflected reductions preferred interests consolidated subsidiaries quarterly payments made reduce minority interests el paso tennessee preferred stock 1996 el paso tennessee pipeline co subsidiary issued 6 million shares publicly registered 825 cumulative preferred stock par value 50 per share 300 million preferred stock redeemable option el paso tennessee redemption price equal 50 per share plus accrued unpaid dividends time january 2002 three years ended december 31 2002 dividends approximately 25 million paid year preferred stock coastal securities company preferred stock 1996 coastal securities company limited wholly owned subsidiary issued 4 million shares preferred stock 100 million cannon investors trust entity comprised consortium banks quarterly cash dividends paid preferred stock rate based libor plus margin 211 based longterm unsecured debt rating subsidiary el paso cgp holders preferred securities right reset dividend rate december 20 2003 every seven years thereafter new rate acceptable preferred holders right require us redeem preferred securities preferred holders also entitled participating dividends based refining margins aruba refinery coastal securities may redeem preferred stock cash liquidation price 100 million plus accrued unpaid dividends el paso oil gas resources preferred units 1999 el paso oil gas resources company lp formerly coastal oil gas resources inc wholly owned subsidiary issued 50000 units preferred units 50 million uagc inc subsidiary rabobank international preferred shareholders entitled quarterly cash dividends rate based libor july 2002 repurchased entire 50000 units 50 million plus accrued unpaid dividends coastal limited ventures preferred stock 1999 coastal limited ventures inc wholly owned subsidiary issued 150000 shares preferred stock 15 million jp morgan chase bank formerly chase manhattan bank preferred shareholders entitled quarterly cash dividends annual rate 6 july 2002 repurchased entire 150000 shares 15 million plus accrued unpaid dividends gemstone part gemstone transaction wholly owned subsidiary topaz issued minority member interest gemstone investor entity indirectly owned rabobank 300 million gemstone investor entitled cumulative preferred return 803 interest agreements underlying transaction expire 2004 earlier sell international power assets owned indirectly topaz gemstone investors preferred interest redeemable liquidation value plus accrued unpaid dividends january 2003 notified rabobank exercising right partnership agreements purchase rabobanks 50 million equity gemstone unless find new partner consolidate gemstone upon purchase rabobanks third party equity gemstone time consolidate minority member interest topaz consolidated partnership december 1999 coastal limited ventures contributed assets limited partnership exchange controlling general partnership interest limited interests partnership issued rbcc unaffiliated investor 285 million limited partners entitled cumulative priority return based libor july 2002 repurchased limited partnership interest el paso production oil gas associates lp formerly known coastal oil gas associates partnership formed coastal limited ventures inc payment approximately 285 million unaffiliated investor equal sum limited partners outstanding capital plus unpaid priority returns el paso energy capital trust coastal finance el paso energy capital trust iv coastal securities company limited trinity river clydesdale topaz el paso tennessee pipeline co either business trusts control companies voting stock consequently entities consolidated financial statements however entities issued preferred securities preferred interests held various unaffiliated investors presented balance sheet preferred interests consolidated subsidiaries preferred distributions paid preferred interests presented income statement return preferred interests consolidated subsidiaries accounting preferred interests consolidated subsidiaries impacted adoption new accounting rules consolidations july 2003 discussion accounting impact see note 1 new accounting pronouncements issued yet adopted 20 commitments contingencies legal proceedings western energy settlement march 20 2003 entered agreement principle western energy settlement various public private claimants including states california washington oregon nevada resolve principal litigation claims regulatory proceedings fully described us subsidiaries relating sale delivery natural gas electricity september 1996 date western energy settlement western energy settlement resulted aftertax charge approximately 650 million fourth quarter 2002 among things components settlement include cash payment 100 million 2 million cash payment officer bonus pool issuance approximately 264 million shares el paso common stock delivery california border 45 million worth natural gas annually 20 years beginning 2004 reduction pricing longterm power supply contracts california department water resources 125 million remaining term contracts run end 2005 payments 22 million per year 20 years period five years epng make available california delivery points 3290 mmcf per day capacity primary delivery point basis period five years affiliates subject restrictions subscribing new capacity epng system admission wrongdoing agreement principle subject negotiation formal settlement agreement portions filed courts ferc approval upon approval parties release us covered claims may us subsidiaries period covered western energy settlement litigation claims regulatory proceedings us subsidiaries dismissed prejudice california lawsuits several subsidiaries named defendants fifteen purported class action municipal individual lawsuits filed california state courts suits contend entities acted improperly limit construction new pipeline capacity california andor manipulate price natural gas sold california marketplace specifically plaintiffs argue conduct violates californias antitrust statute cartwright act constitutes unfair unlawful business practices prohibited california statutes amounts violation californias common law restrictions monopolization general plaintiffs seeking declaratory injunctive relief regarding allegedly anticompetitive actions ii restitution including treble damages iii disgorgement profits iv prejudgment postjudgment interest v costs prosecuting actions vi attorneys fees fifteen cases consolidated single judge two omnibus complaints one set trial september 2003 class action municipal lawsuits one individual lawsuits resolved upon finalization approval western energy settlement november 2002 lawsuit titled gus bustamante v mcgrawhill companies filed superior court california county los angeles several individuals including lt governor bustamante acting private citizen numerous defendants including subsidiary epng alleging creation artificially high natural gas index prices via reporting false price volume information purported class action behalf california consumers alleges various unfair business practices seeks restitution disgorgement profits compensatory punitive damages civil fines lawsuit resolved upon finalization approval western energy settlement september 2001 received civil document subpoena california attorney general seeking information said relevant departments ongoing investigation high electricity prices california cooperated responding attorney generals discovery requests proceeding resolved upon finalization approval western energy settlement may 2002 two lawsuits challenging validity longterm power contracts entered california department water resources early 2001 filed california state court 26 separate companies including subsidiary el paso merchant energy lp epme merchant energy general plaintiffs allege unfair business practices seek restitution damages injunction enforcement contract provisions cases removed federal court costs legal exposure related lawsuits claims currently determinable january 2003 lawsuit titled imc chemicals v epme et al filed california state court us epng epme suit arises gas supply contract imc chemicals imcc epme seeks void gas purchase agreement imcc epme gas purchases december 2003 imcc contends epme affiliates manipulated market prices natural gas part manipulation induced imcc enter contract furtherance attempt void contract imcc repeats allegations claims california lawsuits described epme intends enforce terms contract counterclaim contract damages costs legal exposure related lawsuit currently determinable energy market lawsuits state nevada two individuals filed class action lawsuit nevada state court naming us number subsidiaries affiliates defendants allegations similar california cases suit seeks monetary damages relief nevada antitrust consumer protection laws lawsuit resolved upon finalization approval western energy settlement december 2002 two class action complaints filed one state court oregon federal court state washington naming el paso forty unrelated industry entities case complaint makes general allegations purchasers natural gas andor electricity within respective state overcharged period 2000 2002 defendants allegedly withheld supplies energy exercised improper control energy market manipulated prices lawsuits allege violation state statutes prohibiting unlawful trade practices fraud negligence relief sought includes injunctive relief unspecified damages attorneys fees washington complaint also seeks treble damages costs legal exposure related lawsuits claims currently determinable purported class action suit filed federal court new york city december 2002 alleging el paso epme epng defendants manipulated californias natural gas market manipulating spot market gas traded nymex yet served complaint costs legal exposure related lawsuit currently determinable march 2003 state arizona sued us epng epme unrelated entities behalf arizona consumers suit alleges defendants conspired artificially inflate prices natural gas electricity 2000 2001 making factual allegations similar alleged california cases suit seeks relief similar california cases well arizona antitrust consumer fraud statutes costs legal exposure related lawsuit currently determinable shareholder class action suits beginning july 2002 twelve purported shareholder class action suits alleging violations federal securities laws filed us several officers eleven suits consolidated federal court houston single judge suits generally challenge accuracy completeness press releases public statements made 2001 2002 twelfth shareholder class action lawsuit filed federal court new york city october 2002 challenging accuracy completeness february 27 2002 prospectus equity offering completed june 21 2002 since dismissed light similar claims asserted consolidated suits houston four shareholder derivative actions also filed one shareholder derivative lawsuit filed federal court houston august 2002 derivative action generally alleges claims made shareholder class action consolidated shareholder class actions pending houston stayed second shareholder derivative lawsuit filed delaware state court october 2002 generally alleges claims made consolidated shareholder class action lawsuit third shareholder derivative suit filed state court houston march 2002 fourth shareholder derivative suit filed state court houston november 2002 third fourth shareholder derivative suits generally allege manipulation california gas supply gas prices exposed el paso claims antitrust conspiracy ferc penalties erosion share value costs legal exposure related lawsuits claims currently determinable erisa class action suit december 2002 purported class action lawsuit filed federal court houston alleging generally direct indirect communications participants el paso corporation retirement savings plan included misrepresentations omissions caused members class hold maintain investments el paso stock violation employee retirement income security act erisa costs legal exposure related lawsuit currently determinable carlsbad august 2000 main transmission line owned operated epng ruptured crossing pecos river near carlsbad new mexico twelve individuals site fatally injured june 20 2001 us department transportations office pipeline safety issued notice probable violation proposed civil penalty epng notice alleged five violations dot regulations proposed fines totaling 25 million proposed corrective actions epng fully accrued fines alleged five probable violations regulations department transportations office pipeline safety 1 failure develop adequate internal corrosion control program associated proposed fine 500000 2 failure investigate minimize internal corrosion associated proposed fine 1000000 3 failure conduct continuing surveillance pipelines consider respond appropriately unusual operating maintenance conditions associated proposed fine 500000 4 failure follow company procedures relating investigating pipeline failures thereby minimize chance recurrence associated proposed fine 500000 5 failure maintain elevation profile drawings associated proposed fine 25000 october 2001 epng filed response office pipeline safety disputing alleged violations february 11 2003 national transportation safety board conducted public meeting investigation carlsbad rupture ntsb adopted findings conclusions recommendations based upon investigation synopsis safety boards report ntsb stated determined probable cause august 19 2000 rupture significant reduction pipe wall thickness due severe internal corrosion occurred epngs corrosion control program failed prevent detect control internal corrosion pipeline ntsb also determined ineffective federal preaccident inspections contributed accident identifying deficiencies epngs internal corrosion control program ntsbs final report pending november 1 2002 epng received federal grand jury subpoena documents related carlsbad rupture epng cooperating grand jury number personal injury wrongful death lawsuits filed epng connection rupture one suits settled settlement payments fully covered insurance remaining case geneva smith et al vs epec epng filed october 23 2000 harris county texas connection settlement cases epng contributed 10 million charitable foundation memorial families involved contribution covered insurance parties five settled lawsuits since filed additional lawsuit titled diane heady et al v epec epng harris county texas november 20 2002 seeking additional 180 million based upon interpretation earlier settlement agreements addition plaintiffs counsel settled new mexico state court cases notified epng intend file suit behalf twentythree firemen ems personnel responded fire allegedly suffered psychological trauma served lawsuit costs legal exposure related lawsuits claims currently determinable however believe matters fully covered insurance grynberg 1997 number subsidiaries named defendants actions brought jack grynberg behalf us government false claims act generally complaints allege industrywide conspiracy underreport heating value well volumes natural gas produced federal native american lands deprived us government royalties plaintiff case seeks royalties contends government received volume heating value natural gas produced royalty properties differently measured analyzed calculated reported together interest treble damages civil penalties expenses future injunctive relief require defendants adopt allegedly appropriate gas measurement practices monetary relief specified case matters consolidated pretrial purposes natural gas royalties qui tam litigation us district court district wyoming filed june 1997 may 2001 court denied defendants motions dismiss discovery proceeding costs legal exposure related lawsuits claims currently determinable price formerly quinque number subsidiaries named defendants quinque operating company et al v gas pipelines predecessors et al filed 1999 district court stevens county kansas quinque dropped plaintiff price added class action complaint alleges defendants mismeasured natural gas volumes heating content natural gas nonfederal nonnative american lands plaintiff case seeks certification nationwide class natural gas working interest owners natural gas royalty owners recover royalties plaintiff contends owners received volume heating value natural gas produced properties differently measured analyzed calculated reported together prejudgment postjudgment interest punitive damages treble damages attorneys fees costs expenses future injunctive relief require defendants adopt allegedly appropriate gas measurement practices monetary relief specified case plaintiffs motion class certification argued awaiting ruling costs legal exposure related lawsuit currently determinable mtbe compliance 1990 amendments clean air act use gasoline additive methyl tertiarybutyl ether mtbe gasoline also produce buy sell distribute mtbe number lawsuits filed throughout us regarding mtbes potential impact water supplies currently one several defendants one lawsuit new york plaintiffs seek remediation groundwater prevention future contamination compensatory damages costs replacement water diminished property values well punitive damages attorneys fees court costs cases future medical monitoring costs legal exposure related lawsuit claims currently determinable addition matters subsidiaries affiliates named defendants numerous lawsuits governmental proceedings arise ordinary course business outstanding legal matters evaluate merits case exposure matter possible legal settlement strategies likelihood unfavorable outcome determine unfavorable outcome probable estimated establish necessary accruals december 31 2002 approximately 1040 million accrued outstanding legal matters environmental matters subject federal state local laws regulations governing environmental quality pollution control laws regulations require us remove remedy effect environment disposal release specified substances current former operating sites december 31 2002 accrued approximately 482 million including approximately 463 million expected remediation costs current former operated sites associated onsite offsite groundwater technical studies approximately 19 million related environmental legal costs anticipate incurring 2027 approximately 15 million accrual related discontinued coal mining operations reconciliation accrued liability december 31 2001 accrued liability december 31 2002 addition expect make capital expenditures environmental matters approximately 305 million aggregate years 2003 2007 expenditures primarily relate compliance clean air regulations 2003 estimate total remediation expenditures approximately 87 million 3 million estimate capital related expenditures addition approximately 64 million amount expended government directed cleanup plans remaining 20 million selfdirected connection facility closures internal pcb remediation project since 1988 tgp subsidiary engaged internal project identify address presence polychlorinated biphenyls pcbs substances including environmental protection agencys epa list hazardous substances compressor stations facilities operates conducting project tgp frequent contact federal state regulatory agencies informal negotiation formal entry consent orders ensure efforts meet regulatory requirements tgp executed consent order 1994 epa governing remediation relevant compressor stations working epa relevant states regarding remediation activities tgp also working pennsylvania new york environmental agencies regarding remediation postremediation activities pennsylvania new york stations kentucky pcb project november 1988 kentucky environmental agency filed complaint kentucky state court alleging tgp discharged pollutants waters state disposed pcbs without permit agency sought injunction future discharges order remediate remove pcbs civil penalty tgp entered agreed orders agency resolve many issues raised complaint relevant kentucky compressor stations remediated 1994 consent order epa despite tgps remediation efforts agency may raise additional technical issues seek additional remediation work future pcb cost recoveries may 1995 following negotiations customers tgp filed agreement ferc established mechanism recovering substantial portion environmental costs identified internal remediation project agreement approved ferc november 1995 provided pcb surcharge firm interruptible customers rates pay eligible costs pcb remediation project surcharges collected defined collection period tgp twice received approval ferc extend collection period currently set expire june 2004 agreement also provided biannual audits eligible costs december 31 2002 tgp precollected pcb costs approximately 115 million precollection reduced future eligible costs incurred remainder remediation project tgp required extent actual expenditures less amounts precollected refund customers unused precollection amount plus carrying charges incurred date refunds december 31 2002 tgp recorded regulatory liability included noncurrent liabilities balance sheet future refund obligations approximately 55 million coastal eagle point may 1999 march 2001 coastal eagle point oil company received several administrative orders notices civil administrative penalty assessment new jersey department environmental protection dep assessments related alleged noncompliance new jersey air pollution control act pertaining excess emissions first quarter 1998 fourth quarter 2000 reported eagle point refinery westville new jersey dep assessed penalties totaling approximately 13 million alleged violations dep indicated willingness accept reduced penalty supplemental environmental project eagle point refinery granted administrative hearing issues raised assessments global refinery enforcement initiative environmental protection agency epa referred several clean air act issues dep eagle point refinery expects resolve issues along dep assessments february 24 2003 epa region 2 issued compliance order based 1999 epa inspection refinerys leak detection repair program alleged violations include failure monitor components failure timely repair leaking components august 2000 followup inspection epa confirmed eagle point refinery improved implementation program compliance order requires documentation compliance program eagle point refinery requested conference epa discuss order alleged violations epa may seek monetary penalty cercla matters received notice could designated asked information determine whether could designated potentially responsible party prp respect 58 active sites comprehensive environmental response compensation liability act cercla state equivalents sought resolve liability prp sites indemnification third parties settlements provide payment allocable share remediation costs december 31 2002 estimated share remediation costs sites 29 million 41 million since cleanup costs estimates subject revision information becomes available extent remediation required cases asserted defense liability estimates could change moreover liability federal cercla statute joint several meaning could required pay excess pro rata share remediation costs understanding financial strength prps considered appropriate determining estimated liabilities possible new information future developments could require us reassess potential exposure related environmental matters may incur significant costs liabilities order comply existing environmental laws regulations also possible developments increasingly strict environmental laws regulations claims damages property employees persons environment resulting current past operations could result substantial costs liabilities future information becomes available relevant developments occur adjust accrual amounts accordingly still uncertainties relating ultimate costs may incur based upon evaluation experience date believe current reserves adequate rates regulatory matters wholesale power customers complaints late 2001 early 2002 several wholesale power customers filed complaints ferc epme wholesale power marketers list complaints included primary customers nevada power co sierra pacific power co npsp pacificorp city burbank california public utilities commission california electricity oversight board cpucceob customers entered contracts epme wholesale power suppliers purchase power delivered future complaints customers asked ferc reform contracts entered epme wholesale power marketers grounds involve rates terms unjust unreasonable contrary public interest within meaning federal power act fpa epme respondents believe allegations complaint without merit asked ferc dismiss complaints npsp matter alj issued initial decision concluding contracts issue modified complaints dismissed cpucceob matter alj issued decision finding public interest standard applies contract issue finding consistent initial decision alj npsp case cpucceob matter fully resolved upon finalization approval western energy settlement pacificorp matter alj issued initial decision concluding complaint filed pacificorp epme respondents dismissed prejudice decisions aljs submitted ferc review march 11 2003 city burbank matter set hearing cpuc complaint proceeding april 2000 public utilities commission state california cpuc filed complaint section 5 natural gas act nga ferc alleging sale approximately 12 billion cubic feet per day capacity epng epme wholly owned subsidiaries raised issues market power violation fercs marketing affiliate regulations asked contracts voided although ferc held epng violate marketing affiliate requirements established hearing alj address market power issue spring summer 2001 two hearings held alj address market power issue request alj affiliate issue october 2001 alj issued initial decision two issues finding record support finding either epng epme exercised market power accordingly market power claims dismissed alj found however epng violated fercs marketing affiliate rule epng parties filed briefs exceptions briefs opposing exceptions october initial decision also october 2001 fercs office market oversight enforcement filed comments stating record hearings inadequate conclude epng complied ferc regulations transportation gas california december 2001 ferc remanded proceeding alj supplemental hearing availability capacity epngs california delivery points september 23 2002 alj issued initial decision finding evidence epme exercised market power period issue drive california gas prices therefore recommending complaint epme dismissed however alj found epng withheld least 345 mmcfd capacity perhaps much 696 mmcfd california market period november 1 2000 march 31 2001 alj found alleged withholding violated epngs certificate obligations exercise market power increased gas price california markets therefore recommended ferc initiate penalty procedures epng others filed briefs exceptions initial decision october 23 2002 briefs opposing exceptions filed november 12 2002 proceeding resolved upon finalization approval western energy settlement systemwide capacity allocation proceeding july 2001 several epngs contract demand cd customers filed complaint epng ferc claiming among things epngs full requirements contracts fr contracts volumetric limitations converted cd contracts epng required expand system give demand charge credits cd customers unable meet full contract demands july 2001 several epngs fr customers filed complaint alleging epng violated natural gas act contractual obligations expanding system cost meet increased requirements may 31 2002 ferc issued order complaints required fr service fr customers except small volume customers converted cd service ii firm customers assigned specific receipt point rights lieu existing systemwide receipt point rights iii reservation charge credits given firm customers failure schedule confirmed volumes except cases force majeure iv new firm contracts executed epng demonstrated adequate capacity system v process implemented allow existing cd customers turn back capacity acquisition fr customers process epng would remain revenue neutral changes made effective november 1 2002 order also stated ferc expected epng file certificate authority add compression line 2000 increase system capacity 320 mmcfd without cost coverage next rate case ie january 1 2006 epng previously informed ferc willing add compression line 2000 provided assured rate coverage next rate case july 1 2002 epng parties filed clarification andor rehearing may 31 order september 20 2002 urging fr shippers ferc issued order postponing may 1 2003 effective date fr conversions order also required epng allocate among fr customers 320 mmcfd capacity available addition compression line 2000 ii firm capacity expires existing contracts may 31 2002 may 1 2003 thereby precluding reselling capacity total september 20 order required epngs fr customers pay current aggregate reservation charges existing unsubscribed capacity 230 mmcfd capacity made available november 2002 epngs line 2000 project 320 mmcfd capacity addition compression line 2000 capacity subject contracts expiring may 1 2003 beginning may 1 2003 epng required pay reservation charge credits unable schedule confirmed volumes except cases force majeure may 1 2003 required pay partial reservation charge credits cd customers unable schedule 95 percent monthly confirmed volumes except reasons force majeure provided capacity available supply basins system several pleadings filed response september 20 order including rehearing requests several customers modify order based aljs decision cpuc complaint proceeding discussed pleadings remain pending ferc interim epng proceeding directives contained september 20 order october 7 2002 epng filed tariff sheets compliance september 20 order implement partial demand charge credit period november 1 2002 may 31 2003 allow california delivery points used secondary receipt points extent backhaul displacement capabilities epng proposed reservation usage charge service december 26 2002 ferc issued order denying epngs request charge existing cd customers reservation rate california receipt service remaining term settlement ie december 31 2005 ii allowing epng charge maximum rate service iii approving epngs proposed usage rate service next rate case iv requiring make showing capacity available new shippers utilizing service epng made revised tariff filing january 10 2003 compliance december 26 order january 27 2003 epng filed request rehearing certain aspects december 26 order request pending rate settlement epngs current rate settlement establishes base rates december 31 2005 settlement epngs base rates began escalating annually 1998 inflation epng right increase decrease base rates changes laws regulations result increased decreased costs excess 10 million year addition epngs settling customers participate risk sharing provisions epng received cash payments total 295 million portion risk epng assumed capacity relinquishments customers primarily capacity turned back southern california gas company pacific gas electric company represented approximately onethird capacity epngs system 1996 1997 cash epng received deferred epng recognizes amount revenues ratably risk sharing period december 31 2002 epng unearned risk sharing revenues approximately 32 million 13 million remaining collected customers provision amounts received relinquished capacity sold customers certain dollar levels specified epngs rate settlement obligate refund portion excess customers provision epng refunded 46 million 2001 revenues customers 2001 2002 epng established additional refund obligation 46 million 32 million refunded 2002 remainder refunded 2003 risk revenue sharing provisions rate settlement extend 2003 line 2000 project july 31 2000 epng applied ferc certificate public convenience necessity line 2000 project designed replace old compression system converted oil pipeline resulting increase system capacity response demand conditions system however epng filed march 2001 amend application convert project expansion project 230 mmcfd may 7 2001 ferc authorized amended line 2000 project epng placed line service november 2002 approximate capital cost 185 million cost line 2000 conversion included epngs rates next rate case effective january 1 2006 october 3 2002 pursuant fercs may 31 september 20 orders systemwide capacity allocation proceeding epng filed ferc certificate public convenience necessity add compression line 2000 project increase capacity line additional 320 mmcfd estimated capital cost approximately 173 million phases application protested remains pending epngs request clarification september 20 order epng asked assurances ferc able begin cost recovery project time next rate case becomes effective request remains pending marketing affiliate nopr september 2001 ferc issued notice proposed rulemaking nopr proposes apply standards conduct governing relationship interstate pipelines marketing affiliates energy affiliates proposed regulations adopted ferc would dictate energy affiliates conduct business interact interstate pipelines december 2001 filed comments ferc addressing concerns proposed rules public hearing held may 21 2002 providing opportunity comment nopr following conference additional comments filed pipeline subsidiaries others time cannot predict outcome nopr adoption regulations proposed form would minimum place additional administrative operational burdens us negotiated rate noi july 2002 ferc issued notice inquiry noi seeks comments regarding 1996 policy permitting pipelines enter negotiated rate transactions several pipelines entered transactions years ferc reviewing whether negotiated rates capped whether recourse rate costofservice based rate continues safeguard pipeline exercising market power issues related negotiated rate programs september 25 2002 pipelines others filed comments reply comments filed october 25 2002 time cannot predict outcome noi cash management nopr august 1 2002 ferc issued nopr requiring cash management money pool arrangements ferc regulated subsidiary nonferc regulated parent must writing set forth duties responsibilities cash management participants administrators methods calculating interest allocating interest income expenses restrictions deposits borrowings money pool members nopr also requires specified documentation deposits borrowings interest income interest expenses related arrangements finally nopr proposed condition participating cash management money pool arrangement ferc regulated entity maintain minimum proprietary capital balance 30 percent ferc regulated entity parent maintain investment grade credit ratings august 28 2002 comments filed ferc held public conference september 25 2002 discuss issues raised comments representatives companies gas electric industries participated panel uniformly agreed proposed regulations revised substantially proposed capital balance investment grade credit rating requirements would excessive time cannot predict outcome nopr also august 1 2002 fercs chief accountant issued accounting release effective immediately accounting release provides guidance companies account money pool arrangements types documentation maintained arrangements however address proposed requirements ferc regulated entity maintain minimum proprietary capital balance 30 percent entity parent investment grade credit ratings requests rehearing filed august 30 2002 ferc yet acted rehearing requests emergency reconstruction interstate natural gas facilities nopr january 17 2003 ferc issued nopr proposing 1 expand scope construction activities authorized pipelines blanket certificate allow replacement mainline facilities 2 authorize pipeline commence reconstruction affected system without waiting period 3 authorize automatic approval construction would normal cost ceiling comments nopr filed february 27 2003 time cannot predict outcome rulemaking pipeline safety notice proposed rulemaking january 28 2003 us department transportation issued nopr proposing establish rule requiring pipeline operators develop integrity management programs comprehensively evaluate pipelines take measures protect pipeline segments located notice refers high consequence areas proposed rule resulted enactment pipeline safety improvement act 2002 new bill signed law december 2002 pipelines intend submit comments nopr due april 30 2003 time cannot predict outcome rulemaking ferc inquiry february 26 2003 received letter office chief accountant ferc requesting details announcement 2003 asset sales plans subsidiaries sng anr issue combined 700 million longterm notes letter requested explain intended use proceeds sngs anrs issuance notes included two regulated companies capital structure ratesetting purposes response ferc filed march 12 2003 fully responded request western trading strategies epme subsidiary responded may 22 2002 fercs may 8 2002 request docket pa022 seeking statements admission denial respect trading strategies designed manipulate western power markets epme provided affidavit stating engaged trading strategies wash trade inquiries may 21 22 2002 ferc issued data requests docket pa022 including requests statements admission denial respect socalled wash round trip trades western power gas markets may june 2002 epme responded denying conducted wash round trip trades ie simultaneous prearranged trades entered purpose artificially inflating trading volumes revenues manipulating prices june 7 2002 received informal inquiry sec regarding issue round trip trades although believe round trip trades occurred submitted data sec july 15 2002 july 12 2002 received federal grand jury subpoena documents concerning socalled round trip wash trades complied requests price reporting indices october 22 2002 ferc issued data request docket pa022 largest north american gas marketers including epme regarding price reporting transactional data energy trade press engaged outside firm investigate matters raised data request epme provided information regarding price reporting indices ferc commodities futures trading commission cftc us attorney response requests information provided indicates inaccurate prices reported trade publications epme evidence reporting publications resulted unrepresentative price index march 26 2003 announced settlement epme cftc price reporting matter providing payment epme civil monetary penalty 20 million 10 million payable within three years without admitting denying findings made cftc order implementing agreement refunds pricing august 13 2002 ferc issued notice requesting comment method determining natural gas prices purposes calculating refunds ongoing california refund proceedings dealing sales electric power companies involved referencing staff report also issued august 13 2002 ferc requested comments whether change method determining delivered cost natural gas calculating mitigated marketclearing price refund proceeding method used comments filed october 15 2002 december 12 2002 alj issued initial decision setting forth preliminary calculations amounts owed aggregate alj found 3 billion owed natural gas suppliers offset aggregate refund 12 billion associated prices charged excess mitigated market clearing prices upon finalization approval western energy settlement claims many claimants proceeding credits amounts due epme resolved however specific amount adjustment indeterminable time full ferc expected review decision later 2003 cannot predict final outcome matter australia june 2001 western australia regulators issued draft rate decision lower expected levels dampiertobunbury pipeline owned epic energy australia trust 33 percent ownership interest total investment approximately 200 million epic energy australia appealed variety issues related draft decision western australia supreme court directed regulator review position comply applicable regulatory law fourth quarter 2002 events business epic energy australia including unanticipated cash requirements made apparent cash equity infusion would required refinance debt epic energywa nominee pty matures payable full 2003 fourth quarter credit downgrades rating agencies demands liquidity concluded would contribute equity epic energy western australian investment result recognized impairment 153 million related investment epic energys dampiertobunbury pipeline southwestern bell proceeding engaged proceedings southwestern bell involving disputes regarding telecommunications interconnection agreement metropolitan transport business july 2002 received favorable ruling administrative law judge phase 1 proceedings anticipate determination puc texas administrative law judges recommendation later second quarter 2003 despite favorable ruling administrative law judge puc retains right affirm reject award significant rejection award could negatively impact metro transport business adverse resolution proceeding puc could negative impact ongoing operations prospects business fcc triennial review proceeding fcc pursuant congressional mandate reexamining entire list unbundled network elements unes including high capacity loops transport dark fiber determine removed qualified possible fcc may either eliminate set stringent offering guidelines existing unes although epgn reason assume dark fiber high capacity loops transport may eliminated ruling seriously impaired ability access unes would significantly affect current business model epgn filed comments order expected april 2003 fcc broadband docket fcc issued notice proposed rule making nprm broadband service asked general comments vast array issues nprm indicates fcc inclined declare highspeed dsl internet access service information service would allow incumbent local exchange carriers ilecs stop leasing dsl internet service third party competitors resale customers ilecs also submitted proposals would effectively deregulate optical level highspeed copper based services fcc adopted nprm proposal results would critically affect epgns business epgn filed initial comments conjunction clecs epgn also filed joint reply comments july 3 2002 stressing illegality proposed finding national security implications certain ilecs advocating position high capacity copper fiber lines found information services thereby exempting lease lines epgn opposed holding believe would unlawful decision expected sometime first half 2003 outcome outstanding legal matters environmental matters rates regulatory matters cannot predicted certainty based current information existing accruals expect ultimate resolution matters material adverse effect financial position operating results cash flows however possible new information future developments could require us reassess potential exposure related matters also possible matters could impact debt rating credit rating see item 7 managements discussion analysis financial condition results operations subheading recent developments environmental matters also possible developments increasingly strict environmental laws regulations claims damages property employees persons environment resulting current past operations could result substantial costs liabilities future new information regarding outstanding legal matters environmental matters rates regulatory matters becomes available relevant developments occur review accruals make appropriate adjustments impact changes may material effect results operations financial position cash flows period event occurs matters lng time charters 2001 2002 contracted charter four lng tankers option charter fifth ship transport lng supply areas domestic international market centers february 2003 following announced plan minimize involvement lng business entered various agreements ship owners four ship charters option chartering fifth ship cancelled consideration payments us totaling 24 million two ship charters ship owners assumed responsibility charter vessels paid 20 million capital costs associated fitting two ships regasification capabilities connection transferring chartering responsibilities back ship owners agreed provide letters credit fully collateralized cash equal 120 million could drawn ship owners cover additional capital costs shortfalls rates able charter vessels compared rates provided original charter agreements adjusted capital costs already paid event ship owners able charter ships rates excess original rates adjusted share benefits also retained rights charter vessels use future lng activities connection transactions future exposure ship arrangements limited 120 million enron bankruptcy december 2001 enron corp number subsidiaries including enron north america corp enron power marketing inc epmi filed chapter 11 bankruptcy protection united states bankruptcy court southern district new york contracts enron north america enron power marketing enron subsidiaries among things transportation natural gas ngl trading physical natural gas power petroleum financial derivatives merchant energy positions governed master international swap dealers association inc agreement various master natural gas agreements master power purchase sale agreement commodity agreements terminated tradingrelated contracts believe proper accordance terms contracts october 2002 filed proofs claim domestic trading positions enron trading entities amount totaling approximately 318 million also october 2002 european trading business asserted 20 million claims enron capital trade resources limited subject proceedings united kingdom considering cash margins enron deposited us well reserves established overall merchant energy exposure enron 29 million classified current accounts notes receivable believe amount reasonable based offers received purchase claims february 2003 merchant energy received letter epmi demanding payment march 2001 power purchase sale agreement approximately 46 million merchant energy responded february 2003 demand letter denying sums due epmi agreement addition epmi made demand us sum based august 2 2001 guaranty agreement epmi filed lawsuit merchant energy el paso united states bankruptcy court southern district new york seeking collect sums denied liability addition various enron subsidiaries transportation contracts several pipeline systems transportation contracts rejected pipeline subsidiaries filed proofs claim totaling approximately 137 million epng filed largest proof claim amount approximately 128 million included 18 million amounts due services provided date contracts rejected 110 million damage claims arising rejection transportation contracts september 20 order epng capacity allocation proceeding discussed rates regulatory matters prohibits epng remarketing enron capacity remarketed prior may 31 2002 epng sought rehearing september 20 order fully reserved amounts due date contracts rejected recognized amounts contracts since rejection date result current circumstances surrounding energy sector creditworthiness several industry participants called question taken actions mitigate exposure participants however several industry participants file chapter 11 bankruptcy protection contracts various subsidiaries assumed counterparties could material adverse effect financial position operating results cash flows broadwing arbitration june 2000 el paso global networks epgn formerly known el paso communications company entered agreement broadwing communications services broadwing construct maintain fiber optic telecommunications system houston texas los angeles california may 2002 epgn terminated agreements broadwing due broadwings failure meet contractual obligations broadwing disputed epgns right terminate agreements subsequently epgn filed demand arbitration named arbitrator also sought obtained injunctive relief require broadwing perform maintenance activity prohibit removing materials equipment purchased project determined properly terminated contract broadwing required return money paid us 62 million transfer work completed date free clear liens arbitration scheduled fourth quarter 2003 fourth quarter 2002 wrote value longhaul route 4 million leaving total investment 104 million economic conditions brazil investments power pipeline production projects brazil including investment gemstone aggregate exposure including financial guarantees approximately 18 billion 2002 brazil experienced significant decline financial markets due largely concerns refinancing brazils foreign debt presidential elections completed late october 2002 concerns contributed higher interest rates local debt government private sectors significantly decreased availability funds lenders outside brazil decreased amount foreign investment country factors contributed downgrade brazils foreign currency debt rating 52 percent devaluation local currency us dollar 2002 developments likely delay implementation project financings underway brazil international monetary fund announced fourth quarter 30 billion loan package brazil however release majority money depend brazil committing specified fiscal targets 2003 addition brazils newly elected president may impose changes affecting business including imposing tariff controls electricity fuels currently believe economic difficulties brazil material adverse effect investment country continue monitor economic situation potential changes governmental policy future developments brazil could cause us reassess exposure gemstone affiliate owns 60 percent interest 484 mw gasfired power project known araucaria project located near curitiba brazil investment araucaria project 176 million december 31 2002 project company ownership interest 20 year power purchase agreement ppa copel regional utility copel approximately 60 percent owned state parana recent elections brazil new governor state parana publicly characterized araucaria project unfavorable copel state parana promised full review transaction subsequent announcement copel informed us pay capacity payments due ppa pending review previous payments made ppa made reservation rights respect enforceability contract meeting government well new management copel discuss copels obligations power purchase agreement unable come satisfactory resolution current issues ppa may required initiate enforcement remedies contract including filing arbitration proceeding international chamber commerce rules paris prevail proceeding otherwise able enforce remedies contract could required impair investment project losses would limited investment meizhou wan power project 25 percent equity interest 734 mw coalfired power generating project meizhou wan generating located fuzhou peoples republic china investment project 56 million december 31 2002 also issued 34 million guarantees letters credit equity support debt service reserves project debt collateralized projects assets nonrecourse us project declared ready commercial operations august 2001 however provincial government also buys power generated project accepted project commercial operations october 2002 reached interim agreement allow plant operate sell power reduced rates march 2003 longterm resolution existing past contract terms negotiated price project receives sale power interim agreement expected sufficient provide operating costs debt service project provide return investment projects owners project unable reach longterm agreement provincial government higher rates interim agreement could required impair investment project since cash flows project would sufficient provide us return investment may incur additional losses guarantees letters credit called upon losses limited extent investment guarantees letters credit december 31 2002 impaired 7 million goodwill related investment project milford power project 25 percent direct equity interest 540 mw power plant construction project located milford connecticut chaparral affiliate owns additional 70 percent interest project financed equity contributions construction financing lenders recourse project construction management services agreement funded project experienced significant construction delays primarily associated technological difficulties turbines including inability operate gas fuel oil operate designed capacity specified construction contract october 2001 entered construction management services agreement providing additional funding october 1 2002 construction contractor failed complete construction plant prior october 1 2002 accordance terms specifications construction contract result project default construction lending agreement october 25 2002 entered standstill agreement construction lending banks expired december 2 2002 continue negotiating contractor lending banks attempt reach agreements contract disputes including resolution liquidated damages due project terms construction contract successful completion plant construction march 4 2003 provided notice milford declaring event default fuel supply agreement us milford due nonpayment milford march 6 2003 milford received notice lenders stating lenders intended commence foreclosure project accordance lending agreement within 30 days result default construction lending agreement evaluated investment recorded impairment charge 17 million chaparral recorded impairment charge 44 million fourth quarter 2002 december 31 2002 direct investment project 67 million loans milford construction management services agreement also provided guarantee 8 million fund debt service account milford may required fund account facility financially able within two years commercial operations date unable reach negotiated settlement disputes lending banks may right accelerate construction loan foreclose project may result impairment construction loans including guaranteed amount project occurred could record impairment charge 75 million berkshire power project 25 percent direct equity interest 261 mw power plant located massachusetts chaparral affiliate owns additional 314 percent interest project construction contractor failed deliver plant capable operating gas fuel oil capable operating designed capacity berkshire negotiating contractor respect failure deliver project accordance guaranteed specifications including fuel oil firing capability third quarter 2002 project lenders asserted berkshire default loan agreement berkshire process negotiating lenders resolve disputed contract terms failure reach satisfactory resolution matters could material adverse effect value investment project december 31 2002 direct investment berkshire 20 million including receivables 16 million subordinated fuel agreement chaparrals investment 1 million continue discuss settlement opportunities construction contractor ppn power project subsidiary owns 26 percent minority equity interest 325 mw dual fuel naphtha natural gas fired generating plant located tamil nadu province india project achieved commercial operations april 2001 obtained dual fuel capability september 2002 project sells power tamil nadu electricity board tneb paid power rate lower rate called power purchase agreement december 31 2002 project overdue receivables 36 million tneb requested increase rates permitted charge customers within service territory order provide revenues sufficient make payments owed us amounts currently paid sufficient cover debt service normal operating expenses insufficient cover maintenance return equity project unable reach longterm agreement tneb collect rates higher currently paid project may incur losses plant continues operate recent events also made possibility long term operations natural gas less likely effect increasing operating cost project use naphtha makes electric generation expensive per kilowatt hour basis december 31 2002 impaired investment project totaled 41 million cases california cases discussed five filed superior court los angeles county continental forge company et al v southern california gas company et al filed september 25 2000 berg v southern california gas company et al filed december 18 2000 county los angeles v southern california gas company et al filed january 8 2002 city los angeles et al v southern california gas company et al city long beach et al v southern california gas company et al filed march 20 2001 two filed superior court san diego county john whk phillip v el paso merchant energy john phillip v el paso merchant energy filed december 13 2000 two filed superior court san francisco countysweeties et al v el paso corporation et al filed march 22 2001 california dairies inc et al v el paso corporation et al filed may 21 2001 one filed superior court state california county alameda dry creek corporation v el paso natural gas company et al filed december 10 2001 five filed superior court los angeles countythe city san bernardino v southern california gas company et al city vernon v southern california gas company city upland v southern california gas company et al edgington oil company v southern california gas company et al world oil corporation et al v southern california gas company et al filed december 27 2002 two longterm power contract lawsuits james millar v allegheny energy supply company et al filed may 13 2002 superior court san francisco county california tom mcclintock et al v vikram budhrajaetal filed may 1 2002 superior court los angeles county california cases referenced energy market lawsuits state nevada et al v el paso corporation el paso natural gas company el paso merchant energy company et al filed november 2002 district court clark county nevada sharon lynn lodewick v dynegy inc et al filed december 16 2002 circuit court county multnomah state oregon nick symonds v dynegy inc et al filed december 20 2002 united states district court western district washington seattle henry w perlman et al v san diego gas electric et al filed december 2002 united states district court southern district new york state arizona v el paso corporation el paso natural gas company el paso merchant energy company et al filed march 10 2003 superior court maricopa county arizona purported shareholder class actions filed us district court southern district texas houston division marvin goldfarb et al v el paso corporation william wise h brent austin rodney erskine filed july 18 2002 residuary estate mollie nussbacher adele brody life tenant et al v el paso corporation william wise h brent austin filed july 25 2002 george johnson et al v el paso corporation william wise h brent austin filed july 29 2002 renneck wilson et al v el paso corporation william wise h brent austin rodney erskine filed august 1 2002 sandra joan malin revocable trust et al v el paso corporation william wise h brent austin cases dismissed upon finalization approval western energy settlement rodney erskine filed august 1 2002 lee shalov et al v el paso corporation william wise h brent austin rodney erskine filed august 15 2002 paul c scott et al v el paso corporation william wise h brent austin rodney erskine filed august 22 2002 brenda greenblatt et al v el paso corporation william wise h brent austin rodney erskine filed august 23 2002 stefanie beck et al v el paso corporation william wise h brent austin filed august 23 2002 j wayne knowles et al v el paso corporation william wise h brent austin rodney erskine filed september 13 2002 ezra charitable trust et al v el paso corporation william wise rodney erskine h brent austin filed october 4 2002 purported shareholder action filed southern district new york ira fbo michael conner et al v el paso corporation william wise h brent austin jeffrey beason ralph eads dwight scott credit suisse first boston jp morgan securities filed october 25 2002 shareholder derivative actions filed houston grunet realty corp v william wise byron allumbaugh john bissell juan carlos braniff james gibbons anthony hall jr ronald kuehn jr j carleton macneil jr thomas mcdade malcolm wallop joe wyatt dwight scott filed august 22 2002 john gebhart v byron allumbaugh john bissell juan carlos braniff james gibbons anthony hall jr ronald kuehn jr j carleton macneil jr thomas mcdade malcolm wallop joe wyatt william wise filed march 2002 marilyn clark v el paso natural gas el paso merchant energy byron allumbaugh john bissell juan carlos braniff james gibbons anthony hall jr ronald kuehn jr j carleton macneil jr thomas mcdade malcolm wallop joe wyatt william wise filed november 2002 shareholder derivative lawsuit filed delaware stephen brudno et al v william wise et al filed october 2002 customer complaints filed ferc epme wholesale power marketers nevada power company sierra pacific power company vs el paso merchant energy lp california public utilities commission vs sellers longterm contracts california department water california electricity oversight board vs pacificorp vs el paso merchant energy lp city burbank california vs calpine energy services lp duke energy trading marketing llc el paso merchant energy erisa class action suit william h lewis iii v el paso corporation h brent austin unknown fiduciary defendants 1100 commitments purchase obligations operating leases maintain operating leases ordinary course business activities leases include office space operating facilities office operating equipment terms agreements vary 2003 2053 december 31 2002 total commitments operating leases approximately 844 million several leases provided residual value guarantees lessor total outstanding residual value guarantees operating leases december 31 2002 see residual value guarantees minimum annual rental commitments december 31 2002 follows aggregate minimum commitments reduced minimum sublease rentals approximately 13 million due future noncancelable subleases rental expense operating leases years ended december 31 2002 2001 2000 196 million 147 million 198 million guarantees involved various joint ventures ownership arrangements sometimes require additional financial support results issuance financial performance guarantees financial guarantee obligated make payments guaranteed party fails make payments violates terms financial arrangement performance guarantee provide assurance guaranteed party execute terms contract required perform behalf example guaranteed party required deliver natural gas third party fails would required either deliver natural gas make payments third party equal difference contract price market value natural gas december 31 2002 approximately 25 billion financial performance guarantees outstanding amount approximately 10 billion relates chaparral investment 950 million relates gemstone investment remaining 558 million relates global power equity investments including projects chaparral gemstone pipeline petroleum activities residual value guarantees two operating leases provided residual value guarantees lessor guarantees either choose purchase asset end lease term specified amount typically equal outstanding loan amounts owed lessor choose assist sale leased asset third party asset sold price equals exceeds amount guarantee would obligated shortfall levels residual value guarantees range 862 percent 899 percent original cost leased assets accounting residual value guarantees impacted effective july 1 2003 adoption new accounting rules consolidations discussion accounting impact new rules see note 1 december 31 2002 purchase options residual value guarantees associated operating leases following assets commercial commitments various commercial commitments purchase obligations december 31 2002 firm commitments transportation storage capacity contracts 14 billion commodity purchase commitments 36 million part trading activities purchase capital commitments including maintenance engineering procurement construction contracts 825 million 21 retirement benefits pension benefits maintain defined benefit pension plan covers substantially us employees provides benefits cash balance formula employees participating el pasos defined benefit pension plan december 31 1996 receive greater cash balance benefits prior plan benefits accrued december 31 2001 effective january 1 2000 sonats pension plan merged pension plan sonat employees participants sonat pension plan december 31 1999 receive greater cash balance benefits sonat plan benefits accrued december 31 2004 prior merger coastal provided noncontributory pension plans covering substantially us employees april 1 2001 coastals primary plan merged existing plan coastal employees participants coastals primary plan march 31 2001 receive greater cash balance benefits coastal plan benefits accrued march 31 2006 following mergers coastal sonat offered early retirement incentive program eligible employees organizations programs offered enhanced pension benefits individuals elected early retirement charges incurred connection sonat program 8 million connection coastal program 152 million separate plans provided employees coal convenience store operations also participate one multiemployer pension plan benefit employees union members contributions plan material 2002 2001 retirement savings plan maintain defined contribution plan covering us employees prior may 1 2002 matched 75 percent participant basic contributions 6 percent matching contribution made plans stock fund participants could diversify time may 1 2002 plan amended allow company matching contributions invested manner participant contributions effective march 1 2003 suspended matching contribution amounts expensed plan approximately 28 million 30 million 35 million years ended december 31 2002 2001 2000 postretirement benefits provide postretirement medical benefits coastal coal closed groups retired employees epng el paso tennessee sonat coastal limited postretirement life insurance benefits current retired employees january 31 2003 sale coastal coal operations completed result sale coastal coal closed group retired employees see note 9 discussion matter postretirement employee benefits opeb prefunded extent costs recoverable rates extent actual opeb costs tgp epng sng differ amounts recovered rates regulatory asset liability recorded medical benefits closed groups retirees may subject deductibles copayment provisions limitations dollar caps amount employer costs reserve right change benefits following table details projected benefit obligation accumulated benefit obligation fair value plan assets september 30 related balance sheet accounts december 31 recorded loss pension plans comprehensive loss accumulated benefit obligation exceeded fair value plan assets plans september 30 2002 included pension plans september 30 2001 two pension plans whose accumulated benefit obligation exceeded fair value plan assets projected benefit obligation accumulated benefit obligation accrued benefit liability associated plans 51 million 47 million 61 million september 30 2001 following table sets forth change benefit obligation change plan assets reconciliation funded status components net periodic benefit cost pension benefits postretirement benefits presented computed twelve months ended september 30 1 unrecognized net actuarial loss september 30 2002 year ended december 31 2002 primarily result decrease discount rate used actuarial calculation lower actual returns plan assets compared expected return 2002 recognize difference actual return expected return three year period permitted sfas 87 current liability portion postretirement benefits 35 million december 31 2002 46 million december 31 2001 benefit obligations based upon actuarial estimates described assumptions differed average rates presented following table details weighted average assumptions used pension postretirement plans 2002 2001 actuarial estimates postretirement benefits plans assumed weighted average annual rate increase per capita costs covered health care benefits 110 percent 2002 gradually decreasing 55 percent year 2008 assumed health care cost trends significant effect amounts reported postretirement benefit plans onepercentage point change assumed health care cost trends would following effects 22 capital stock common stock may 2002 increased authorized capitalization 15 billion shares common equity june 2002 issued approximately 518 million additional shares common stock approximately 1 billion net issuance costs approximately 31 million december 2001 issued 203 million shares common stock approximately 863 million net issuance costs equity security units june 2002 issued 115 million 9 equity security units equity security units consist two securities purchase contract pay quarterly contract adjustment payments annual rate 286 requires holder buy el paso common stock settled august 16 2005 ii senior note due august 16 2007 principal amount 50 per unit pay quarterly interest payments annual rate 614 beginning august 16 2002 senior notes issued total principal value 575 million pledged secure holders obligation purchase shares common stock purchase contracts purchase contracts settled 2005 issue el paso common stock time proceeds allocated common stock additional paidin capital number common shares issued depend prior consecutive 20trading day average closing price common stock determined third trading day immediately prior stock purchase date issue minimum approximately 24 million shares maximum 288 million shares settlement date depending average stock price recorded approximately 43 million noncurrent liabilities reflect present value quarterly contract adjustment payments required make units annual rate 286 stated amount 50 per purchase contract offsetting reduction additional paidin capital quarterly contract adjustment payments allocated liability recognized date issuance additional paidin capital based constant rate term purchase contracts fees expenses incurred connection equity security units offering allocated senior notes purchase contracts based respective fair values issuance date amount allocated senior notes recognized interest expense term senior notes amount allocated purchase contracts recorded additional paidin capital feline pridessm august 2002 issued 12184444 shares common stock satisfy purchase contract obligations feline pridessm program return issuance stock received approximately 25 million cash maturity zero coupon bond return 435 million existing 6625 senior debentures due august 2004 issued 1999 zero coupon bond senior debentures held collateral purchase contract obligations 25 million received maturity zero coupon bond used retire additional senior debentures total debt reduction issuance common stock approximately 460 million preferred stock part balance sheet enhancement plan announced december 2001 completed amendments chaparral gemstone agreements 2002 eliminated series b mandatorily convertible single reset preferred stock issued connection chaparral third party notes eliminated series c mandatorily convertible single reset preferred stock issued connection gemstone third party notes dividend february 5 2003 declared quarterly dividend 004 per share common stock payable april 7 2003 stockholders record march 7 2003 also year ended december 31 2002 el paso tennessee pipeline co subsidiary paid dividends 25 million series cumulative preferred stock 8 14 per annum 20625 per quarter 23 stockbased compensation grant stock awards various stock option plans account stock option plans using accounting principles board opinion 25 related interpretations employee plans may issue incentive stock options common stock intended qualify section 422 internal revenue code nonqualified stock options restricted stock appreciation rights sars phantom stock options performance units nonemployee director plans may issue nonqualified stock options deferred shares common stock reserved approximately 69 million shares common stock existing future stock awards december 31 2002 approximately 24 million shares remained unissued nonqualified stock options granted nonqualified stock options employees 2002 2001 2000 stock options contractual terms 10 years generally vest completion one five years continuous employment grant date also granted options nonemployee members board directors fair market value grant date exercisable immediately except special circumstances summary stock options stock options outstanding december 31 2002 2001 2000 presented fair value stock option granted estimated date grant using blackscholes optionpricing model following weightedaverage assumptions blackscholes weighted average fair value options granted 2002 2001 2000 1423 1575 1016 restricted stock stockbased compensation plans limited number shares restricted common stock may granted officers employees shares carry voting dividend rights however sale transfer shares restricted stock awards vest specific period time andor achieve established performance targets restricted stock awards representing 14 million 23 million 04 million shares granted 2002 2001 2000 weighted average grant date fair value 3845 6210 3482 per share december 31 2002 44 million shares restricted stock outstanding value restricted shares subject performance vesting determined based fair market value date performance targets achieved value charged compensation expense ratably required service restriction period value time vested restricted shares determined issuance date cost amortized compensation expense period service 2002 2001 2000 charges totaled 73 million 67 million 13 million included deferred compensation december 31 2000 69 million related options converted automatically common stock end vesting period options met performance targets december 2000 performance units award eligible officers performance units payable cash stock end vesting period final value performance units may vary according plan granted usually based common stock price end vesting period total shareholder return vesting period relative peer group value performance units charged ratably compensation expense vesting period periodic adjustments account fluctuation market price stock changes expected total shareholder return amounts charged compensation expense 2002 2001 2000 10 million 64 million 25 million 2001 expense includes 51 million charge pay outstanding phantom stock options june 2002 reduced amount accruing performance units issued executives adjustment decreased total liability 21 million employee stock purchase program october 1999 implemented employee stock purchase plan section 423 internal revenue code plan allows participating employees right purchase common stock quarterly basis 85 percent lower market price beginning plan period end calendar quarter five million shares common stock authorized issuance plan following table presents number shares issued price per share quarter year ended december 31 1 since many employees reached maximum contribution imposed section 423 internal revenue code third quarter 2001 2002 excluded participating fourth quarter 2001 2002 funds receive program may used general corporate purposes however record liability withholdings yet applied towards purchase common stock bear expenses associated administering plan except costs including applicable taxes associated participants sale common stock effective january 1 2003 suspended employee stock purchase program 24 segment information segregate business activities four distinct operating segments pipelines production field services merchant energy segments strategic business units provide variety energy products services managed separately business unit requires different technology marketing strategies second quarter 2002 reclassified historical coal mining operations merchant energy segment discontinued operations financial statements periods restated reflect change pipelines segment provides natural gas transmission storage gathering related services us internationally conduct activities primarily seven wholly owned seven partially owned interstate transmission systems along six underground natural gas storage entities lng terminalling facility pipeline operations also include access us based systems canada mexico well interests three operating natural gas transmission systems australia production segment engaged exploration acquisition development production natural gas oil natural gas liquids primarily north america us production onshore coal seam operations properties 16 states offshore operations properties federal state waters gulf mexico internationally exploration production rights australia bolivia brazil canada hungary indonesia turkey field services segment provides customers wellheadtomainline services including natural gas gathering products extraction fractionation dehydration purification compression transportation natural gas natural gas liquids field services assets include 23 processing plants related gathering facilities located south texas louisiana midcontinent rocky mountain regions well interest el paso energy partners merchant energy segment consists three primary divisions global power petroleum energy trading buy sell trade natural gas power crude oil refined products coal energy commodities throughout world interests 88 power plants 18 countries use ebit assess operating results effectiveness business segments define ebit operating income adjusted several items including equity earnings unconsolidated investments minority interests consolidated less whollyowned operating subsidiaries miscellaneous nonoperating items included measure financing costs including interest debt expense returns preferred interest consolidated subsidiaries income taxes discontinued operations extraordinary items impact accounting changes believe measurement useful investors allows evaluate effectiveness businesses operations investments operational perspective exclusive costs finance activities exclusive income taxes neither directly relevant efficiency operations measurement may comparable measurements used companies used substitute net income performance measures operating cash flow following segment results year ended december 31 1 includes corporate telecommunication activities eliminations intercompany transactions intersegment revenues along intersegment operating expenses consist normal course businesstype transactions operating segments record intersegment revenue elimination included corporate column remove intersegment transactions 2 merchant energy revenues take account adoption consensus reached eitf issue 023 requires us report physical sales energy commodities energy trading activities net basis component revenues see note 1 regarding adoption issue 3 includes 106 million assets classified discontinued operations 1 includes corporate telecommunication activities eliminations intercompany transactions 2001 retail business intersegment revenues along intersegment operating expenses consist normal course businesstype transactions operating segments record intersegment revenue elimination included corporate column remove intersegment transactions 2 merchant energy revenues take account adoption consensus reached eitf issue 023 requires us report physical sales energy commodities energy trading activities net basis component revenues see note 1 regarding adoption issue 3 increase intersegment revenue 2000 2001 production segment primarily due consolidation engage september 2000 4 includes 352 million assets classified discontinued operations 1 includes corporate telecommunication activities eliminations intercompany transactions intersegment revenues along intersegment operating expenses consist normal course businesstype transactions operating segments record intersegment revenue elimination included corporate column remove intersegment transactions 2 merchant energy revenues take account adoption consensus reached eitf issue 023 requires us report physical sales energy commodities energy trading activities net basis component revenues see note 1 regarding adoption issue 3 includes 322 million assets classified discontinued operations reconciliations ebit income loss continuing operation extraordinary items cumulative effect accounting changes presented three years ended december 31 customers whose revenues exceeded 10 percent total revenues 2002 2001 2000 25 supplemental cash flow information detail cash flow changes working capital three years ending december 31 follows nonworking capital cash flow changes three years ending december 31 follows following table contains supplemental cash flow information years ended december 31 interest taxes reflected working capital nonworking capital changes detail shortterm longterm borrowings repayments years ended december 31 follows 26 investments advances unconsolidated affiliates hold investments various unconsolidated affiliates accounted using equity method accounting principal equity method investees international pipelines interstate pipelines power generation plants gathering systems investment balance greater equity net assets investments december 31 2002 2001 223 million 551 million 2002 primary differences related unamortized purchase price adjustments asset impairment charges 2001 primary differences related unamortized purchase price adjustments power contract restructurings change priority return investment chaparral financial guarantee international investment net ownership interest investments advances unconsolidated affiliates follows december 31 1 sold 123 percent interest november 2002 sold remaining 21 percent interest march 2003 2 lp represents limited partnership 3 sold 100 percent interest november 2002 4 llc represents limited liability company 5 sold 100 percent interest january 2003 6 mesquite investors llc included chaparral gave notice partner march 2003 intent exercise option purchase interest anticipate transaction close second quarter 2003 7 citrus corporation owns 100 percent florida gas transmission system 8 consolidated january 2002 9 gp represents general partnership 10 ownership interest consists one percent general partner interest approximately 27 percent partnerships common units outstanding series b preference units 158 million liquidation value outstanding series c units acquired 350 million november 2002 11 includes 46 percent general partner interest great lakes gas transmission limited partnership 4 percent limited partner interest ownership great lakes gas transmission company 12 ownership interest consists 381 percent general partner interest 54 percent limited partner interest 13 denotes investments individually less 50 million 14 impaired first quarter 2002 includes 45 percent capsa owns 60 percent capex results 27 percent indirect ownership interest capex 15 sold 100 percent interest samalayuca ii power plant december 2002 earnings unconsolidated affiliates follows three years ended december 31 1 sold 123 percent interest november 2002 sold remaining 21 percent interest march 2003 2 sold first quarter 2003 3 consolidated january 2002 4 sold interest samalayuca ii power plant december 2002 impairment charges gains losses sales investments 2002 2001 2000 consisted following summarized financial information proportionate share unconsolidated affiliates includes affiliates hold less 50 percent interest well hold greater 50 percent interest received distributions dividends 256 million 2002 241 million 2001 investments proportional shares unconsolidated affiliates hold greater 50 percent interest net income 24 million 38 million 2002 2001 total assets 450 million 766 million december 31 2002 2001 following table shows revenues charges unconsolidated affiliates 1 decrease 2001 affiliated revenue cost sales due primarily consolidation engage september 2000 chaparral entered chaparral investment also referred electron 1999 expand domestic power generation business chaparrals corporate structure limited liability company december 31 2002 owned approximately 20 us approximately 80 unaffiliated investor limestone capitalized private equity contributions 150 million group unrelated financial investors credit suisse first boston corporation 1 billion senior secured notes issued institutional investors limestone controlled subsidiaries affiliates credit suisse first boston corporation march 2003 notified limestone would exercise right partnership agreements purchase outstanding third party equity limestone may 31 2003 175 million also march 2003 contributed 1 billion limestone exchange noncontrolling interest limestone used pay limestone notes matured march 17 2003 following investment 1 billion limestone effective ownership chaparral increased approximately 90 percent continue account investment chaparral equity method since control limestone therefore control chaparral however consolidate chaparral upon purchase remaining limestone equity interest anticipate occur may 2003 time record acquired assets liabilities fair values fair value assets liabilities acquired impacted changes unregulated power industry whole well changes regional power prices us excess proceeds paid fair value net assets acquired reflected goodwill amortized tested impairment chaparral owns interests approximately 34 power generation facilities december 31 2002 chaparral 42 billion total assets 18 billion consolidated third party debt chaparrals debt related specific projects owns interests recourse solely projects entered various financing transactions chaparral subsidiaries year include capital contributions debt issuances advances following table summarizes presentation transactions balance sheet december 31 millions debt securities notes payable receivable revolving credit facility contingent interest promissory notes included current longterm receivables payables affiliates appropriate related interest income expense income statement debt securities payable chaparral payable demand carry fixed interest rate 7443 notes payable receivable chaparral payable demand carry various fixed interest rates credit facility established 1999 allows chaparral borrow 925 million us variable interest rate 194 264 732 december 31 2002 2001 2000 contingent interest promissory notes carry variable interest rate exceed 1275 100 110 109 december 31 2002 2001 2000 mature 2019 2021 interest payments contingent cash flow distributions five power plant investments sell investments maturity date notes may accelerated chaparral used funds contributed limestone acquire domestic power generation related businesses described cases chaparral acquired power generation assets us chaparral acquire power generation assets us 2002 chaparral acquired power generation assets us value 276 million 2001 determined fair reasonable amount recognize gains losses transactions addition financing transactions described also entered various contractual agreements chaparral related management trading activities serve manager chaparral management agreement expires 2006 compensated services provide annual management fee performance based fixed components performance fee determined based well performed manager chaparral determined evaluating changes value portfolio power assets held chaparral management fee evaluated reasonableness subject approval joint venture partner annually 2002 2001 management fee 205 million 167 million consisting 185 million 147 million performance fee recorded operating revenues plus 20 million annual fixed fee years recorded reimbursement operating expenses expect earn performancebased management fee receive cost reimbursement fee chaparral 2003 addition administrative services agreements many power plants chaparral structure recorded approximately 104 million 95 million 47 million 2002 2001 2000 reimbursement operating expenses agreements also enter various contractual agreements chaparral operating subsidiaries conjunction chaparrals operations include agreements supply natural gas fuels power chaparrals facilities ii purchase portion power produced chaparrals facilities iii provide power supply chaparral obligated provide fulfill agreements third parties iv purchase tolling rights v provide services chaparral related operations recognized revenues 65 million 243 million 2002 2001 related transactions activities accounted accrual method marktomarket method accounting depending contract gemstone entered gemstone investment 2001 finance five major power plants brazil gemstone generic term used describe several entities first joint venture equity investment named diamond power ventures llc diamond owned us company called gemstone investor limited gemstone investor gemstone investor 100 percent owned subsidiary rabobank international addition 50 million equity investment issued 950 million senior secured notes institutional investors gemstone investor used entire 1 billion invest 700 million diamond b purchase 300 million preferred interest company called topaz power ventures llc topaz consolidated subsidiary topaz indirectly owns operates two brazilian power plants account gemstone investors preferred investment topaz minority interest consolidate diamond owns three power plants development brazil gemstone owns interests five power generation facilities brazil total power generation capacity 2184 megawatts december 31 2002 gemstone total assets 17 billion including 304 million investment topaz carries preferred return 803 122 million receivables us carry fixed interest rate 525 total investment gemstone december 31 2002 663 million excluding payables 122 million minority interest 304 million mentioned consolidated subsidiary gemstone administracao ltda serves managing member diamond provides management services diamond fixedfee administrative services agreement original term ten years fixed fee reimburses us legal accounting general administrative expenses incurred behalf diamond fee significant 2002 2001 following summarizes financial position gemstone december 31 millions credit facility gemstone allows gemstone borrow 300 million us variable interest rate 68 december 31 2002 gemstone owed us 25 million facility december 31 2002 utilize facility 2001 earned less 1 million interest income facility 2002 2001 investment gemstone december 31 2002 2001 663 million 555 million account investment using equity method accounting since ability exercise control entity shortterm notes issued included shortterm borrowings balance sheet related interest expense income statement account investors preferred interest consolidated subsidiary minority interest balance sheet preferred return minority interest expense income statement management agreement gemstone earn costbased management fee significant 2002 2001 also entered participation agreement one gemstones power generation interests whereby earn fee managing constructing operating related facilities marketing distributing energy produced facilities fee significant 2002 rabobank third party investor gemstone right remove us manager gemstone january 2003 rabobank notified us planned remove us manager turn notified rabobank exercising right partnership agreements purchase 50 million equity gemstone consolidate gemstone upon purchase rabobanks third party equity gemstone april 2003 unless replace new partner gemstone owns interests five power generation facilities brazil total power generation capacity 2184 mw summarized financial position data unconsolidated affiliate gemstone diamond power ventures llc follows december 31 citrus 50 percent citrus corp enron corp owns 50 percent citrus corporation owns florida gas transmission 4804 mile regulated pipeline system extends producing regions texas markets florida investment citrus limited ownership voting stock citrus financial obligations commitments guarantees either written oral support citrus one commercial contract citrus provide natural gas trading subsidiary citrus paid fixed price ownership agreements citrus provide partner right first refusal purchase ownership interest partner obligations either written oral acquire enrons ownership interest citrus event enron must sell interest result current bankruptcy proceedings enron serves operator citrus enron filed bankruptcy minimal changes operations management citrus result enrons bankruptcy accordingly citrus continued operate jointly owned investment significant influence ability control enrons bankruptcy impacted financial results citrus related energy contracts citrus enrons energy trading subsidiary 2001 established reserves 69 million related enron bankruptcy 2002 accounts receivable balances associated contracts rejected bankruptcy court classified uncollectable applied 69 million reserve amount outstanding accounts receivable balance none charges considered material financial statements el paso energy partners subsidiary field services segment serves general partner el paso energy partners master limited partnership limited partnership units trade new york stock exchange currently 265 percent 11674245 partnerships common units one percent general partner interest remaining 735 percent common units limited partnership owned public unit holders including small amounts owned general partners management employees none exceeds 10 percent ownership interest november 2002 part proceeds sale san juan basin assets el paso energy partners received 350 million series c units new nonvoting class limited partnership units series c units receive level distributions common units converted common units april 30 2003 right request vote common unitholders whether series c units converted common units common unitholders approve conversion series c unit convert common unit common unitholders approve conversion within 120 days vote requested distribution rate series c units increase 105 percent common unit distribution rate time thereafter series c unit distribution rate increase 110 percent common unit distribution rate april 30 2004 115 percent common unit distribution rate april 30 2005 also third quarter 2000 received 170 million series b preference units exchange sale natural gas storage businesses crystal gas storage inc wholly owned subsidiary el paso energy partners preference units accrue dividends rate 10 cumulative basis redeemable option el paso energy partners october 2001 partnership redeemed 50 million liquidation value series b preference units received crystal transaction december 31 2002 liquidation value remaining series b preference units 158 million majority members board directors governing el paso energy partners independent us audit conflicts committee governance compensation committee completely comprised independent board members general partner field services manages partnerships daytoday operations performs partnerships administrative operational activities general administrative services agreement cases separate operational agreements el paso energy partners contributes income general partner interest ownership common preference units loans el paso energy partners addition except nominal guarantee lease obligations behalf subsidiary el paso energy partners provided guarantees either monetary performance behalf benefit el paso energy partners liabilities normal course business result arising role general partner ownership interest el paso energy partners normal course business transactions el paso energy partners include sales natural gas services transportation fractionation storage processing types operational services activities based terms nonaffiliates field services recognized revenues 1 million 2002 cost sales 97 million 32 million 2002 2001 field services also reimbursed 59 million 34 million 22 million 2002 2001 2000 expenses incurred behalf partnership addition merchant energy recognized revenues 6 million 28 million 14 million 2002 2001 2000 cost sales 80 million 16 million 22 million 2002 2001 2000 2001 result merger coastal el paso energy partners sold interest several offshore assets including seven natural gas pipeline systems dehydration facility two offshore platforms proceeds sales approximately 135 million resulted loss partnership approximately 25 million consideration sales committed pay el paso energy partners series payments totaling 29 million required contribute 40 million trust related one assets sold el paso energy partners payments recorded mergerrelated costs april 2002 november 2002 sold midstream assets el paso energy partners total consideration 735 million 766 million see note 3 discussion 27 supplemental selected quarterly financial information unaudited financial information quarter summarized 1 coal mining operations classified discontinued operations see note 10 discussion 2 operating revenues differ previously reported march 31 2002 form 10q 9433 million due income statement reclassifications associated adoption eitf issue 023 discontinued operations minor reclassifications impact previously reported net income stockholders equity 3 operating income loss differs previously reported september 30 2002 june 30 2002 march 31 2002 form 10qs 10 million 15 million 387 million due income statement reclassifications associated discontinued operations reclassifications gains losses asset sales asset impairments operating income minor reclassifications impact previously reported net income stockholders equity 1 coal mining operations classified discontinued operations see note 10 discussion 2 operating revenues differ previously reported september 30 2001 june 30 2001 march 31 2001 form 10qs 10679 million 9606 million 13787 million due income statement reclassifications associated adoption eitf issue 023 discontinued operations minor reclassifications impact previously reported net income stockholders equity 3 operating income loss differs previously reported september 30 2001 june 30 2001 march 31 2001 form 10qs 3 million 141 million 4 million due income statement reclassifications associated discontinued operations reclassification gains losses asset sales asset impairments operating income minor reclassifications impact previously reported net income stockholders equity 28 supplemental natural gas oil operations unaudited december 31 2002 interests natural gas oil properties 16 states offshore operations properties federal state waters gulf mexico internationally limited number natural gas oil properties brazil canada hungary indonesia also exploration production rights australia bolivia brazil canada hungary indonesia turkey purposes supplemental natural gas oil operations disclosure presented reserves standardized measure discounted future net cash flows related changes standardized measure separately natural gas systems operations includes regulated natural gas oil properties owned colorado interstate gas company subsidiaries sold 2002 supplemental natural gas oil operations disclosure include value natural gas systems storage gas liquids volumes managed pipelines segment capitalized costs relating natural gas oil producing activities related accumulated depreciation depletion amortization follows december 31 millions 1 includes international operations brazil hungary indonesia costs incurred natural gas oil producing activities whether capitalized expensed follows december 31 millions 1 includes international operations brazil hungary indonesia per january 1 2003 reserve report amounts estimated spent 2003 2004 2005 develop worldwide booked proved undeveloped reserves 570 million 483 million 178 million presented analysis capitalized costs natural gas oil properties year expenditure amortized december 31 2002 pending determination proved reserves capitalized interest 16 million 18 million 7 million years ended december 31 2002 2001 2000 included presentation millions 1 includes operations united states brazil canada hungary indonesia projects presently excluded amortization various stages evaluation majority costs expected included amortization calculation years 2003 2006 total amortization expense per mcfe including ceiling test charges 171 122 100 2002 2001 2000 excluding ceiling test charges amortization expense would 131 104 100 per mcfe 2002 2001 2000 depreciation depletion amortization excludes provisions impairment international projects 15 million 2000 proved properties exception proved reserves brazil hungary indonesia located north america us canada net quantities proved developed undeveloped reserves natural gas liquids including condensate crude oil changes reserves presented information table based reserve report dated january 1 2003 prepared internally production reviewed huddleston co inc information consistent estimates reserves filed federal agencies except differences less five percent resulting actual production acquisitions property sales necessary reserve revisions additions reflect actual experience reserves include 465783 mmcfe production delivery commitments financing arrangements extend 2042 financing arrangement supported reserves matures 2006 total proved reserves fields dedicated production 919265 mmcfe addition table excludes following equity interests productions interest unopaso pescada brazil merchant energys interests sengkang indonesia capsa capex argentina aguaytia peru interest el paso energy partners combined proved natural gas reserves balances equity interests 435713 mmcf liquids reserves 39693 mbbls natural gas equivalents 673871 mmcfe net ownership interests 1 includes international operations brazil hungary indonesia 2 includes natural gas oil properties owned colorado interstate gas company subsidiaries sold 2002 3 net proved reserves exclude royalties interests owned others reflects contractual arrangements royalty obligations effect time estimate 1 includes international operations brazil hungary indonesia 2 includes natural gas oil properties owned colorado interstate gas company subsidiaries sold 2002 1 includes oil condensate natural gas liquids 2 includes international operations brazil hungary indonesia 3 includes natural gas oil properties owned colorado interstate gas company subsidiaries sold 2002 4 net proved reserves exclude royalties interests owned others reflects contractual arrangements royalty obligations effect time estimate 1 includes oil condensate natural gas liquids 2 includes international operations brazil hungary indonesia 3 includes natural gas oil properties owned colorado interstate gas company subsidiaries sold 2002 numerous uncertainties inherent estimating quantities proved reserves projecting future rates production timing development expenditures including many factors beyond control reserve data represents estimates reservoir engineering subjective process estimating underground accumulations natural gas oil cannot measured exact manner significant changes reserves purchases sales production due reservoir performance existing fields drilling additional wells existing fields major discoveries events favorable adverse may considered caused significant change estimated proved reserves since december 31 2002 results operations producing activities fiscal year follows december 31 millions 1 includes international operations brazil hungary indonesia 2 production costs include direct lifting costs labor repairs maintenance materials supplies administrative costs field offices insurance property severance taxes 1 includes international operations brazil hungary indonesia 2 production costs include direct lifting costs labor repairs maintenance materials supplies administrative costs field offices insurance property severance taxes standardized measure discounted future net cash flows relating proved natural gas oil reserves follows december 31 millions 1 includes international operations brazil hungary indonesia 2 includes natural gas oil properties owned colorado interstate gas company subsidiaries sold 2002 3 excludes 708 million future net cash outflows attributable hedging activities 1 includes international operations brazil hungary indonesia 2 includes natural gas oil properties owned colorado interstate gas company subsidiaries sold 2002 3 excludes 973 million future net cash inflows attributable hedging activities 4 excludes 1995 million future net cash outflows attributable hedging activities calculations preceding table estimated future cash inflows estimated future production proved reserves computed using yearend market natural gas oil prices may receive amounts different standardized measure discounted cash flow number reasons including price changes effects hedging activities rely upon standardized measure making investment operating decisions based various factors including probable proved reserves different price cost assumptions actual economic conditions capital availability corporate investment criteria following principal sources change standardized measure discounted future net cash flows millions 1 disclosure reflects changes standardized measure calculation excluding effects hedging activities 2 includes operations united states canada brazil hungary indonesia 3 includes natural gas oil properties owned colorado interstate gas company subsidiaries sold 2002 report independent accountants board directors stockholders el paso corporation opinion based upon audits report auditors consolidated financial statements listed index item 15a1 present fairly material respects consolidated financial position el paso corporation subsidiaries company december 31 2002 2001 consolidated results operations cash flows three years period ended december 31 2002 conformity accounting principles generally accepted united states america addition opinion based audits report auditors financial statement schedule listed index item 15a2 presents fairly material respects information set forth therein read conjunction related consolidated financial statements financial statements financial statement schedule responsibility companys management responsibility express opinion financial statements financial statement schedule based audits consolidated financial statements financial statement schedule give retroactive effect merger el paso cgp company formerly coastal corporation january 29 2001 transaction accounted pooling interests described note 3 consolidated financial statements audit financial statements financial statement schedule el paso cgp company december 31 2000 year ended statements reflect total revenues 26936 million year ended december 31 2000 statements audited auditors whose report thereon furnished us opinion expressed herein insofar relates amounts included el paso cgp company december 31 2000 year ended based solely report auditors conducted audits statements accordance auditing standards generally accepted united states america require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements assessing accounting principles used significant estimates made management evaluating overall financial statement presentation believe audits report auditors provide reasonable basis opinion discussed notes 1 6 company adopted statement financial accounting standards 142 goodwill intangible assets statement financial accounting standards 144 accounting impairment disposal longlived assets january 1 2002 dig issue c16 scope exceptions applying normal purchases sales exception contracts combine forward contract purchased option contract second quarter 2002 eitf issue 023 accounting contracts involved energy trading risk management activities consensus 1 2 third fourth quarter 2002 respectively described notes 1 13 company adopted statement financial accounting standards 133 accounting derivatives hedging activities january 1 2001 pricewaterhousecoopers llp houston texas march 28 2003 independent auditors report board directors stockholders el paso cgp company houston texas audited consolidated statements income stockholders equity cash flows comprehensive income el paso cgp company formerly coastal corporation subsidiaries year ended december 31 2000 presented separately herein audit also included el paso cgp schedule valuation qualifying accounts presented separately herein financial statements financial statement schedule responsibility companys management responsibility express opinion financial statements based audit conducted audit accordance auditing standards generally accepted united states america standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements audit also includes assessing accounting principles used significant estimates made management well evaluating overall financial statement presentation believe audit provides reasonable basis opinion consolidated financial statements present fairly material respects el paso cgp companys results operations cash flows year ended december 31 2000 conformity accounting principles generally accepted united states america also opinion financial statement schedule considered relation basic consolidated financial statements taken whole presents fairly material respects information set forth therein deloitte touche llp houston texas march 19 2001 march 28 2003 effects reclassifications related adoption net reporting trading activities discontinued operations discussed notes 1 9 respectively schedule ii el paso corporation valuation qualifying accounts years ended december 31 2002 2001 2000 millions 1relates western energy settlement 899 million 2payments various litigation reserves 3payments various environmental remediation reserves 4payments revenue crediting rate settlement reserves 5primarily accounts written 6in 2001 finalized purchase price adjustment legal reserves related pge acquisition 7of amount 232 million relates additional environmental remediation liabilities recorded connection events described note 20 8we accrued 23 million 2001 reversed 24 million reserves corpus christi refinery leased valero june 9of amount 53 million legal reserve acquired connection purchase pges texas midstream operations recorded additional 159 million legal reserves related purchase price adjustments pge acquisition item 9item 8 financial statements supplementary data index financial statements notes contained item 8 financial statements supplementary data el paso corporation consolidated statements income millions except per common share amounts see accompanying notes el paso corporation consolidated balance sheets millions except share amounts see accompanying notes el paso corporation consolidated balance sheets continued millions except share amounts see accompanying notes el paso corporation consolidated statements cash flows millions 1 individual line items cash flows operating activities restated total cash flows continuing operating investing financing activities well discontinued operations unaffected see accompanying notes el paso corporation consolidated statements cash flows continued millions 1 individual line items cash flows operating activities restated total cash flows continuing operating investing financing activities well discontinued operations unaffected see accompanying notes el paso corporation consolidated statements stockholders equity thousands shares millions dollars except per share amounts see accompanying notes el paso corporation consolidated statements comprehensive income millions see accompanying notes el paso corporation notes consolidated financial statements 1 restatement historical financial statements liquidity 2004 identified several issues resulted restatement amounts previously reported historical financial statements periods 1999 2002 first nine months 2003 restatements related revisions historical estimates proved natural gas reserves manner accounted certain derivatives primarily related hedges natural gas production restatements discussed restatement historical financial statements reserve revisions february 2004 completed december 31 2003 reserve estimation process proved natural gas oil reserves production segment time independent reserve engineers completed estimates proved reserves overall internally prepared reserve estimates within 5 percent total estimates independent reserve engineers proved reserve estimates december 31 2003 indicated 18 tcfe approximate 41 percent downward revision proved natural gas oil reserves needed given size revision audit committee board directors initiated independent investigation conducted outside law firm determine factors contributed significant downward revision scope investigation included 1 assessing reasons downward revisions 2 evaluating internal controls associated booking reserves 3 suggesting recommendations regard improvements internal controls processes 4 recommending remedial actions may required investigation included completion 200 interviews review 100000 documents based investigation results concluded material portion negative reserve revisions reflected periods prior 2003 would require revision historical reserve estimates included supplemental natural gas oil operations data quantities proven natural gas oil reserves used determining financial statement amounts including ceiling test charges depletion expense gains losses property sales revision historical reserve estimates required restatement financial statement information derived estimates investigation found certain personnel used aggressive times unsupportable methods book proved reserves instances certain personnel provided historical proved reserve estimates knew known incorrect time reported investigation also found cases maintain adequate documentation records support historically booked reserves based results investigation reviewed alternatives respect method methods used restate reserve amounts prior periods b assessed implemented remedial actions related management structure internal control environment internal control processes accounting certain derivatives august 2004 evaluated manner historically accounted hedges anticipated natural gas production certain hedging transactions related primarily pipeline capacity held pipelines hedges anticipated production owned one pipeline subsidiaries entered significant number hedge transactions 1999 2002 hedge transactions certain subsidiaries would enter affiliated derivative positions merchant energy segment usually fixed floating swaps merchant energy segment would enter identical transaction third party complete accounting hedge consolidated reporting purposes hedge transaction accomplish portfolio management objectives merchant energy segment would many cases enter offsetting transaction third party transactions third parties create hedge complete offsetting transactions implemented master isda swap agreements total 457 hedging transactions took place timeframe 110 approximately 24 percent involved use offsetting transaction however approximately 79 percent volumes hedged period involved use offsetting transaction applying accounting treatment transactions prior periods originally concluded hedge offsetting transaction economic substance separate apart conclusion based upon several factors including hedges offsetting transactions entered market prices ii merchant energy segment valid business purpose entering offsetting transaction ie permit company manage overall price risk exposure trading portfolio efficient basis iii view credit risk associated separate enforcement hedges offsetting transactions reaching conclusion restate historical accounting related hedging transactions determined properly applied generally accepted accounting principles gaap first reviewed factors supported original accounting determinations took consideration underlying business purpose entering offsetting transactions pricing transactions economic substance offsetting transactions upon review factors considered aggregate determined hedge offsetting transaction meet requirements treated separate transactions gaap principally determined business purpose offsetting transaction alone sufficient satisfy standards separate accounting treatment hedge transaction gaap requires objective two transactions one may accomplished single transaction production hedge objectives could accomplished single though less efficient transaction addition considered two additional factors reaching conclusion first found offsetting transactions entered within range current market prices second determined general matter sufficient credit risk associated separate enforcement transactions support original conclusion transactions economic substance based conclusions determined restatement historical financial statements required following determination restatement needed conducted investigation reasons restatement b remedial actions taken restatement methodologies reserve revisions concerns historical documentation supporting reserves aggressive sometimes unsupportable methods used personnel booking proved reserves methodology adopted restate reserves years ended december 31 2001 2002 nine months ended september 30 2003 reserve reconstruction approach method utilized estimated proved reserves december 31 2003 derived review completed february 2004 determined historical reserves adjusting reserves actual historical production data known data determine reconstructed estimates reserves period end basic assumption underlying methodology december 31 2003 reserve report represented recent reliable available information best estimate proved reserves report therefore became basis historical reserve reconstruction created reconstruction process adding actual production volumes prior periods well basis adjustments assets sold significant sales reevaluated one independent reserve engineers since proved reserves sold december 31 2003 reserve report needed reevaluated given findings investigation known information period cost capital spending restatement period applied approach described back december 31 2000 however periods prior december 31 2000 necessary determine impact reserve restatement beginning stockholders equity january 1 2001 access necessary detailed electronic records apply methodology due part documentation issues identified investigation numerous changes personnel immediately following past mergers impacted ability locate historical documentation result used december 31 2000 reserve levels determined reconstruction approach described foundation estimating reserves related future cash flows ceiling test purposes periods prior december 31 2000 estimation approach involved use reserve production ratio based reconstructed december 31 2000 reserve estimates reserve production ratio provided estimated life reserves based production levels applied ratio actual historical period production levels calculate estimated historical reserves period determining reserve production ratio use period historical prices considered since different pricing levels varying levels reserves economical produce also impacted capital cost operating cost revenue assumptions determining cash flows would derived reserves overall restatement approach allowed us recalculate reasonable proved reserve estimates end quarter last five years determined historical reserve levels calculated estimated future net cash flows end quarter revised quarterly proved reserves resulting discounted net cash flows used perform ceiling test calculate depreciation depletion amortization rate income taxes evaluate gain loss recognition asset sales quarter finally assessed adequacy overall approach based historical prices historically capitalized costs leading earliest period restatement performed based assessment believe amount recorded retained earnings adjustment january 1 1999 reasonably reflects financial statement impact restated reserve levels would occurred prior time believe approach used restate historical reserves reasonable approach appropriate circumstances based current thoroughly reviewed well documented reserve study reflects actual historical data however limitations first restated reserve levels reported earnings incorporate normal positive negative revisions reserves could resulted reasons mechanical failures changes estimates impact actual drilling results proved undeveloped reserves normally occurring changes reserves estimates methodology used reflected year actually occurred rather part beginning retained earnings adjustments overall believe effects reported results would similar second use variation methodology years 1999 2000 determine impact retained earnings january 1 2001 restated reserves periods may comparable reserve amounts would resulted actual reconstruction none periods would identical completely reengineered approach overall however believe approach given results investigation documentation issues discussed provides reasonable approach revising historical reserve data presents related historical financial results accordance generally accepted accounting principles also considered restatement methodologies reengineering specific production reserve areas determine hindsight previous estimates adjusted specific periods rejected approach several reasons first method would produced view accurate result method adopted particularly given concerns respect timing reserves originally recorded second difficult make reasonable assessments specific reserves booked particular time without influenced subsequent data especially light assumptions already made reserve estimation process third investigation identified large number personnel responsible making reserve estimates consistent centralized approach used reserve estimation process including assumptions used process documentation generated support assumptions b lack controls inputs reserve data base result factors integrity data could reasonably relied upon detailed reengineering reserves finally findings independent investigation identified inadequate detailed historical technical documentation support booking certain reported reserves consequently without detailed documentation would extremely difficult cases impossible determine precision appropriate time specific reserves removed proved reserves category reserve restatement methodology resulted following revisions proved natural gas oil reserves bcfe unaudited restatement proved reserves also impacted previously reported items supplemental information natural gas oil activities including classification costs incurred natural gas oil activities exploration development cost discussion natural gas oil reserves see note 30 supplemental natural gas oil operations production certain hedges stated entered series derivative transactions related substantial portion anticipated natural gas production certain derivative transactions included production pipeline segment affiliated hedges merchant energy segment ii merchant energys identical transaction third party hedge transaction iii merchant energys offsetting transaction third party offsetting transaction historical accounting derivative transactions ii defer income statement impacts settlement underlying transactions impacts merchant energys offsetting transactions positive negative reflected income statement marktomarket basis period 1999 september 30 2003 recognized total approximately 499 million taxes marktomarket income related offsetting transactions deferring similar loss accumulated comprehensive income hedges restate historical results reversed amounts deferred accumulated comprehensive income related hedges reflected marktomarket basis income statement period consolidated level effect reversing amounts accumulated comprehensive income statement period material impact reported periods consolidated stockholders equity however affect reported income loss period addition loss hedge accounting historical periods affected ceiling test calculations periods resulting additional losses discussion impacts restatement see discussion business segments evaluated whether affected segments reflect affiliated transaction production merchant energy individual segment results whether conclude since derivatives qualify hedges consolidated reporting level reported hedges individual segment level concluded known original transactions would qualified hedges consolidated reporting purposes would entered original transactions accordingly presenting individual segment results reversed impacts transactions qualify hedges consolidated purposes see note 26 presentation restated historical segment results financial impact restatement total cumulative impact restatements affected stockholders equity september 30 2003 reduction approximately 24 billion includes reduction beginning stockholders equity january 1 2001 approximately 20 billion overall financial increasedecrease stockholders equity restatements year end follows billions 1 adjustments december 31 2000 represent opening retained earnings adjustment january 1 2001 reserve restatement amount represents impact reserve revisions 2000 prior years adjustment hedges relates primarily mark market losses 2000 individual financial statement line items historical financial statements years ended december 31 2002 2001 quarters years quarter first nine months 2003 reflect effects restatement calculation historical depletion expense effect cumulative effect accounting changes asset retirement obligations ii amount quarterly full cost ceiling test charges amounts capitalized natural gas oil full cost pools iii amounts gains losses recorded longlived assets sold iv amount marktomarket income recognized revenues period v impact income taxes amend annual report form 10k years ended december 31 2002 2001 quarterly reports form 10q periods prior december 31 2003 financial statements related financial information contained reports longer relied upon summary effects restatements reported amounts years ended december 31 2002 2001 quarterly periods three year periods ended december 31 2003 presented quarterly period information 2001 provided supplemental purposes also information quarterly data represents income statement balance sheet line items affected restatement additional supplemental quarterly information see note 29 supplemental selected quarterly financial information unaudited 1 ceiling test charges period calculated based comparison overall capitalized costs estimated future cash flows reserves using restated reserve levels current prices adjusting cash flows impact qualifying hedges calculations performed quarterly period restated 2 impact stockholders equity year ended december 31 2001 includes restatement impacts operating revenues depreciation depletion amortization ceiling test charges accumulated comprehensive income loss year well adjustment opening retained earnings effects restatement years prior 2001 3 cumulative effect transition adjustment recorded accumulated comprehensive income loss associated adoption sfas 133 january 1 2001 originally reported 1280 million reported restated financial statements 647 million 1 reported depreciation depletion amortization operating income loss income taxes benefit net loss basic diluted loss per common share continuing operations differ amounts originally included march 31 2003 form 10q 1 million 257 million 28 million 038 per share due reclassifications petroleum markets business discontinued operations minor reclassifications impact previously reported net income stockholders equity restatement historical reserve estimates historical financial information derived estimates restatement associated production hedges certain derivative transactions resulted delay filing annual financial statements year ended december 31 2003 resulted result delay filing forms 10q quarterly periods ended march 31 2004 june 30 2004 september 30 2004 furthermore restatements ongoing reviews investigations sec us attorney regulators restatements could limit delay ability quickly access capital markets near term finally two wholly owned subsidiaries el paso cgp company el paso production holding company also impacted restatement reserve revisions historical results also restated el paso production holding company restated certain derivative transactions restatement result lower depletion rate reduced exposure ceiling test charges future would case absent restatement addition restatement impact consolidated cash flows liquidity business update year ended december 31 2003 year significant change business strategy financial condition late 2002 designed plan realign businesses take advantage core competencies significantly reduce outstanding liabilities improve liquidity credit ratings continued investment grade throughout 2003 made significant progress areas outlined plan completing announcing sales assets investments approximately 66 billion 2003 2004 see note 4 completing financing transactions approximately 38 billion december 31 2003 see note 20 retiring refinancing approximately 70 billion maturing debt obligations preferred securities 58 billion december 31 2003 including retiring longterm debt 37 billion 28 billion december 31 2003 see note 20 repaying 900 million outstanding amounts 3 billion revolving credit facility net repayments 650 million december 31 2003 see note 20 redeeming 980 million obligations trinity river financing arrangement proceeds 12 billion term loan refinancing term loan eliminate 2004 2005 amortization requirements see note 21 eliminating 1 billion financial obligation purchase consolidation thirdparty equity interests gemstone chaparral power investments see note 3 redeeming preferred interests coastal securities company limited 100 million see note 21 exchanging common stock cash 53 percent outstanding equity security units reduced outstanding debt balances approximately 303 million see note 24 finalizing western energy settlement substantially resolved principal exposure relating western energy crisis raising funds satisfy significant portion obligations settlement see notes 6 22 mid2003 began work longrange plan publicly presented december 15 2003 plan among things defined core businesses established timeline debt reductions sales noncore businesses assets set financial goals future liquidity update discussed restated historical financial statements reflect reduction historically reported proved natural gas oil reserves revise manner accounted certain hedges primarily associated anticipated natural gas production believe material restatement financial statements would constituted events default 3 billion revolving credit facility various financing transactions specifically provisions arrangements related representations warranties accuracy historical financial statements debt total capitalization ratio 2004 received several waivers 3 billion revolving credit facility various financing transactions address issues waivers continue effective also received extension various lenders november 30 2004 file first second quarter 2004 forms 10q expect meet unable file forms 10q date able negotiate additional extension filing deadline 3 billion revolving credit facility various transactions could accelerated part obtaining waivers also amended various provisions 3 billion revolving credit facility including provisions related events default limitations ability well subsidiaries repay indebtedness scheduled mature june 30 2005 based upon review covenants contained indentures financing agreements outstanding indebtedness acceleration 3 billion revolving credit facility could constitute event default debt agreements addition three subsidiaries indentures associated public debt contain 5 million crossacceleration provisions 3 billion revolving credit facility matures june 30 2005 facility collateralized equity interests tgp epng anr cig southern gas storage company anr storage company series common units series c units gulf terra process negotiating refinancing facility currently expect successful obtaining refinancing cash sources june 30 2004 include available capacity revolving credit facility event unable refinance existing 3 billion revolving credit facility june 30 2005 would obligated repay outstanding amounts make alternative arrangements letters credit issued pursuant credit facility june 30 2004 borrowed 600 million approximately 11 billion letters credit issued credit facility although expect successfully refinance portion existing 3 billion revolving credit facility unsuccessful believe could adjust planned capital expenditures increase planned asset sales meet shortfall liquidity time provide operations el paso required repay obligations 3 billion revolving credit facility assets currently collateralize facility including equity interests tgp epng anr cig southern gas storage company anr storage company series common units gulfterra would become available support new financing transactions although cannot guarantee outcome future events believe available collateral would adequate provide financing sufficient meet liquidity needs various financing arrangements entered us subsidiaries including el paso cgp el paso production holding company include covenants require us file financial statements within specified time periods noncompliance covenants constitute automatic event default instead agreements subject acceleration indenture trustee holders least 25 percent outstanding principal amount series debt provides notice issuer noncompliance indenture event noncompliance cured filing financial statements within specified periods time 30 90 days receipt notice depending particular indenture avoid acceleration repayment holders el paso production holding companys debt obligations waived financial filing requirements december 31 2004 filing first second quarter 2004 forms 10q subsidiaries cure events noncompliance resulting failure file financial statements subsidiaries addition neither subsidiaries received notice default caused failure file financial statements financial statements subsidiaries also impacted restatement event acceleration may unable meet payment obligations respect related indebtedness furthermore material restatement financial statements period ended december 31 2001 could cause default financing agreements entered connection 950 million gemstone notes due october 31 2004 currently 748 million gemstone notes outstanding however currently expect repay notes full upon maturity october 31 2004 subsidiaries significant potential source liquidity us participate overall cash management program extent permitted financing agreements indentures cash management program depending whether participating subsidiary shortterm cash surpluses requirements either provide cash provides cash us incur event default credit facilities would unable obtain cash pipeline subsidiaries primary source cash program currently one subsidiaries cig advancing funds us via cash management program due expected cash needs addition ownership number subsidiaries investments serve collateral revolving credit facility borrowings lenders credit facility borrowings exercise rights collateral could required liquidate investments result events described subject voluntary involuntary bankruptcy proceedings creditors could attempt make claims subsidiaries including claims substantively consolidate subsidiaries believe claims substantively consolidate subsidiaries would without merit however assurance creditors would advance claim bankruptcy proceeding creditors able substantively consolidate subsidiaries bankruptcy proceeding could material adverse effect financial condition liquidity despite events described believe able meet liquidity cash needs remainder 2004 june 2005 combination sources including cash hand cash generated operations borrowings 3 billion revolving credit facility proceeds asset sales reduction discretionary capital expenditures possible issuance longterm debt common preferred equity securities however number factors could influence liquidity sources well timing ultimate outcome ongoing efforts plans 2 significant accounting policies basis presentation consolidated financial statements include accounts majorityowned controlled subsidiaries elimination significant intercompany accounts transactions results periods presented reflect petroleum markets coal mining businesses discontinued operations additionally financial statements prior periods include reclassifications made conform current year presentation reclassifications impact reported net income stockholders equity principles consolidation consolidate entities ability control operating financial decisions policies entity exert significant influence control policies decisions apply equity method accounting use cost method accounting unable exert significant influence entity determination ability control exert significant influence entity involves use judgment extent control influence equity owners participants entity discussed new accounting pronouncements issued yet adopted standard effective impact consolidation principles use estimates preparation financial statements conformity accounting principles generally accepted us requires use estimates assumptions affect amounts report assets liabilities revenues expenses disclosures financial statements actual results often differ estimates accounting regulated operations interstate natural gas pipelines storage operations subject jurisdiction ferc accordance natural gas act 1938 natural gas policy act 1978 regulated pipelines tgp epng sng mpc follow regulatory accounting principles prescribed statement financial accounting standards sfas 71 accounting effects certain types regulation anr cig wic discontinued application sfas 71 1996 accounting required sfas 71 differs accounting required businesses apply provisions transactions generally recorded differently result applying regulatory accounting requirements include capitalization equity return component regulated capital projects postretirement employee benefit plans costs included expected included future rates fourth quarter 2003 cig wic began reapplying provisions sfas 71 see note 17 discussion perform annual review assess applicability provisions sfas 71 financial statements outcome could result reapplication accounting regulated systems discontinuance accounting others cash equivalents consider shortterm investments original maturity less three months cash equivalents maintain cash deposit banks insurance companies pledged particular use restricted support potential liability classify balances restricted cash current noncurrent assets balance sheet based expect cash used december 31 2003 590 million restricted cash current assets 349 million noncurrent assets december 31 2002 124 million restricted cash current assets 212 million noncurrent assets 2003 amounts 468 million related funds escrowed western energy settlement discussed note 6 allowance doubtful accounts establish provisions losses accounts notes receivable natural gas imbalances due shippers operators determine collect part outstanding balance regularly review collectibility establish adjust allowance necessary using specific identification method inventory consists spare parts natural gas storage optic fiber power turbines classify inventory current noncurrent based whether sold used normal operating cycle assets relates typically within next twelve months use average cost method account inventories value inventory lower cost market value property plant equipment property plant equipment recorded original cost construction upon acquisition fair value assets acquired capitalize direct costs labor materials indirect costs overhead interest regulated businesses apply provisions sfas 71 equity return component capitalize major units property replacements improvements expense minor items included pipeline property balances additional acquisition costs represent excess purchase costs associated purchase business combinations allocated regulated interstate systems costs amortized straightline basis recover excess costs rates following table presents property plant equipment type depreciation method depreciable lives 1 regulated interstate systems apply sfas 71 use composite group method depreciate property plant equipment method assets similar useful lives characteristics grouped depreciated one asset apply depreciation rate approved rate settlements total cost group net book value equals salvage value reevaluate depreciation rates time redevelop transportation rates file ferc increase decrease rates retire regulated property plant equipment accounted sfas 71 charge accumulated depreciation amortization original cost plus cost remove sell dispose less salvage value recognize gain loss unless sell entire operating unit include gains losses dispositions operating units income retire regulated property plant equipment accounted sfas 71 nonregulated properties reduce property plant equipment original cost less accumulated depreciation salvage value remaining gain loss recorded income capitalize carrying cost funds invested construction longlived assets carrying cost consists interest cost investment financed debt applies regulated nonregulated transmission businesses ii return investment financed equity applies regulated transmission businesses apply sfas 71 debt portion calculated based average cost debt interest cost debt amounts capitalized years ended december 31 2003 2002 2001 34 million 32 million 63 million amounts included reduction interest expense income statements equity portion calculated using recent ferc approved equity rate return equity amounts capitalized years ended december 31 2003 2002 2001 19 million 8 million 8 million amounts included nonoperating income statement capitalized carrying costs debt equityfinanced construction reflected increase cost asset balance sheet asset impairments apply provisions sfas 144 accounting impairment disposal longlived assets account asset impairments standard evaluate asset impairment events circumstances indicate carrying value may recovered events include market declines changes manner intend use asset decisions sell asset adverse changes legal business environment adverse actions regulators event occurs evaluate recoverability assets carrying value based ability generate future cash flows undiscounted basis decide exit sell longlived asset group assets adjust carrying value assets downward necessary estimated sales price less costs sell fair value estimates continually updated generally based market data obtained sales process analysis expected discounted cash flows magnitude impairments impacted number factors including nature assets sold established time frame completing sales among factors also reclassify asset assets either heldforsale discontinued operations depending among criteria whether continuing involvement cash flows assets sold natural gas oil properties use full cost method account natural gas oil properties full cost method substantially productive nonproductive costs incurred connection acquisition development exploration natural gas oil reserves capitalized amounts include costs unproved properties internal costs directly related acquisition development exploration activities asset retirement costs capitalized interest method differs successful efforts method accounting activities primary differences two methods treatment exploratory dry hole costs generally expensed successful efforts determination made measurable reserves exist geological geophysical costs also expensed successful efforts method full cost method dry hole costs geological geophysical costs capitalized full cost pool periodically assessed recoverability discussed amortize capitalized costs using unit production method life proved reserves capitalized costs associated unproved properties excluded amortizable base properties evaluated future development costs dismantlement restoration abandonment costs net estimated salvage values included amortizable base beginning january 1 2003 began capitalizing asset retirement costs associated proved developed natural gas oil reserves full cost pool pursuant adoption sfas 143 accounting asset retirement obligations discussed capitalized costs net related income tax effects limited ceiling based present value future net revenues using end period spot prices discounted 10 percent plus lower cost fair market value unproved properties net related income tax effects discounted revenues equal greater total capitalized costs required writedown capitalized costs level perform ceiling test calculation quarter required writedowns included income statement ceiling test charge ceiling test calculations include effects derivative instruments designated qualify cash flow hedges anticipated future natural gas oil production sell convey interests including net profits interests natural gas oil properties reduce reserves amount attributable sold conveyed interest recognize gain loss sales natural gas oil properties unless sales would significantly alter relationship capitalized costs proved reserves treat sales proceeds nonsignificant sales adjustment cost properties goodwill intangible assets intangible assets consist goodwill resulting acquisitions intangible assets apply sfas 141 business combinations sfas 142 goodwill intangible assets account intangibles standards recognize goodwill separately intangible assets addition goodwill intangibles indefinite lives amortized also goodwill indefinite lived intangible assets periodically tested impairment least annually whenever event occurs indicates impairment may occurred adopted standards january 1 2002 stopped amortizing goodwill reported pretax aftertax gain 154 million cumulative effect accounting change 2002 elimination negative goodwill net carrying amounts goodwill december 31 2003 2002 changes net carrying amounts goodwill years ended december 31 2003 2002 segments follows may 2003 merchant energy segment recorded 22 million goodwill connection acquisition chaparral december 2003 board directors approved sale significant number chaparrals power plants based bids received determined goodwill recorded chaparral recoverable fully impaired related 22 million goodwill segment also disposed 42 million goodwill related sale financial services businesses 2002 merchant energy impaired 44 million goodwill associated financial services businesses impairment resulted combined effects weak industry conditions decision invest capital businesses also impaired 163 million goodwill 2003 related telecommunications business corporate activities due weak industry conditions production segment also impaired 75 million goodwill 2003 resulted decision reduce involvement canadian production operations intangible assets consist customer lists general partnership interest gulfterra miscellaneous intangible assets amortize intangible assets straightline basis estimated useful life excluding excess investment general partnership interest gulfterra determined indefinite life following gross carrying amounts accumulated amortization intangible assets december 31 amortization expense intangible assets subject amortization 9 million years ended december 31 2003 2002 year ended december 31 2001 amortization intangible assets including goodwill 55 million based current amount intangible assets subject amortization estimated amortization expense approximately 1 million next five years amounts may vary result future acquisitions dispositions recorded impairments following table presents loss extraordinary items cumulative effect accounting changes net income basic diluted earnings per common share year ended december 31 2001 goodwill indefinitelived intangibles amortized year compared results actually reported pension postretirement benefits maintain several pension postretirement benefit plans require us make contributions fund benefits paid plans contributions invested benefits paid plan participants record benefit expense related plans income statement benefit expense function many factors including benefits earned year plan participants function employees salary level benefits provided plan actuarial assumptions passage time expected return plan assets recognition certain deferred gains losses well plan amendments compare benefits earned accumulated benefit obligation plans fair value assets annual basis extent plans accumulated benefit obligation exceeds fair value plan assets record minimum pension liability balance sheet equal difference two amounts record additional minimum liability less liability already accrued plan difference greater pension liability recorded balance sheet however record additional liability amount comprehensive loss net income taxes financial statements revenue recognition business segments provide number services sell variety products revenue recognition policies segment follows pipelines revenues pipelines segment derives revenues primarily transportation storage services also derive revenue sales natural gas transportation storage services recognize reservation revenues firm contracted capacity contract period regardless amount actually used interruptible volumetric based services revenues natural gas sales contracts record revenues complete delivery natural gas agreed upon delivery point natural gas injected withdrawn storage facility revenues services generally based thermal quantity gas delivered subscribed price specified contract tariff subject ferc regulations result revenues collect may refunded final order pending future rate proceeding result rate settlement establish reserves potential refunds production revenues production segment derives revenues primarily physical sales natural gas oil natural gas liquids produced revenues sales products recorded upon passage title using sales method net royalty interests profit interests produced product actual natural gas sales volumes exceed entitled share sales volumes overproduced imbalance occurs extent overproduced imbalance exceeds share remaining estimated proved natural gas reserves given property record liability costs associated transportation delivery production included cost sales field services revenues field services segment derives revenues primarily gathering processing services sale commodities retained providing services two general types services feebased makewhole feebased services recognize revenues time service rendered based upon volume gas gathered treated processed contracted fee makewhole services fee consists retainage natural gas liquids byproducts result processing recognize revenues services time sell products generally coincides provide service merchant energy revenues merchant energy segment derives revenues physical sales natural gas power management derivative contracts derivative transactions recorded fair value changes fair value reflected operating revenues see discussion income recognition policies derivatives price risk management activities revenues physical sales recognized time commodity delivered based volumes delivered contractual market price corporate revenue producing activities corporate operations primarily consist revenues telecommunications business recognize revenues metro transport collocation crossconnect services month services actually used customer environmental costs contingencies record liabilities environmental assessments indicate remediation efforts probable costs reasonably estimated recognize current period expense liability cleanup efforts benefit future periods capitalize costs benefit one accounting period except instances separate agreements legal regulatory guidelines dictate otherwise estimates liabilities based currently available facts existing technology presently enacted laws regulations taking consideration likely effects societal economic factors include estimates associated legal costs amounts also consider prior experience remediating contaminated sites companies cleanup experience data released epa organizations estimates subject revision future periods based actual costs new circumstances included balance sheet current longterm liabilities undiscounted amounts evaluate recoveries insurance coverage government sponsored programs separately liability recovery assured record report asset separately associated liability financial statements recognize liabilities contingencies exposure fully analyzed indicates probable asset impaired liability incurred amount impairment loss reasonably estimated funds spent remedy contingencies charged reserve one exists expensed range probable loss estimated accrue likely amount least minimum range probable loss price risk management activities price risk management activities consist following activities derivatives entered hedge commodity interest rate foreign currency exposures primarily natural gas oil production longterm debt derivatives related power contract restructuring business derivatives related trading activities historically entered objective generating profits exposure shifts changes market prices account derivative instruments sfas 133 accounting derivative instruments hedging activities sfas 133 derivatives reflected balance sheet fair value assets liabilities price risk management activities classify derivatives either current noncurrent assets liabilities based anticipated settlement date net derivative assets liabilities counterparties legal right offset january 1 2001 adopted sfas 133 recorded cumulativeeffect adjustment 647 million restated see note 1 net income taxes accumulated comprehensive income loss recognize fair value derivatives designated hedging instruments date majority initial cumulativeeffect adjustment related cash flow hedges anticipated sales natural gas year ended december 31 2001 602 million restated see note 1 net income taxes initial adjustment reclassified earnings result completed sales purchases year see note 15 discussion price risk management activities prior 2002 also accounted nonderivative contracts transportation storage capacity contracts physical natural gas inventories exchanges used energy trading business fair values emerging issues task force eitf issue 9810 accounting contracts involved energy trading risk management activities 2002 adopted eitf issue 023 issues related accounting contracts involving energy trading risk management activities result adjusted carrying value nonderivative instruments zero account accrual basis accounting also adjusted physical natural gas inventories used historical trading business cost lower market physical natural gas exchanges expected settlement amounts reclassified amounts inventory accounts receivable payable balance sheet upon adoption eitf issue 023 recorded loss 343 million 222 million net income taxes cumulative effect accounting change income statement 118 million adjustment natural gas inventories exchanges 225 million adjustment nonderivative instruments income statement treatment changes fair value settlements derivatives depends nature derivative instrument derivatives used hedging activities reflected either revenues expenses income statements based nature timing hedged transaction derivatives related power contract restructuring activities reflected either revenues settlements changes fair values power sales contracts expenses settlements changes fair values fuel supply agreements income statement presentation derivative contracts used historical energy trading activities reported revenue net basis revenues net expenses physically settled purchases net presentation historical trading activities began july 1 2002 adoption eitf issue 023 periods reflect presentation prior adoption reflected activities gross basis physically settled revenues separate physically settled expenses upon adoption revenues costs year ended december 31 2001 revised follows millions cash flow statement cash inflows outflows associated settlement derivative instruments recognized operating cash flows receivables payables resulting settlements reported trade receivables payables balance sheet 2002 also adopted derivatives implementation group dig issue c16 scope exceptions applying normal purchases sales exception contracts combine forward contract purchased option contract dig issue c16 requires fixedprice fuel supply contract allows buyer purchase option additional quantities fixedprice contract derivative must recorded fair value one unconsolidated affiliates midland cogeneration venture limited partnership recognized gain one fuel supply contract upon adoption new rules recorded proportionate share gain 14 million net income taxes cumulative effect accounting change income statement income taxes report current income taxes based taxable income provide deferred income taxes reflect estimated future tax payments receipts deferred taxes represent tax impacts differences financial statement tax bases assets liabilities carryovers year end account tax credits flowthrough method reduces provision income taxes year tax credits first become available reduce deferred tax assets valuation allowance based estimates likely portion assets realized future period estimates utilized recognition deferred tax assets subject revision either future periods based new facts circumstances maintain tax accrual policy record regular alternative minimum taxes companies included consolidated federal state income tax returns policy provides among things company taxable income position accrue current expense equivalent federal state income taxes ii company tax loss position accrue benefit extent deductions including general business credits utilized consolidated returns pay consolidated us federal state income taxes directly appropriate taxing jurisdictions separate tax billing agreement may bill refund subsidiaries portion income tax payments foreign currency transactions translation record currency transaction gains losses income gains losses classified income statement based upon nature transaction gives rise currency gain loss sales purchases commodities goods gains losses included operating revenue expense gains losses insignificant 2003 2002 2001 gains losses arising equity investees record gains losses equity earnings gains losses foreign denominated debt include gains losses component expense years ended december 31 2003 2002 2001 recorded net foreign currency losses 100 million 91 million 10 million primarily related currency losses eurodenominated debt us dollar functional currency majority foreign operations foreign operations whose functional currency deemed us dollar assets liabilities translated yearend exchange rates included separate component accumulated comprehensive income loss stockholders equity cumulative currency translation gain loss recorded accumulated comprehensive income loss 44 million 115 million december 31 2003 2002 revenues expenses translated average exchange rates prevailing year treasury stock account treasury stock using cost method report balance sheet reduction stockholders equity treasury stock sold issued valued firstin firstout basis included treasury stock december 31 2003 2002 approximately 17 million shares common stock held trust deferred compensation programs stockbased compensation account stockbased compensation plans using intrinsic value method provisions accounting principles board opinion apb 25 accounting stock issued employees related interpretations fixed variable compensation plans account plans using fixed variable accounting appropriate compensation expense variable plans including restricted stock grants measured using market price stock date number shares grant becomes determinable measured expense amortized income period service grant earned stock options granted fixed plan market value date grant accordingly compensation expense recognized accounted stock option grants using sfas 123 accounting stockbased compensation rather apb 25 income loss per share impacts stockbased compensation financial statements would different following shows impact net loss per share applied sfas 123 accounting asset retirement obligations january 1 2003 adopted sfas 143 requires record liability retirement removal costs longlived assets used business liability recorded estimated fair value corresponding increase property plant equipment increase property plant equipment depreciated remaining useful life longlived asset liability relates ongoing expense also recognized changes value liability result passage time record depreciation depletion amortization expense income statement first quarter 2003 recorded charge cumulative effect accounting change approximately 9 million net income taxes related adoption sfas 143 also recorded property plant equipment 208 million asset retirement obligations 222 million january 1 2003 amounts restated reflect impact reserve revisions timing settlement asset retirement obligations described note 1 asset retirement obligations associated natural gas oil wells related infrastructure production segment natural gas storage wells pipelines segment obligations plug wells production wells exhausted abandon currently forecast obligations met various times generally next ten years based expected productive lives wells estimated timing plugging abandoning wells net asset retirement liability january 1 2003 december 31 2003 reported current noncurrent liabilities balance sheet changes net liability year ended december 31 2003 follows millions changes estimate represent changes expected amount timing payments settle asset retirement obligations changes primarily result obtaining new information timing obligations plug natural gas oil wells costs adopted sfas 143 january 1 2001 aggregate current noncurrent retirement liabilities date would approximately 180 million income continuing operations net income years ended december 31 2002 2001 would lower 13 million year basic diluted earnings per share years ended december 31 2002 2001 would materially affected accounting certain financial instruments characteristics liabilities equity may 2003 financial accounting standards board fasb issued sfas 150 accounting certain financial instruments characteristics liabilities equity statement provides guidance classification financial instruments equity liabilities equity particular standard requires classify mandatorily redeemable securities liabilities balance sheet july 1 2003 adopted provisions sfas 150 reclassified 625 million capital trust coastal finance preferred interests preferred interests consolidated subsidiaries longterm financing obligations balance sheet also began classifying dividends accrued preferred interests interest debt expense income statement year ended december 31 2003 total dividends 40 million 20 million recorded interest expense 20 million recorded distributions preferred interests income statement new accounting pronouncements issued yet adopted december 31 2003 several accounting standards interpretations issued yet adopted us discussion significant standard impact us consolidation variable interest entities january 2003 fasb issued financial interpretation fin 46 consolidation variable interest entities interpretation arb 51 interpretation defines variable interest entity legal entity whose equity owners sufficient equity risk andor controlling financial interest entity standard requires company consolidate variable interest entity allocated majority entitys losses andor returns including fees paid entity december 2003 fasb issued fin 46r amended fin 46 extend effective date first quarter 2004 types entities except special purpose entities addition fin 46r also limited scope fin 46 exclude certain joint ventures entities meet characteristics businesses january 1 2004 adopted standard upon adoption deconsolidated previously consolidated entity ema power limited company owns power generation facility hungary consolidated blue lake gas storage company equity investment owns blue lake natural gas storage facility several minor entities overall impact consolidations deconsolidation described following table 3 acquisitions consolidations acquisitions 2003 acquired remaining third party interests chaparral gemstone investments began consolidating first second quarters 2003 respectively historically accounted investments using equity method accounting acquisitions discussed chaparral entered chaparral investment 1999 expand domestic power generation business chaparral owned interests 34 power plants united states total generating capacity 3470 megawatts based chaparrals interest plants primarily concentrated northeastern western united states chaparral also owned several companies longterm derivative power agreements december 31 2002 owned 20 percent chaparral remaining 80 percent owned limestone electron trust limestone 2003 paid 1175 million acquire limestones 80 percent interest chaparral limestone used 1 billion proceeds retire notes previously guaranteed us reflected chaparrals results operations income statement though acquired january 1 2003 acquired chaparral effective january 1 2002 net increases decreases income statement year ended december 31 2002 would follows millions 2003 recorded impairment investment chaparral 207 million income taxes discussed note 28 following table presents allocation purchase price chaparral assets liabilities prior consolidation prior elimination intercompany transactions allocation reflects allocation purchase price 1175 million ii carrying value initial investment 252 million iii impairment 207 million millions 1 debt recourse project contract plant relates allocation purchase price based valuations performed independent third party consultant finalized december 2003 significant changes initial purchase price allocation valuations derived using discounted cash flow analyses valuation methods valuations indicated fair value net assets purchased chaparral less purchase price paid chaparral 22 million recorded goodwill financial statements see note 2 discussion subsequent impairment goodwill gemstone entered gemstone investment 2001 finance five major power plants brazil gemstone investments three power projects macae porto velho araucaria also owned preferred interest two consolidated power projects rio negro manaus 2003 acquired thirdparty investors rabobank interest gemstone approximately 50 million gemstones results operations included consolidated financial statements since april 1 2003 acquired gemstone effective january 1 2003 net income basic diluted earnings per share year ended december 31 2003 would affected revenues operating income would higher 58 million 41 million amounts unaudited acquisition effective january 1 2002 net income basic diluted earnings per share would affected revenues operating income would higher 187 million 134 million amounts unaudited allocation purchase price assets acquired liabilities assumed upon consolidation gemstone follows millions allocation purchase price based valuations performed independent third party consultant finalized december 2003 significant changes initial purchase price allocation valuations derived using discounted cash flow analyses valuation methods prior acquisitions chaparral gemstone balances including loans notes chaparral gemstone eliminated upon consolidation result overall impact consolidated balance sheet acquiring investments different individual assets liabilities acquired overall impact acquisitions consolidated balance sheet increase consolidated assets 21 billion increase consolidated liabilities approximately 24 billion including increase consolidated debt approximately 22 billion reduction preferred interests consolidated subsidiaries approximately 03 billion consolidations second quarter 2003 amended several financing agreements connection new 3 billion revolving credit agreement see note 20 amendments completed simplify capital structure eliminating several offbalance sheet obligations replace direct obligations ii strengthen overall collateral package available financial lenders amendments discussed lakeside amended operating lease agreement lakeside technology center add guarantee benefiting party invested lessor allow third party certain lenders share collateral package provided banks new 3 billion revolving credit facility guarantee reduced investors risk loss investment resulting controlling lessor result consolidated lessor consolidation lakeside technology center resulted increase property plant equipment approximately 275 million increase longterm debt approximately 275 million additionally upon consolidation recorded asset impairment charge approximately 127 million representing difference facilitys estimated fair value residual value guarantee lease prior consolidation difference periodically expensed part operating lease expense term lease aruba amended operating lease aruba facility provide full guarantee parties invested lessor allow third party certain lenders share collateral package provided banks new credit facility guarantee reduced investors risk loss investment resulting controlling lessor result consolidated lessor increasing total property plant equipment 370 million prior impairment charge recorded assets 50 million increasing longterm debt 370 million result intent exit substantially petroleum markets operations leased assets associated debt reclassified discontinued operations sale aruba refinery closed march 2004 370 million obligation repaid proceeds sale clydesdale 2003 modified clydesdale financing arrangement convert thirdparty investors mustang investors llc preferred ownership interest one consolidated subsidiaries term loan matures equal quarterly installments 2005 also acquired 10 million preferred interest mustang guaranteed mustangs equity holders obligations result consolidated mustang increased longterm debt 743 million decreased preferred interests consolidated subsidiaries 753 million 10 million preferred interest acquired mustang eliminated upon consolidation december 2003 repaid remaining clydesdale debt obligation see notes 20 21 4 divestitures 2002 2003 2004 completed announced sale number assets investments business segments follows 1 amounts sales announced contract sale estimates subject customary regulatory approvals final sale negotiations conditions 2 sales completed 2004 3 sales 17 plants completed 2004 4 sold ownership interests ucf 2004 21 million cash affiliate bear stearns also assumed 815 million ucf debt incurred loss approximately 100 million sale 2004 1 includes 20 million costs incurred preparing assets disposal returns invested capital cash transferred assets sold 2 includes 84 million proceeds related sale asphalt facilities includes 39 million cash 27 million accounts notes receivable release 18 million previously outstanding liabilities december 2003 recorded valuation allowance 17 million receivables reducing net realizable value continue evaluate financial condition purchaser order determine whether additional valuation allowance receivables necessary 1 includes receipt 350 million series c units nonvoting class limited partnership interest gulfterra sale assets field services segment 27 million costs incurred preparing assets disposal returns invested capital cash transferred assets sold years ended december 31 2003 2002 2001 asset impairments net realized gain loss longlived assets 949 million 185 million 77 million impairments net realized loss sales investments 176 million 624 million 46 million gains losses asset impairments discussed notes 7 28 year ended december 31 2001 sold midwestern gas transmission system gulfstream pipeline project 50 percent interest stingray ut offshore pipeline systems investments empire state iroquois pipeline systems net proceeds sales approximately 279 million recognized extraordinary net gains approximately 26 million net income taxes approximately 27 million gains treated extraordinary since resulted federal trade commission ftc order connection merger 2001 coastal sfas 144 accounting impairment disposal longlived assets classify assets disposed received appropriate approvals management andor board directors met criteria held sale appropriate discontinued operations december 31 2003 2002 903 million 31 million net assets liabilities held sale reflected balance sheet net assets liabilities held sale december 31 2003 710 million related announced sales domestic power plants 193 million related announced sale south texas processing plants remaining domestic power assets approved board directors sale 2003 assets held sale december 31 2002 related 31 million gathering assets field services segment sold 2003 following table details items reflected current assets liabilities held sale balance sheets december 31 continue evaluate assets may sell otherwise divest future specific assets identified divestiture required record lower fair value less selling costs historical cost require us assess possible impairment charges generally based estimated fair value determined market data obtained divestiture process assessing probabilityweighted cash flows asset discussion impairment charges incurred longlived assets see note 7 impairments discontinued operations see note 12 impairments investments unconsolidated affiliates see note 28 5 restructuring mergerrelated costs restructuring costs part balance sheet liquidity enhancement actions taken 2002 2003 incurred certain organizational restructuring costs included operation maintenance expense january 1 2003 adopted provisions sfas 146 accounting costs associated exit disposal activities recognized restructuring costs applying provisions standard prior date recognized restructuring costs according provisions eitf issue 943 liability recognition certain employee termination benefits costs exit activity segment restructuring costs 2003 2002 follows 2003 restructuring costs incurred part ongoing liquidity enhancement cost reduction efforts employee severance costs included severance payments costs pension benefits settled curtailed existing benefit plans 2003 eliminated approximately 900 fulltime positions continuing businesses approximately 1800 positions related businesses discontinued 76 million employee severance costs continuing businesses 54 million paid december 31 2003 addition substantially costs related discontinued operations totaled 12 million paid december 31 2003 june 30 2004 incurred additional 33 million employee severance costs part ongoing liquidity enhancement cost reduction efforts contract termination costs included charges approximately 44 million related amounts paid cancelling restructuring obligations charter fifth ship transport lng supply areas domestic international market centers 2002 completed employee restructuring across operating segments resulted reduction approximately 900 fulltime positions terminations result actions incurred 37 million employee severance termination costs paid also incurred paid fees 40 million eliminate stock price credit rating triggers related chaparral gemstone investments mergerrelated costs 2001 incurred mergerrelated costs connection coastal merger follows employee severance retention transition costs include direct payments benefit costs severed employees early retirees occurred result mergerrelated workforce reduction consolidation following coastal merger completed employee restructuring across operating segments resulting reduction 3285 fulltime positions combination early retirements terminations result actions employee severance retention transition costs 2001 approximately 822 million included 214 million pension postretirement benefits paid applicable benefit periods terminated retired employees charge 278 million resulting issuance approximately 4 million shares common stock date coastal merger exchange fair value coastal employees directors stock options restricted stock total 339 employees 11 directors received shares costs expensed paid incurred transaction costs include investment banking legal accounting consulting advisory fees incurred obtain federal state regulatory approvals take actions necessary complete mergers costs expensed paid incurred business operational integration costs include charges consolidate facilities operations business segments total charges 2001 383 million primarily included 153 million related charge marktomarket loss energyrelated contract transportation capacity alliance pipeline ii 15 million incremental fees software seismic license agreements recorded production segment iii 222 million estimated leaserelated costs relocate pipeline operations detroit michigan houston texas el paso texas colorado springs colorado leaserelated costs accrued time completed relocations closed offices paid term applicable noncancelable lease agreements costs expensed paid incurred costs include payments made satisfaction obligations arising ftc approval merger coastal miscellaneous charges part ftc order related merger coastal gulfterra required sell interests seven natural gas pipeline systems dehydration facility two offshore platforms proceeds sales assets approximately 135 million resulted loss partnership approximately 25 million consideration sales committed pay gulfterra series payments totaling 29 million required contribute 40 million trust related one assets sold gulfterra expensed commitment 6 western energy settlement june 2003 entered two definitive agreements referred western energy settlement number public private claimants including states california washington oregon nevada resolve principal litigation claims regulatory proceedings us subsidiaries relating sale delivery natural gas electricity september 1996 date settlement agreements modified agreement principle entered march 20 2003 subject court regulatory approvals received settlement includes payments cash proceeds issuance common stock reduction prices power supply contract analysis obligations discounted basis definitive settlement agreements december 31 2003 upon initial agreement principle recorded initial pretax charge discounted obligation 899 million 1690 million undiscounted december 2002 upon entering definitive agreements remainder 2003 recorded increase obligation pretax charge 104 million adjustment primarily result changes timing settlement payments changes value common stock issued connection definitive settlement agreements 2003 also recorded 66 million additional charges including 51 million accretion expense discounted western energy settlement obligation charges 15 million included part operation maintenance expense income statement december 31 2003 10 million total obligation satisfied issues regarding potential tax deductibility western energy settlement charges see note 11 established escrow account amounts funded us final approval settlement agreements received december 31 2003 total amounts account 468 million reflected restricted cash balance sheet investing activity statement cash flows funded 322 million account majority net proceeds issuance senior notes july 2003 epng subsidiary issuance total 176 million shares common stock 121 million 2003 2004 made additional deposits escrow account including proceeds issuance remaining 88 million shares stock obligation approximately 74 million noted upon final approval settlement june 2004 amounts escrow released reflected addition cash flows investing activities settlement became effective june 2004 upon approximately 602 million released california claimants included 568 million previously escrowed funds 12 million prepayment portion 20 year obligation upon release amounts reduced liability reflected reduction cash flow operations second quarter 2004 june 30 2004 remaining obligation consisted 75 million power supply contract remaining term remaining 20year cash payment obligation approximately 876 million connection settlement provided collateral form natural gas oil properties secure remaining 20 year payment obligation approximately 44 million per year initial collateral requirement approximately 592 million reduced payments made 20year obligation information western energy settlement see note 22 7 loss longlived assets loss longlived assets continuing operations consists realized gains losses sales longlived assets impairments longlived assets including goodwill intangibles three years ended december 31 loss longlived assets follows net realized gain loss 2003 net realized loss primarily related 74 million loss agreement reimburse gulfterra portion future pipeline integrity costs previously sold assets see note 28 investments advances unconsolidated affiliates 67 million gain release purchase obligation chaco facility 14 million gain sale north louisiana midcontinent midstream assets field services segment well 75 million loss termination energy bridge contracts 10 million loss sale mohawk river funding merchant energy segment 2002 net realized gain primarily related 245 million net gains sales san juan gathering assets natural buttes ouray gathering systems dragon trail gas processing plant texas new mexico assets field services segment see note 4 discussion divestitures 2001 net realized losses related miscellaneous asset sales across segments asset impairments impairment charges years ended december 31 2003 2002 2001 recorded primarily based intent dispose reduce involvement number assets part liquidity enhancement efforts corporate telecommunications charge includes impairment investment wholesale metropolitan transport services primarily texas 269 million 2003 including writedown goodwill 163 million 2003 impairment lakeside technology center facility 127 million based probabilityweighted scenarios asset could sold current market 2002 incurred 168 million corporate telecommunication charges related impairment longhaul fiber network rightofway assets production charges include writedown 75 million goodwill 2003 ability recover amount impaired based decision reduce involvement canadian production operations field services charges include impairment south texas processing facilities 167 million 2003 based planned sale facilities enterprise see note 28 66 million impairment resulted decision sell north louisiana gathering facilities 2002 2003 2002 merchant energy charges primarily result plan reduce involvement lng business planned sale domestic power assets including turbines classified longterm assets additional asset impairments discontinued operations investments unconsolidated affiliates see notes 12 28 additional discussion goodwill intangibles see note 2 8 accounting changes accounting principle years ended december 31 2003 2002 recorded following cumulative effect accounting changes due adoption new accounting pronouncements millions discussion accounting principles adopted 2003 2002 see note 2 changes accounting estimate 2001 incurred approximately 316 million costs related changes accounting estimates consist 232 million additional environmental remediation liabilities 47 million additional accrued legal obligations 37 million charge reduce value spare parts inventories reflect changes usability parts worldwide operations overall pretax amount approximately 182 million costs included continuing operation maintenance costs 134 million related discontinued petroleum markets coal businesses included part discontinued operations changes estimates reduced overall net income approximately 215 million 124 million related continuing operations 91 million related discontinued operations change estimated environmental remediation liabilities due number events including sale majority retail gas stations closure gulf coast chemical midwest refining operations lease corpus christi refinery valero conforming coastals methods environmental identification assessment remediation strategies processes historical practices following merger coastal 9 ceiling test charges see note 1 discussion restatement historical reserves note 30 discussion natural gas oil reserves reserve revisions years ended december 31 2003 2002 2001 incurred ceiling test charges following full cost pools use financial instruments hedge volatility natural gas oil prices impact qualifying cash flow hedges considered determining ceiling test charges factored future ceiling test calculations charges international cost pools would materially changed impact hedges included calculating ceiling test charges since significantly hedge international production activities 2001 us charge incurred third quarter year impact qualifying cash flow hedges excluded domestic charge would increased 330 million 10 income expenses following components income expenses continuing operations three years ended december 31 1 amounts 2003 2002 primarily related net foreign currency losses eurodenominated debt 2 impaired investment costanera power plant 2002 various telecommunication investments 2001 11 income taxes pretax loss continuing operations composed following three years ended december 31 following table reflects components income tax expense benefit included loss continuing operations three years ended december 31 income tax benefit included loss continuing operations differs amount computed applying statutory federal income tax rate 35 percent following reasons three years ended december 31 following components net deferred tax liability related continuing operations december 31 upon review classification deferred tax assets determined deferred tax assets associated current liability commoditybased derivatives historically classified longterm deferred income taxes classified current asset consolidated balance sheet accordingly revised consolidated balance sheets reflect change classification revisions impact consolidated statements income cash flows comprehensive income changes stockholders equity see note 1 discussion restatement included deferred tax assets amounts related western energy settlement proposed tax legislation introduced us senate would disallow deductions certain settlements made behalf governmental entities enacted tax legislation could impact deductibility expenses related western energy settlement could result writeoff associated deferred tax assets event tax expense would increase also included deferred tax assets december 31 2003 amounts related abandonments sales certain foreign investments occurred 2003 anticipated occur 2004 december 31 2003 portion cumulative undistributed earnings foreign subsidiaries foreign corporate joint ventures recorded us income taxes approximately 835 million since earnings intended indefinitely reinvested foreign operations provision made us taxes foreign withholding taxes may applicable upon actual deemed repatriation distribution earnings made might subject foreign withholding taxes us income taxes net allowable foreign tax credits deductions however estimate taxes practicable reasons recorded provision us income taxes foreign currency translation adjustment recorded accumulated comprehensive income loss tax effects associated employees nonqualified dispositions employee stock purchase plan stock exercise nonqualified stock options vesting restricted stock well restricted stock dividends increased taxes payable 26 million 2003 reduced taxes payable 15 million 2002 31 million 2001 tax effects included additional paidin capital balance sheets december 31 2003 alternative minimum tax credits 279 million carryover indefinitely 2 million general business credit carryovers carryover periods end various times years 2009 2021 table presents details federal state net operating loss carryover periods december 31 2003 also 52 million foreign net operating loss carryovers carryover indefinitely usage us federal carryovers subject limitations provided sections 382 383 internal revenue code well separate return limitation year rules irs regulations record valuation allowance reflect estimated amount deferred tax assets may realize due uncertain availability future taxable income expiration net operating loss tax credit carryovers december 31 2003 maintained valuation allowance 5 million related estimated ability realize state tax benefits deduction charge took related western energy settlement 2 million related us federal state net operating loss carryovers 1 million related foreign tax assets ceiling test charges 1 million related general business credit carryover december 31 2002 maintained valuation allowances 22 million related foreign net operating loss carryovers 34 million related foreign deferred tax assets ceiling test charges 9 million related state tax benefits western energy settlement 6 million related us federal state net operating loss carryovers 1 million related general business credit carryover change valuation allowances december 31 2002 december 31 2003 primarily related partial reversal state tax valuation allowance related western energy settlement reversal valuation allowances certain foreign ceiling test charges foreign impairment foreign net operating loss carryover 12 discontinued operations petroleum markets operations june 2003 board directors authorized sale petroleum markets operations including aruba refinery unilube blending operations domestic international terminalling facilities petrochemical chemical plants boards actions addition previous actions approving sales eagle point refinery asphalt business florida terminal tug barge business lease crude operations based intent dispose operations required adjust assets estimated fair value result recognized pretax charges 2003 totaling 15 billion related impairment petroleum markets assets included 11 billion related aruba refinery 264 million related eagle point refinery impairments based comparison carrying value petroleum markets assets estimated fair value less selling costs first quarter 2004 completed sales aruba eagle point refineries 883 million used portion proceeds repay 370 million debt associated operations magnitude charges impacted number factors including nature assets sold established time frame completing sales among factors also recognized 90 million realized gains primarily sale florida terminalling transportation assets asphalt facilities chemical facilities 2003 2004 sold substantially petroleum markets assets coal mining operations june 2002 board directors authorized sale coal mining operations consisted fifteen active underground two surface mines located kentucky virginia west virginia following approval compared carrying value underlying assets estimated sales proceeds net estimated selling costs based bids received sales process carrying value higher estimated net sales proceeds recorded impairment charge 185 million 2002 december 2002 sold substantially reserves properties west virginia kentucky affiliate natural resources partners lp 57 million cash january 2003 sold remaining coal operations consisted mining operations businesses properties reserves kentucky west virginia 59 million included 35 million cash 24 million notes receivable record significant gain loss sales 2002 2003 petroleum markets operations coal mining operations classified discontinued operations financial statements historical periods presented assets liabilities remaining discontinued businesses classified current assets liabilities december 31 2003 summarized financial results financial position data discontinued operations follows 1 amounts include intercompany activities discontinued petroleum markets operations continuing operating segments 13 earnings per share basic diluted earnings loss per share period presented net losses continuing operations calculated basic diluted earnings loss per share amounts follows three years ended december 31 year ended december 31 2003 2002 less 1 million shares related stock options approximately 85 million shares related convertible debentures approximately 78 million shares related trust preferred securities excluded determination average common shares outstanding net losses periods additionally 2003 approximately 88 million shares related remaining stock obligation western energy settlement excluded also due net losses 2003 see note 6 information 14 financial instruments following table presents carrying amounts estimated fair values financial instruments december 31 2003 2002 amounts commoditybased price risk management activities restated reflect impact hedge revisions price risk management activities described note 1 reclassified longterm financing obligations upon adoption sfas 150 2003 december 31 2003 2002 carrying amounts cash equivalents shortterm borrowings trade receivables payables represented fair value shortterm nature instruments fair value longterm debt variable interest rates approximates carrying value marketbased nature interest rate estimated fair value debt fixed interest rates based quoted market prices similar issues see note 15 discussion methodology determining fair value derivative instruments used price risk management activities credit risk subject credit risk related financial instrument assets credit risk relates risk loss would incur result nonperformance counterparties pursuant terms contractual obligations measure credit risk estimated replacement costs commodities would purchase sell future plus amounts owed counterparties delivered unpaid commodities exposures netted legally enforceable right setoff maintain credit policies regard counterparties price risk management activities minimize overall credit risk policies require evaluation potential counterparties financial condition including credit rating ii collateral certain circumstances including cash advance letters credit guarantees iii use margining provisions standard contracts iv use master netting agreements allow netting positive negative exposures various contracts associated single counterparty use daily margining provisions financial contracts physical power agreements master netting agreements require counterparty post cash letters credit fair value contract exceeds daily contractual threshold amount typically tied published credit rating counterparty margining collateral provisions also allow us terminate contract liquidate positions counterparty unable provide required collateral margining provisions required return collateral amount posted collateral exceeds amount collateral required collateral received returned vary significantly day based changes market values counterpartys credit ratings furthermore amount collateral hold may less fair value derivative contracts counterparty given period following table presents summary counterparties net financial instrument asset exposure december 31 2003 2002 amounts restated reflect impact hedge revisions net exposure financial instrument assets related price risk management activities 1 investment grade investment grade determined using publicly available credit ratings investment grade includes counterparties minimum standard poors rating bbb moodys rating baa3 investment grade includes counterparties public credit rating meet criteria investment grade rated includes counterparties rated public rating service 2 net asset exposure financial instrument assets primarily relates assets liabilities price risk management activities exposures prepared netting assets liabilities counterparties contractual right offset positions netted include current noncurrent amounts include amounts already billed delivered derivative contracts would netted exposures approximately 100 counterparties energy marketers although counterparties currently rated investment grade one counterparties fails perform case us gen new england mirant enron see note 22 may recognize immediate loss earnings well additional financial impacts future delivery periods extent replacement contract prices quantities cannot established one electric utility customer public service electric gas company pseg comprised 66 percent 49 percent net financial instrument asset exposure december 31 2003 2002 pseg rated investment grade moodys investors services standard poors required collateral december 31 2003 2002 also one customer duke energy trading marketing llc comprised six percent net financial instrument asset exposure counterparty december 31 2003 duke also rated investment grade december 31 2003 early 2004 dukes rating lowered investment grade moodys standard poors time duke provided us letter credit concentration counterparties may impact overall exposure credit risk either positively negatively counterparties may similarly affected changes economic regulatory conditions 15 price risk management activities table derivatives designated hedges consist instruments used hedge natural gas oil production well instruments hedge interest rate currency risks longterm debt derivatives power contract restructuring activities relate power purchase sale agreements arose activities business commoditybased derivative contracts relate historical energy trading activities following table summarizes carrying value derivatives used price risk management activities december 31 2003 2002 amounts commoditybased price risk management activities restated reflect impact hedge revisions derivatives described note 1 includes 983 million net assets derivative contracts acquired connection acquisition controlling interest chaparral 2003 2 included current noncurrent assets liabilities balance sheet derivative contracts recorded financial statements fair value best indication fair value quoted market prices however quoted market prices available estimate fair value derivatives due major industry participants exiting reducing trading activities 2002 2003 availability reliable commodity pricing data marketbased sources used estimating fair value derivatives significantly limited certain locations longer time periods consequently use independent pricing source substantial amount forward pricing data beyond current twoyear period forward pricing data within two years use commodity prices marketbased sources new york mercantile exchange periods beyond two years use combination commodity prices marketbased sources forecasted settlement prices independent pricing source develop price curves use estimate value settlements future periods based contractual settlement quantities dates finally discount estimated settlement values using libor curve except described restructured power contracts additionally contracts denominated foreign currencies converted us dollars using marketbased foreign exchange spot rates record valuation adjustments reflect uncertainties associated estimates use determining fair value common valuation adjustments include market liquidity creditworthiness contractual counterparties extent possible use marketbased data together quantitative methods measure risks record valuation adjustments determine level valuation adjustments valuation techniques used valuing derivative contracts historically accounted trading activities well used hedge natural gas production adjusted method determine fair value restructured power contracts restructured power derivatives use methodology discussed determining forward settlement prices discounted using risk free interest rate adjusted individual credit spread counterparty contract additionally liquidity valuation adjustment provided derivative contracts since intended held maturity derivatives designated hedges engage two types hedging activities hedges cash flow exposure hedges fair value exposure hedges cash flow exposure primarily relate natural gas oil production hedges foreign currency interest rate risks longterm debt designed hedge forecasted sales transactions limit variability cash flows received paid related recognized asset liability hedges fair value exposure entered protect fair value recognized asset liability firm commitment enter derivative contract designate derivative either cash flow hedge fair value hedge hedges foreign currency exposure designated either cash flow hedges fair value hedges based whether interest underlying debt converted either fixed floating interest rate changes derivative fair values designated cash flow hedges deferred accumulated comprehensive income loss extent effective included income hedged transactions occur recognized earnings ineffective portion cash flow hedges change value recognized immediately earnings component operating revenues income statement changes fair value derivatives designated fair value hedges recognized earnings offsets changes fair values related hedged assets liabilities firm commitments formally document relationships hedging instruments hedged items well risk management objectives strategies undertaking various hedge transactions methods assessing testing correlation hedge ineffectiveness hedging instruments linked hedged asset liability firm commitment forecasted transaction also assess whether derivatives highly effective offsetting changes cash flows fair values hedged items discontinue hedge accounting prospectively determine derivative longer highly effective hedge decide discontinue hedging relationship discussion hedging activities follows cash flow hedges majority commodity sales purchases spot market forward market prices use futures forward contracts swaps limit exposure fluctuations commodity markets objective realizing fixed cash flow stream activities also fixed rate foreign currency denominated debt exposes us changes exchange rates foreign currency us dollar use currency swaps convert fixed amounts foreign currency due foreign currency denominated debt us dollar amounts december 31 2003 2002 converted approximately 275 million euros debt 255 million summary impacts cash flow hedges included accumulated comprehensive loss net income taxes december 31 2003 2002 follows 2002 amounts restated reflect impact hedge revisions accumulated comprehensive incomeloss described note 1 reclassifications occur upon physical delivery hedged commodity corresponding expiration hedge 2 may 2002 announced plan reduce volumes natural gas hedged production segment result removed hedging designation derivatives 3 2004 entered hedges 55 tbtu future natural gas production average price 564 per mmbtu 11 mmbbls production segments anticipated oil production average price 3515 per bbl 4 december 2002 reduced amount foreign currency exchange risk hedged eurodenominated debt result removed hedging designation derivatives 5 accumulated comprehensive income loss also includes 44 million 115 million currency translation adjustments 24 million 35 million additional minimum pension liability december 31 2003 2002 years ended december 31 2003 2002 2001 recognized net loss 2 million net loss 4 million net gain 2 million net income taxes loss continuing operations related ineffective portion cash flow hedges fair value hedges fixed rate us dollar foreign currency denominated debt exposes us paying higher market rates interest rates decline use interest rate swaps effectively convert fixed amounts interest due debt agreements variable interest payments based libor plus spread derivatives fair value loss 19 million december 31 2003 converted interest rate 350 million us dollar denominated debt floating weighted average interest rate libor plus 42 also derivatives fair value 52 million december 31 2003 converted approximately 350 million euros debt 390 million also converted interest rate debt floating weighted average interest rate libor plus 37 recorded fair value derivatives component longterm debt related accrued interest years ended december 31 2002 2001 financial statement impact fair value hedges immaterial 2004 entered new hedges converted interest rate additional 90 million us dollar denominated debt floating interest rate libor plus 43 new hedges converted another 100 million euros debt 121 million converted interest rate debt fixed rate floating interest rate libor plus 45 december 2002 reduced volumes foreign currency exchange risk hedged debt removed hedging designation derivatives net fair value gain 6 million 8 million december 31 2003 2002 amounts reflected longterm debt reclassified income interest principal debt paid 2009 power contract restructuring activities 2001 2002 conducted power contract restructuring activities involved amending terminating power purchase contracts existing power facilities restructuring transaction would eliminate requirement plant provide power generation customer contract usually regulated utility replace requirement new contract gave us ability provide power customer wholesale power market conjunction power restructuring activities merchant energys energy marketing trading division generally entered additional marketbased contracts third parties provide power wholesale power market effectively locked margin restructured transaction difference contracted rate restructured sales contract wholesale market rates purchase contract time prior restructuring power plant related power purchase contract accounted historical cost either cost construction acquired acquisition cost revenues expenses prior restructuring cases accounted accrual basis power generated sold plant following restructuring accounting treatment power purchase agreement changed since restructured contract met definition derivative addition since power plant longer exclusive obligation provide power original dedicated power purchase contract operated peaking merchant facility generating power economical significant change use plants carrying value typically written estimated fair value changes also often required us terminate amend related fuel supply andor steam agreements enter third party intercompany contracts transportation agreements associated operating merchant facility finally many cases power contract restructuring activities also involved contract terminations resulted cash payments customer cancel underlying dedicated power contract 2002 completed power contract restructuring consolidated eagle point power facility applied accounting described transaction also employed principles power contract restructuring business reaching settlement dispute nejapa power contract included cash payment us recorded payments operating revenues also terminated power contract consolidated mount carmel facility exchange 50 million cash payment year ended december 31 2002 consolidated power restructuring activities following effects consolidated financial statements millions 1 restructuring activities thirdparty owners also held ownership interests plants allocated portion income loss 2003 new power restructuring transactions completed result consolidated financial statements year ended december 31 2003 reflect change value restructured contracts power supply contracts related purchases sales contracts result credit downgrade economic changes power market longer pursuing additional power contract restructuring activities actively seeking sell otherwise dispose existing restructured power contracts june 2004 completed sale ucf restructured eagle point power contract commoditybased derivatives commoditybased derivatives primarily relate historical trading activities include services provide energy sector entered objective generating profits benefiting movements market prices primarily related purchase sale energy commodities derivatives trading portfolio fair value liability 488 million 525 million december 31 2003 2002 16 inventory following current inventory december 31 also following noncurrent inventory included assets balance sheets december 31 1 2003 2002 recorded impairment charge related turbines see note 7 17 regulatory assets liabilities regulatory assets liabilities included current noncurrent assets liabilities balance sheets balances presented balance sheets gross basis 2003 cig wic met requirements reapply provisions sfas 71 result applying standard recorded 18 million regulatory assets pretax benefit 18 million 2003 income statement addition 2 million assets 10 million liabilities reclassified regulatory assetsliabilities upon reapplication sfas 71 details regulatory assets liabilities represent regulated interstate systems apply provisions sfas 71 december 31 1 amounts included rate base earn current return 18 assets liabilities detail current noncurrent assets liabilities balance sheets december 31 19 property plant equipment december 31 2003 2002 approximately 11 billion 14 billion construction workinprogress included property plant equipment december 31 2003 2002 tgp epng anr excess purchase costs associated acquisition total excess costs pipelines approximately 5 billion accumulated depreciation approximately 1 billion excess costs amortized life related pipeline assets amortization expense three years ended december 31 2003 2002 2001 approximately 74 million 71 million 58 million adoption sfas 142 impact amounts since included part property plant equipment rather goodwill currently earn return excess purchase costs rate payers 20 debt financing obligations credit facilities debt credit facilities consist short longterm borrowings third parties notes affiliated companies 2003 entered new 3 billion revolving credit facility acquired consolidated number entities existing debt refinanced shorterterm obligations longerterm borrowings redeemed eliminated preferred interests subsidiaries summary actions follows millions 1 includes 500 million borrowings 1150 million repayments 3 billion revolving credit facility 2 amounts consolidated consequence acquisition chaparral gemstone discussed note 3 amount approximately 1640 million nonrecourse project financing contract debt 3 relates adoption sfas 150 see note 2 4 includes 571 million debt related sale east coast power 139 million related sale mohawk river funding shortterm financing obligations following shortterm borrowings financing obligations december 31 1 weightedaverage interest rate shortterm credit facilities 269 december 31 2002 longterm financing obligations longterm financing obligations outstanding consisted following december 31 2003 date 2004 following changes debt financing obligations 1 net proceeds primarily used repay maturing longterm debt redeem preferred interests consolidated subsidiaries repay shortterm borrowings financing obligations general corporate investment purposes 2 amount excludes 500 million borrowings 1150 million repayments 2003 3 billion revolving credit facility classified longterm debt 250 million repayments january 2004 classified longterm debt 3 conjunction redemption trinity river financing see note 21 obtained 12 billion two year term loan based libor term loan subsequently refinanced proceeds el paso production holding senior note issuance 4 amounts consolidated consequence acquisition chaparral gemstone discussed note 3 chaparral macae debt obligations nonrecourse debt financings 5 order simplify balance sheet improve liquidity acquired consolidated divested various entities debt obligations among actions affected debt balance discussion changes see notes 3 4 21 28 6 debt related exchange equity security units common stock aggregate maturities principal amounts longterm financing obligations next 5 years total thereafter follows millions included thereafter line table 895 million zero coupon convertible debentures maturity value 18 billion due 2021 yield maturity 4 holders cause us repurchase option years 2006 2011 2016 time elect settle cash common stock debentures convertible 8456589 shares common stock based conversion rate 47872 shares per 1000 principal amount maturity rate equal conversion price 94604 per share common stock also included thereafter line 675 million debentures holders option redeem prior stated maturity total amount 75 million redeemed 2005 600 million redeemed 2007 credit facilities april 2003 entered new 3 billion revolving credit facility 15 billion letter credit sublimit matures june 30 2005 3 billion revolving credit facility borrowing cost libor plus 350 basis points letter credit fees 350 basis points commitment fees 75 basis points unused amounts facility 3 billion revolving credit facility replaced previous 3 billion revolving credit facility also 1 billion revolving credit facility matured august 2003 financing arrangements including leases discussed notes 3 12 letters credit facilities also amended conform provisions obligations new facility 3 billion revolving credit facility financing arrangements collateralized ownership epng tgp anr cig wic anr storage company southern gas storage company series common units series c units gulfterra combined book value collateral approximately 82 billion december 31 2003 total potential exposure financing transactions assets collateralize 33 billion september 15 2004 december 31 2003 850 million borrowings outstanding 12 billion letters credit issued 3 billion revolving credit facility amounts outstanding 3 billion revolving credit facility december 31 2003 classified noncurrent balance sheet based facilitys maturity date june 30 2005 january 2004 repaid 250 million outstanding debt 3 billion revolving credit facility september 15 2004 borrowing availability facility 12 billion availability borrowings 3 billion revolving credit facility borrowing agreements subject various conditions described beginning page 150 conditions include compliance financial covenants ratios required agreements absence default agreements continued accuracy representations warranties contained agreements capital trust march 1998 formed el paso energy capital trust wholly owned subsidiary issued 65 million 475 trust convertible preferred securities 325 million common securities trust exists sole purpose issuing preferred securities investing proceeds 475 convertible subordinated debentures issued due 2028 sole asset trust sole source income interest earned debentures interest income used pay obligations trust preferred securities provide full unconditional guarantee trust preferred securities trust preferred securities nonvoting except limited circumstances pay quarterly distributions annual rate 475 carry liquidation value 50 per security plus accrued unpaid distributions convertible common shares time prior close business march 31 2028 option holder rate 12022 common shares trust preferred security equivalent conversion price 4159 per common share 2003 outstanding amounts securities reclassified longterm debt preferred interests subsidiaries result new accounting standard see note 21 coastal finance coastal finance indirect wholly owned business trust formed may 1998 coastal finance completed public offering 12 million mandatory redemption preferred securities 300 million coastal finance holds subordinated debt securities issued wholly owned subsidiary el paso cgp purchased proceeds preferred securities offering cumulative quarterly distributions paid preferred securities annual rate 8375 liquidation amount 25 per preferred security coastal finance source income interest earned subordinated debt securities interest income used pay obligations coastal finance preferred securities preferred securities mandatorily redeemable maturity date may 13 2038 may redeemed option may 13 2003 redemption price paid 25 per preferred security plus accrued unpaid distributions date redemption el paso cgp provides guarantee payment obligations coastal finance related preferred securities extent coastal finance funds available obligation provide funds coastal finance payment redemption preferred securities outside obligation pay interest principal subordinated debt securities 2003 amounts outstanding securities reclassified longterm debt preferred interests subsidiaries result new accounting standard see note 21 equity security units june 2002 issued 115 million 9 equity security units equity security units consist two securities purchase contract pay quarterly contract adjustment payments annual rate 286 requires holder buy common stock stated settlement date august 16 2005 ii senior note due august 16 2007 principal amount 50 per unit pay quarterly interest payments annual rate 614 senior notes issued total principal value 575 million pledged secure holders obligation purchase shares common stock purchase contracts december 2003 completed tender offer exchange 6057953 outstanding equity security units represented approximately 53 percent total units outstanding unit tendered holder received 25063 shares common stock cash amount 970 per equity security unit exchange issued total 15182972 shares common stock total market value 119 million paid 59 million cash upon completion tender offer comparison fair value financial instruments exchanged respective book values recorded net loss 12 million income statement associated debt component equity security units ii 45 million common stock 189 million additional paidincapital associated equity component units iii 22 million asset liability changes associated exchange remaining purchase contracts settled 2005 issue common stock time proceeds allocated common stock additional paidin capital number common shares issued depend prior consecutive 20trading day average closing price common stock determined third trading day immediately prior stock purchase date issue minimum approximately 11 million shares maximum approximately 14 million shares settlement date depending average stock price time security units issued recorded approximately 43 million noncurrent liabilities reflect present value quarterly contract adjustment payments making units offsetting reduction additional paidin capital december 31 2003 remaining amount liability 10 million quarterly contract adjustment payments allocated liability recognized date issuance interest expense based constant rate term purchase contracts accretion quarterly contract adjustment payments recorded interest expense restrictive covenants subsidiaries entered debt instruments guaranty agreements contain covenants restrictions debt levels restrictions liens securing debt guarantees restrictions mergers sales assets capitalization requirements dividend restrictions crosspayment default crossacceleration provisions breach covenants could result acceleration debt financial obligations subsidiaries 3 billion revolving credit facility significant debt covenants cross defaults ratio consolidated debt guarantees capitalization defined 3 billion revolving credit facility cannot exceed 75 percent purpose calculation allowed add back capitalization noncash impairments longlived assets including ceiling test charges exclude impact accumulated comprehensive income loss among items additionally determining debt agreements allowed exclude certain nonrecourse project finance debt among items b epng tgp anr cig subsidiaries cannot incur incremental debt incurrence incremental debt would cause debt ebitda ratio defined new 3 billion revolving credit facility agreement particular company exceed 5 1 additionally proceeds issuance debt pipeline company borrowers used maintenance expansion capital expenditures investments fercregulated assets fund working capital requirements refinance existing debt c occurrence event default expiration applicable grace period respect debt excluded items aggregate principal amount 200 million addition restrictions andor subsidiaries subject number additional restrictions covenants restrictions covenants include limitations additional debt subsidiaries limitations use proceeds borrowings subsidiaries limitations cases transactions affiliates limitations incurrence liens potential limitations abilities subsidiaries declare pay dividends potential limitations subsidiaries participate cash management program discussed note 1 restated historical financial statements reflect reduction historically reported proved natural gas oil reserves revise manner accounted certain hedges primarily associated anticipated natural gas production believe material restatement financial statements would constituted events default 3 billion revolving credit facility various financing transactions specifically provisions arrangements related representations warranties accuracy historical financial statements debt total capitalization ratio 2004 received several waivers 3 billion revolving credit facility various financing transactions address issues waivers continue effective also received extension various lenders november 30 2004 file first second quarter 2004 forms 10q expect meet unable file forms 10q date able negotiate additional extension filing deadline 3 billion revolving credit facility various transactions could accelerated part obtaining waivers also amended various provisions 3 billion revolving credit facility including provisions related events default limitation ability well subsidiaries repay indebtedness scheduled mature june 30 2005 based upon review covenants contained indentures financing agreements outstanding indebtedness acceleration 3 billion revolving credit facility could constitute event default debt agreements addition three subsidiaries indentures associated public debt contain 5 million crossacceleration provisions various financing arrangements entered us subsidiaries including el paso cgp el paso production holding company include covenants require us file financial statements within specified time periods noncompliance covenants constitute automatic event default instead agreements subject acceleration indenture trustee holders least 25 percent outstanding principal amount series debt provides notice issuer noncompliance indentures event noncompliance cured filing financial statements within specified periods time 30 90 days receipt notice depending particular indenture avoid acceleration repayment holders el paso production holding companys debt obligations waived financial filing requirements december 31 2004 filing first second quarter 2004 forms 10q subsidiaries cure events noncompliance resulting failure file financial statements subsidiaries addition neither subsidiaries received notice default caused failure file financial statements financial statements subsidiaries also impacted restatements event acceleration may unable meet payment obligations respect related indebtedness also issued various guarantees securing financial obligations subsidiaries unconsolidated affiliates similar covenants facilities furthermore material restatement financial statements period ended december 31 2001 could cause default financing agreements entered connection 950 million gemstone notes due october 31 2004 currently 748 million gemstone notes outstanding however currently expect repay notes full upon maturity october 31 2004 respect guarantees issued subsidiaries significant debt covenant addition covenants discussed el paso cgp must maintain minimum net worth 850 million breached amounts guaranteed guaranty agreements could accelerated guaranty agreements also 30 million crossacceleration provision el paso cgps net worth december 31 2003 approximately 33 billion addition three subsidiaries indentures associated public debt contain 5 million crossacceleration provisions indentures state event default occur resulting acceleration debt obligations subsidiaries excess 5 million longterm debt obligations containing provisions could accelerated acceleration debt would adversely affect liquidity position turn financial condition available capacity shelf registration statements maintain shelf registration statement sec allows us issue 3 billion securities registration statement issue combination debt equity instruments including trust preferred securities two wholly owned trusts el paso capital trust ii el paso capital trust iii issue securities trusts required issue full unconditional guarantees securities december 31 2003 999 million remaining capacity shelf registration statement however order access capacity required increase level disclosure shelf registration statement due nontimely filing annual financial statements increased disclosure could subject review securities exchange commission could result delays accessing capacity letters credit enter letters credit ordinary course operating activities december 31 2003 outstanding letters credit approximately 14 billion versus 869 million december 31 2002 14 billion outstanding letters credit approximately 12 billion outstanding 3 billion revolving credit facility included amount 06 billion letters credit securing recorded obligations related price risk management activities 02 billion letters credit associated eagle point aruba refineries sold 2004 outstanding letters credit 65 million supported cash collateral notes payable affiliates december 31 2002 notes payable affiliates 390 million included 248 million chaparral debt securities 123 million gemstone debt securities consolidated andor retired securities 2003 21 preferred interests consolidated subsidiaries past entered financing transactions accomplished sale preferred interests consolidated subsidiaries total amounts outstanding programs december 31 follows millions summarized actions 2003 related preferred interests consolidated subsidiaries millions 1 amounts reclassified longterm financing obligations result adoption sfas 150 see note 20 trinity river 1999 entered trinity river financing arrangement generate funds investment general operating purposes december 31 2002 approximately 980 million outstanding arrangement first quarter 2003 redeemed entire 980 million outstanding preferred interests arrangement portion proceeds issuance 12 billion twoyear term loan see note 20 clydesdale 2000 entered clydesdale financing arrangement generate funds investment general operating purposes december 31 2002 approximately 950 million outstanding arrangement prior april 2003 retired approximately 197 million third party member interests clydesdale april 2003 restructured clydesdale arrangement whereby remaining unredeemed preferred member interests 753 million converted term loan term loan amortized equal quarterly amounts 100 million 2005 also purchased 10 million preferred equity third party investor clydesdale mustang investors llc along financial guarantee repayment us resulted consolidation mustang second quarter 2003 consolidation resulted increase longterm debt approximately 743 million reduction preferred interests consolidated subsidiaries approximately 753 million december 2003 repaid remaining amount outstanding clydesdale term loan gemstone december 31 2002 gemstone owned 300 million preferred securities two consolidated subsidiaries second quarter 2003 acquired 100 percent interest holder preferred interests began consolidating equity holder result consolidation eliminated preferred interest see note 3 coastal securities company preferred stock 1996 coastal securities company limited wholly owned subsidiary issued 4 million shares preferred stock 100 million cannon investors trust entity comprised consortium banks generate funds investment general operating purposes december 2003 redeemed entire 100 million outstanding preferred interests paid accrued unpaid dividends el paso tennessee preferred stock 1996 el paso tennessee pipeline co subsidiary issued 6 million shares publicly registered 825 cumulative preferred stock par value 50 per share 300 million preferred stock redeemable option redemption price equal 50 per share plus accrued unpaid dividends time el paso tennessee pipeline co indirectly owns tennessee gas pipeline company marketing trading businesses substantially domestic international power businesses required following financial information intended provide additional information el paso tennessee pipeline co preferred security holders 22 commitments contingencies legal proceedings government investigations western energy settlement june 2003 announced executed master settlement agreement msa resolve principal litigation relating sale delivery natural gas andor electricity western united states msa became effective june 2004 msa along separate settlement agreements settled california lawsuits state courts california public utilities commission cpuc proceeding ferc california attorney general investigation discussed herein parties settlement agreements include private class action litigants california governor lieutenant governor california attorneys general california washington oregon nevada cpuc california electricity oversight board california department water resources pacific gas electric company pge southern california edison company five california municipalities six nonclass private plaintiffs discussion charges taken connection western energy settlement well amounts released settling parties remaining obligations settlement see note 6 msa agreed following terms made cash payments totaling 955 million benefit parties definitive settlement agreements subsequent signing agreements amount represents originally announced 102 million cash payment less credits amounts paid settling parties paid amounts equal proceeds issuance approximately 264 million shares common stock behalf settling parties proceeds sales 2003 2004 totalling approximately 195 million deposited escrow account benefit settling parties deposited approximately 250 million escrow benefit settling parties within 180 days signing definitive settlement agreements pay 45 million cash per year semiannual payments 20year period longterm payment obligation direct obligation el paso corporation el paso merchant energy lp epme guaranteed subsidiary epng required provide collateral obligation form natural gas oil reserves posted oil gas collateral collateralize payment obligations june 2004 upon effectiveness msa epme agreed receive reduced payments due power supply transaction california department water resources total 125 million pro rated monthly basis remaining 30 month term transaction difference current payments reduced payments prior effectiveness msa placed escrow benefit settling parties monthly basis upon effectiveness actual payments epme delivered power made reduced amounts msa addition joint settlement agreement jsa announced earlier june 2003 agreed provide structural relief settling parties jsa agreed following subject conditions settlement 1 make 329 bcfd primary firm pipeline capacity epng system available california delivery points five year period date settlement shippers sign firm contracts 329 bcfd capacity california delivery points 2 maintain facilities sufficient deliver 329 bcfd california delivery points 3 add firm incremental load epng system would prevent satisfying obligation provide capacity construct new 320 mmcfd line 2000 powerup expansion project forego recovery cost service expansion epngs next rate case ferc clarify rights northern california shippers recall epngs system capacity block ii capacity serve markets pges service area limited exceptions bar affiliated companies obtaining additional firm capacity epng pipeline system five year period effective date settlement june 2003 anticipation execution msa el paso cpuc pge southern california edison company city los angeles filed jsa described ferc resolution cpuc complaint proceeding discussed november 2003 ferc approved jsa minor modifications east california shippers filed requests rehearing denied ferc march 30 2004 certain shippers appealed fercs ruling us court appeals district columbia defendant number additional lawsuits pending several western states relating various aspects 20002001 western energy crisis believe additional lawsuits either individually aggregate material impact us shareholder class action suits beginning july 2002 twelve purported shareholder class action lawsuits alleging violations federal securities laws filed us several former officers eleven lawsuits consolidated federal court houston single judge twelfth lawsuit filed southern district new york dismissed light similar claims asserted consolidated suits houston lawsuits generally challenge accuracy completeness press releases public statements made 2001 2002 two shareholder derivative actions also filed generally allege claims made consolidated shareholder class action lawsuits one filed federal court houston august 2002 consolidated shareholder class actions pending houston stayed second shareholder derivative lawsuit filed delaware state court october 2002 generally alleges claims made consolidated shareholder class action lawsuit also stayed two shareholder derivative lawsuits consolidated state court houston generally allege manipulation california gas supply gas prices exposed us claims antitrust conspiracy ferc penalties erosion share value costs legal exposure related lawsuits claims currently determinable beginning february 2004 seventeen purported shareholder class action lawsuits alleging violations federal securities laws filed us several individuals federal court houston lawsuits generally allege reporting natural gas oil reserves materially false misleading lawsuits recently consolidated shareholder lawsuits described immediately preceding paragraph amended complaint consolidated securities lawsuit filed july 2 2004 september 2004 new derivative lawsuit filed federal court houston certain el pasos current former directors officers claims new derivative lawsuit part claims made june 2004 consolidated amended complaint securities lawsuit one distinction derivative lawsuit includes claim disgorgement sarbanesoxley act 2002 certain individually named defendants erisa class action suit december 2002 purported class action lawsuit filed federal court houston alleging generally direct indirect communications participants el paso corporation retirement savings plan included misrepresentations omissions caused members class hold maintain investments el paso stock violation employee retirement income security act erisa lawsuit recently amended include allegations relating reporting natural gas oil reserves costs legal exposure related lawsuit currently determinable however believe matter covered insurance cpuc complaint proceeding docket rp00241000 april 2000 cpuc filed complaint section 5 natural gas act nga ferc alleging epngs sale approximately 12 bcf capacity affiliate epme raised issues market power violation fercs marketing affiliate regulations asked contracts voided spring summer 2001 hearings held alj address market power issue affiliate issue november 19 2003 ferc approved jsa part western energy settlement vacated aljs initial decisions decision upheld ferc order issued march 30 2004 april 9 2004 certain shippers appealed ferc orders matter us court appeals district columbia circuit governmental reviews october 2003 announced sec authorized staff fort worth regional office conduct investigation certain aspects periodic reports filed sec investigation appears focused principally power plant contract restructurings related disclosures accounting treatment restructured power contracts including particular eagle point restructuring transaction completed 2002 cooperating sec investigation wash trades june 2002 received informal inquiry sec regarding issue round trip trades although believe round trip trades occurred submitted data sec july 2002 july 2002 received federal grand jury subpoena documents concerning round trip wash trades complied requests also cooperating us attorney regarding investigation specific transactions executed connection production hedges price reporting october 2002 ferc issued data requests regarding price reporting transactional data energy trade press provided information ferc commodity futures trading commission cftc us attorney response requests first quarter 2003 announced settlement epme cftc price reporting matter providing payment epme civil monetary penalty 20 million 10 million payable 2006 without admitting denying cftc holdings order continuing cooperate us attorneys investigation matter reserve revisions march 2004 received subpoena sec requesting documents relating reserve revisions also received federal grand jury subpoenas documents regard reserve revisions cooperating sec us attorney investigations matter cftc investigation april 2004 affiliates elected voluntarily cooperate cftc connection cftcs industrywide investigation activities affecting price natural gas fall 2003 specifically affiliates provided information relating storage reports provided energy information administration period october 2003 december 2003 august 30 2004 cftc announced completed investigation found evidence wrongdoing iraq oil sales september 2004 coastal corporation el paso cgp company received subpoena grand jury us district court southern district new york produce records regarding united nations oil food program governing sales iraqi oil subpoena seeks various records relating transactions oil iraqi origin period 1995 2003 others energy industry received similar subpoenas carlsbad august 2000 main transmission line owned operated epng ruptured crossing pecos river near carlsbad new mexico twelve individuals site fatally injured june 20 2001 us department transportations office pipeline safety issued notice probable violation proposed civil penalty epng notice alleged five violations dot regulations proposed fines totaling 25 million proposed corrective actions epng fully accrued fines october 2001 epng filed response office pipeline safety disputing alleged violations december 2003 matter referred department justice public hearing conducted national transportation safety board ntsb investigation carlsbad rupture ntsb published final report april 2003 ntsb stated determined probable cause august 2000 rupture significant reduction pipe wall thickness due severe internal corrosion occurred epngs corrosion control program failed prevent detect control internal corrosion pipeline ntsb also determined ineffective federal preaccident inspections contributed accident identifying deficiencies epngs internal corrosion control program november 1 2002 epng received federal grand jury subpoena documents related carlsbad rupture cooperated fully responding subpoena since expired december 2003 january 2004 eight current former employees served testimonial subpoenas issued grand jury six individuals testified march 2004 april 2 2004 epng received new federal grand jury subpoena requesting additional documents responded fully subpoena two additional employees testified grand jury june 2004 number personal injury wrongful death lawsuits filed epng connection rupture lawsuits settled settlement payments fully covered insurance connection settlement cases epng contributed 10 million charitable foundation memorial families involved contribution covered insurance parties four settled lawsuits since filed additional lawsuit titled diane heady et al v epec epng harris county texas november 20 2002 seeking additional sums based upon interpretation earlier settlement agreements agreement principle reached resolve issues parties addition lawsuit entitled baldonado et al v epng filed june 30 2003 state court eddy county new mexico behalf 23 firemen ems personnel responded fire allegedly suffered psychological trauma case dismissed trial court appeals court initially issued notice dismissing claims decision appealed appeals court agreed hear matter briefs filed end year believe decision may appealed costs legal exposure related baldonado lawsuit currently determinable however believe matter fully covered insurance grynberg number subsidiaries named defendants actions filed 1997 brought jack grynberg behalf us government false claims act generally complaints allege industrywide conspiracy underreport heating value well volumes natural gas produced federal native american lands deprived us government royalties plaintiff case seeks royalties contends government received volume heating value differently measured analyzed calculated reported together interest treble damages civil penalties expenses future injunctive relief require defendants adopt allegedly appropriate gas measurement practices monetary relief specified case matters consolidated pretrial purposes natural gas royalties qui tam litigation us district court district wyoming filed june 1997 discovery proceeding costs legal exposure related lawsuits claims currently determinable price formerly quinque number subsidiaries named defendants price et al v gas pipelines predecessors et al filed 1999 district court stevens county kansas plaintiffs allege defendants mismeasured natural gas volumes heating content natural gas nonfederal nonnative american lands seek recover royalties contend received volume heating value natural gas produced properties differently measured analyzed calculated reported together prejudgment postjudgment interest punitive damages treble damages attorneys fees costs expenses future injunctive relief require defendants adopt allegedly appropriate gas measurement practices monetary relief specified case plaintiffs motion class certification nationwide class natural gas working interest owners natural gas royalty owners denied april 10 2003 plaintiffs granted leave file fourth amended petition narrows proposed class royalty owners wells kansas wyoming colorado removes claims heating content second class action since filed heating content claims costs legal exposure related lawsuits claims currently determinable mtbe compliance 1990 amendments clean air act use gasoline additive methyl tertiarybutyl ether mtbe gasoline also produced bought sold distributed mtbe number lawsuits filed throughout us regarding mtbes potential impact water supplies subsidiaries currently one several defendants 50 lawsuits nationwide consolidated pretrial purposes multidistrict litigation us district court southern district new york plaintiffs generally seek remediation groundwater prevention future contamination variety compensatory damages punitive damages attorneys fees court costs legal exposure related lawsuits claims currently determinable addition matters subsidiaries affiliates named defendants numerous lawsuits governmental proceedings arise ordinary course business also regulatory rules orders various stages adoption review andor implementation none believe material impact us outstanding legal matters evaluate merits case exposure matter possible legal settlement strategies likelihood unfavorable outcome determine unfavorable outcome probable estimated establish necessary accruals information becomes available relevant developments occur adjust accrual amounts accordingly still uncertainties related ultimate costs may incur based upon evaluation experience date believe current reserves adequate december 31 2003 approximately 12 billion accrued outstanding legal matters includes accruals related western energy settlement environmental matters subject federal state local laws regulations governing environmental quality pollution control laws regulations require us remove remedy effect environment disposal release specified substances current former operating sites december 31 2003 accrued approximately 412 million including approximately 400 million expected remediation costs associated onsite offsite groundwater technical studies approximately 12 million related environmental legal costs anticipate incurring 2027 412 million accrual 179 million reserved facilities currently operate 233 million reserved nonoperating sites facilities shut sold superfund sites reserve estimates range approximately 412 million approximately 632 million accrual represents combination two estimation methodologies first likely outcome reasonably estimated cost accrued 94 million second likely outcome cannot estimated range costs established 318 million 538 million lower end range accrued type site reserves based following estimates reasonably possible outcomes reconciliation accrued liability december 31 2003 millions 2004 estimate total remediation expenditures approximately 68 million addition expect make capital expenditures environmental matters approximately 86 million aggregate years 2004 2008 expenditures primarily relate compliance clean air regulations internal pcb remediation project since 1988 tgp subsidiary engaged internal project identify address presence polychlorinated biphenyls pcbs substances including epa list hazardous substances hsl compressor stations facilities operates conducting project tgp frequent contact federal state regulatory agencies informal negotiation formal entry consent orders tgp executed consent order 1994 epa governing remediation relevant compressor stations working epa relevant states regarding remediation activities tgp also working pennsylvania new york environmental agencies regarding remediation postremediation activities pennsylvania new york stations may 2003 finalized new estimate cost complete pcbhsl project years developments impacted various individual components ability estimate likely outcome total project possible recently new estimate identified 31 million reduction estimated cost complete project pcb cost recoveries may 1995 following negotiations customers tgp filed agreement ferc established mechanism recovering substantial portion environmental costs identified internal remediation project agreement approved ferc november 1995 provided pcb surcharge firm interruptible customers rates pay eligible remediation costs surcharges collected defined collection period tgp received approval ferc extend collection period currently set expire june 2006 agreement also provided biannual audits eligible costs december 31 2003 tgp precollected pcb costs approximately 119 million precollected amount reduced future eligible costs incurred remainder remediation project extent actual eligible expenditures less amounts precollected tgp refund customers difference plus carrying charges incurred date refunds december 31 2003 tgp recorded regulatory liability included noncurrent liabilities balance sheet 87 million estimated future refund obligations cercla matters received notice could designated asked information determine whether could designated potentially responsible party prp respect 62 active sites comprehensive environmental response compensation liability act cercla state equivalents sought resolve liability prp sites indemnification thirdparties settlements provide payment allocable share remediation costs december 31 2003 estimated share remediation costs sites 32 million 44 million since cleanup costs estimates subject revision information becomes available extent remediation required cases asserted defense liability estimates could change moreover liability federal cercla statute joint several meaning could required pay excess pro rata share remediation costs understanding financial strength prps considered appropriate estimating liabilities accruals issues included previously indicated estimates superfund sites possible new information future developments could require us reassess potential exposure related environmental matters may incur significant costs liabilities order comply existing environmental laws regulations also possible developments increasingly strict environmental laws regulations claims damages property employees persons environment resulting current past operations could result substantial costs liabilities future information becomes available relevant developments occur adjust accrual amounts accordingly still uncertainties relating ultimate costs may incur based upon evaluation experience date believe current reserves adequate enron bankruptcy december 2001 enron corp number subsidiaries including enron north america corp ena enron power marketing inc epmi filed chapter 11 bankruptcy protection new york various contracts enron marketing trading entities tradingrelated contracts terminated due bankruptcy october 2002 filed proofs claims enron trading entities totaling approximately 317 million sold 244 million original claims third party enron also maintained el paso merchant energypetroleum owed approximately 3 million epme owed epmi 46 million due termination petroleum physical power contracts cases maintained due contractual setoff rights money owed enron parties additionally epme maintained epmi owed epme 30 million due termination physical power contract included 317 million filed claims epmi filed lawsuit epme guarantor el paso corporation based alleged 46 million liability june 24 2004 bankruptcy court approved settlement agreement enron resolved foregoing issues well trading merchant issues parties european trading businesses also asserted 20 million claims enron capital trade resources limited subject separate proceedings united kingdom addition corresponding claim enron corp based corporate guarantee considering valuation setoff arguments reserves established believe overall exposure enron 3 million addition various enron subsidiaries transportation contracts several pipeline systems transportation contracts rejected pipeline subsidiaries filed proofs claim totaling approximately 137 million epng filed largest proof claim amount approximately 128 million included 18 million amounts due services provided date contracts rejected 110 million damage claims arising rejection transportation contracts epng expects enron vigorously contest claims given uncertainty bankruptcy process results uncertain fully reserved amounts due date contracts rejected recognized amounts contracts since rejection date duke litigation citrus trading corporation ctc direct subsidiary citrus corp citrus filed suit duke energy lng sales inc duke panenergy corp holding company duke seeking damages 185 million breach gas supply contract wrongful termination contract duke sent ctc notice termination gas supply contract alleging failure ctc increase amount outstanding letter credit collateral purchase obligations duke filed federal court amended counter claim joining citrus cross motion partial summary judgment requesting court find duke right terminate gas sales contract ctc due failure ctc adjust amount letter credit supporting purchase obligations ctc filed answer dukes motion currently pending court economic conditions brazil investments power pipeline production assets brazil aggregate exposure including financial guarantees approximately 16 billion 2002 brazil experienced significant decline financial markets due largely concerns refinancing foreign debt presidential elections completed late november 2002 concerns contributed significantly higher interest rates 2002 local debt government private sectors significantly decreased availability funds lenders outside brazil decreased amount foreign investment country addition government may impose attempt impose changes could affect investments including imposing price controls electricity fuels attempting force renegotiation power purchase agreements ppas provide partial protection local currency devaluation attempting impose concessions developments delayed may continue delay implementation project financings planned underway brazil although raised 420 million nonrecourse debt macae power project february 2004 currently believe economic difficulties brazil material adverse effect investment country continue monitor economic situation potential changes governmental policy working statecontrolled utilities brazil counterparties projects ppas attempt maintain economic returns anticipated made investments specific difficulties experiencing brazil discussed 60 percent interest 484 mw gasfired power project known araucaria project located near curitiba brazil project company ownership interest 20year ppa regional utility currently international arbitration litigation curitiba courts curitiba court ruled arbitration clause ppa invalid enjoined project company prosecuting arbitration penalty approximately 173000 daily fines project company appealing ruling obtained stay order imposition daily fines pending outcome appeal investment araucaria project 181 million december 31 2003 based future outcome dispute ppa could required write value investment two projects located manaus brazil first project 238 mw fueloil fired plant known manaus project net book value 104 million december 31 2003 second project 158 mw fueloil fired plant known rio negro project net book value plant equipment 108 million december 31 2003 manaus projects ppa currently expires january 2005 rio negro projects ppa currently expires january 2006 first quarter 2003 manaus project began experiencing delays payment purchaser power manaus energia sa fourth quarter 2003 contractual issues resolved payment schedule established followed payments arrears past due payments collected march 2004 december 31 2003 accounts receivable manaus project 19 million addition filed lawsuit brazilian courts manaus energia rio negro project regarding tariff dispute related power sales 1999 2003 additional longterm receivable 32 million subject lawsuit result changes brazilian political environment early 2004 manaus energia issued request power supply proposals 450 mw 525 mw net generating capacity 2005 2006 bid qualifications issued manaus energia may prohibit us supplying power manaus rio negro projects filed administrative legal challenges bid qualifications intend submit bid nongovernmental organization obtained preliminary injunction enjoining manaus energia proceeding bid process decision merits complaint made based expected results bid process impact future outcome negotiations extend term ppas recorded impairment charge approximately 135 million first quarter 2004 based future outcome lawsuit related 32 million receivable could required provide allowance receivable discussed 50 percent interest 404 mw dualfuelfired power project known porto velho project located porto velho brazil porto velho project two ppas first ppa term ten years relates first phase project second ppa term 20 years relates second 345 mw phase project negotiating certain provisions ppas eletronorte including amount installed capacity energy prices take pay levels term first ppa issues although current terms ppas proposed amendments indicate impairment investment 283 million december 31 2003 may required write value investment negotiations resolved unfavorably outcome matters cannot predicted certainty believe established appropriate reserves matters however possible new information future developments could require us reassess potential exposure related matters adjust accruals accordingly impact changes may material effect results operations financial position cash flows periods events occur commitments purchase obligations operating leases maintain operating leases ordinary course business activities leases include office space operating facilities office operating equipment terms agreements vary 2004 2053 december 31 2003 total commitments operating leases approximately 488 million minimum annual rental commitments operating leases december 31 2003 follows aggregate minimum commitments reduced minimum sublease rentals approximately 16 million due future noncancelable subleases rental expense operating leases years ended december 31 2003 2002 2001 72 million 146 million 94 million may 2004 announced would consolidate houstonbased operations one location anticipate consolidation substantially complete end 2004 result established establish accrual record liability obligations terms leases period space vacated available subleasing currently lease approximately 912000 square feet office space buildings vacating various leases lease terms expiring 2004 2014 estimate total accrual space approximately 80 million 100 million expenses related relocation expensed period incurred guarantees involved various joint ventures ownership arrangements sometimes require additional financial support results issuance financial performance guarantees financial guarantee obligated make payments guaranteed party fails make payments violates terms financial arrangement performance guarantee provide assurance guaranteed party execute terms contract required perform behalf december 31 2003 approximately 277 million financial performance guarantees otherwise reflected financial statements also periodically provide indemnification arrangements related assets businesses sold arrangements include indemnification income taxes resolution existing disputes environmental matters necessary expenditures ensure safety integrity assets sold cases evaluate time guaranty entered period thereafter whether liability exists estimated record accruals criteria met december 31 2003 accrued 78 million related arrangements commercial commitments various commercial commitments purchase obligations recorded balance sheet december 31 2003 firm commitments tolling transportation storage capacity contracts 18 billion commodity purchase commitments 361 million purchase capital commitments including maintenance engineering procurement construction contracts 429 million included purchase capital commitments purchase obligation entered 2003 acquire pipe equipment used cheyenne plains pipeline project totaling 136 million paid 2004 23 retirement benefits pension benefits primary pension plan defined benefit plan covers substantially us employees provides benefits cash balance formula certain employees participated prior pension plans el paso sonat coastal receive greater cash balance benefits transition benefits prior plan formulas transition benefits reflect prior plan accruals employees december 31 2001 december 31 2004 march 31 2006 anticipate making contributions pension plan 2004 addition primary pension plan maintain supplemental executive retirement plan serp provides benefits selected officers key management serp provides benefits excess certain irs limits essentially mirror primary pension plan also maintain two pension plans closed new participants provide benefits former employees previously discontinued coal convenience store operations serp frozen plans together referred pension plans also participate one multiemployer pension plan benefit employees union members contributions plan 2003 2002 2001 material expect contribute 6 million serp 2004 anticipate making contributions pension plans 2004 2001 offered early retirement incentive program associated pension plans eligible employees coastal program offered enhanced pension benefits individuals elected early retirement net charges incurred connection program approximately 137 million 2001 2003 11 million charges primary pension plan resulted employee terminations internal reorganization retirement savings plan maintain defined contribution plan covering us employees prior may 1 2002 matched 75 percent participant basic contributions 6 percent matching contribution made plans stock fund participants could diversify time may 1 2002 plan amended allow company matching contributions invested manner participant contributions effective march 1 2003 suspended matching contribution reinstituted rate 50 percent participant basic contributions 6 percent july 1 2003 effective july 1 2004 increased matching contribution 75 percent participant basic contributions 6 percent result el paso current sec filings plan committee temporarily suspended participants making future contributions transferring investment funds el paso corporation stock fund effective june 25 2004 temporary suspension affect participants ability maintain transfer investment may currently el paso corporation stock fund participants may continue sell stock currently held el paso corporation stock fund discretion subject insider trading restrictions soon el paso completes required sec filings compliance sec requirements participants able invest el paso corporation stock fund amounts expensed plan approximately 14 million 28 million 30 million years ended december 31 2003 2002 2001 postretirement benefits provide postretirement medical benefits closed groups retired employees limited postretirement life insurance benefits current retired employees postretirement employee benefits opeb prefunded extent costs recoverable rates extent actual opeb costs regulated pipeline companies differ amounts recovered rates regulatory asset liability recorded expect contribute 59 million postretirement plans 2004 medical benefits closed groups retirees may subject deductibles copayment provisions limitations dollar caps amount employer costs reserve right change benefits 2001 offered onetime election continue benefits postretirement medical life plans early retirement incentive program eligible employees coastal net charges incurred coastal program approximately 65 million december 8 2003 medicare prescription drug improvement modernization act 2003 signed law benefit obligations costs reported related prescription drug coverage reflect impact legislation current accounting standards effective 2004 may require changes previously reported benefit information projected benefit obligation accumulated benefit obligation fair value plan assets september 30 plan measurement date related balance sheet accounts pension plans december 31 information pension plans accumulated benefit obligations excess plan assets year ended december 31 required recognize additional minimum liability pension plans accumulated benefit obligation excess plan assets recorded comprehensive income loss 18 million 2003 55 million 2002 related change additional minimum liability change projected benefit obligation change plan assets reconciliation funded status pension postretirement benefit plans benefits presented computed twelve months ended september 30 1 unrecognized net actuarial loss september 30 2003 year ended december 31 2003 primarily result decrease discount rate used actuarial calculation lower actual returns plan assets compared expected return 2002 recognize difference actual return expected return three year period permitted sfas 87 portion postretirement benefit obligation included current liabilities 45 million 35 million december 31 2003 2002 years ended december 31 components net benefit cost income follows 1 permitted amortization prior service cost determined using straightline amortization cost average remaining service period employees expected receive benefits plan projected benefit obligations net benefit cost based actuarial estimates assumptions following table details weightedaverage actuarial assumptions used determining projected benefit obligation net benefit cost pension postretirement plans 2003 2002 2001 1 expected return plan assets pretax rate tax rate 27 percent postretirement benefits primarily based expected riskfree investment return adjusted historical risk premiums specific risk adjustments associated debt equity securities expected returns weighted based target asset allocations investment portfolio 2004 assumed expected return assets pension benefits reduced 850 actuarial estimates postretirement benefit plans assumed weightedaverage annual rate increase per capita costs covered health care benefits 100 percent 2003 gradually decreasing 55 percent year 2008 assumed health care cost trends significant effect amounts reported postretirement benefit plans onepercentage point change assumed health care cost trends would following effects september 30 plan assets following table provides target actual asset allocations pension postretirement benefit plans september 30 1 actuals pension plans include 33 million 15 percent total assets 39 million 18 percent total assets common stock september 30 2003 september 30 2002 primary investment objective plans ensure longterm life plans adequate pool sufficiently liquid assets support benefit obligations participants retirees beneficiaries exists meeting objective plans seek achieve high level investment return consistent prudent level portfolio risk investment objectives longterm nature covering typical market cycles three five years shortfall investment performance compared investment objectives result general economic capital market conditions late 2003 modified target asset allocations postretirement benefit plans increase equity allocation 65 percent total plan assets result actual assets september 30 2003 yet adjusted reflect allocation change 2004 modified target actual asset allocations pension plans reduce equity allocation 60 percent total plan assets correspondingly 2004 assumption related expected return plan assets reduced 880 850 reflect change 24 capital stock common stock november december 2003 issued 176 million shares common stock approximately 121 million partial satisfaction western energy settlement obligation january 2004 issued 88 million shares common stock 74 million satisfy remaining stock obligation settlement also issued approximately 15 million shares part offer exchange equity security units december 2003 common stock discussion see note 20 dividend year ended december 31 2003 paid dividends 203 million common stockholders date 2004 paid dividends 74 million common stock july 16 2004 declared quarterly dividends 004 per share common stock payable october 4 2004 shareholders record september 3 2004 el paso tennessee pipeline co subsidiary paid dividends 2003 approximately 25 million series cumulative preferred stock 825 per annum 20625 per quarter date 2004 eptp paid dividends approximately 12 million declared quarterly dividend september 7 2004 payable september 30 2004 25 stockbased compensation grant stock awards various stock option plans account stock option plans using accounting principles board opinion 25 related interpretations employee plans may issue incentive stock options common stock intended qualify section 422 internal revenue code nonqualified stock options restricted stock appreciation rights phantom stock options performance units nonemployee director plan may issue deferred shares common stock reserved approximately 68 million shares common stock existing future stock awards including deferred shares december 31 2003 approximately 29 million shares remained unissued nonqualified stock options granted nonqualified stock options employees 2003 2002 2001 stock options contractual terms 10 years generally vest completion one five years continuous employment grant date also granted options nonemployee members board directors fair market value grant date exercisable immediately except special circumstances summary stock option transactions stock options outstanding stock options exercisable december 31 presented 1 includes conversion common stock cash stock options cost employees based upon achievement certain performance targets lapse time options original stated exercise approximately 42 per share following table summarizes range exercise prices weightedaverage remaining contractual life options outstanding range exercise prices options exercisable december 31 2003 fair value stock option granted used complete pro forma net income disclosures see note 2 estimated date grant using blackscholes optionpricing model following weightedaverage assumptions restricted stock stockbased compensation plans limited number shares restricted common stock may granted officers employees shares carry voting dividend rights however sale transfer shares restricted stock awards vest specific period time andor achieve established performance targets restricted stock awards representing 04 million 14 million 23 million shares granted 2003 2002 2001 weightedaverage grant date fair value 746 3845 6210 per share december 31 2003 23 million shares restricted stock outstanding value restricted shares subject performance vesting determined based fair market value date performance targets achieved value charged compensation expense ratably required service restriction period value time vested restricted shares determined issuance date cost amortized compensation expense period service 2003 2002 2001 charges totaled 64 million 73 million 67 million included deferred compensation december 31 2003 23 million related options converted automatically common stock end vesting period performance units past awarded eligible officers performance units payable cash stock end vesting period final value performance units may vary according plan granted usually based common stock price end vesting period total shareholder return vesting period relative peer group value performance units charged ratably compensation expense vesting period periodic adjustments account fluctuation market price stock changes expected total shareholder return amounts recorded compensation expense 2002 2001 11 million 64 million 2001 expense includes 51 million charge pay outstanding phantom stock options 2002 reduced performance unit liability 21 million due reduction expected total shareholder return july 2003 outstanding performance units vested threshold level compensation committee board directors determined would payout performance units accordingly reversed remaining liability units recorded income 16 million employee stock purchase program october 1999 implemented employee stock purchase plan section 423 internal revenue code plan allowed participating employees right purchase common stock quarterly basis 85 percent lower market price beginning end calendar quarter five million shares common stock authorized issuance plan years ended december 31 2002 2001 sold 14 million 03 million shares common stock employees effective january 1 2003 suspended employee stock purchase program 26 segment information segregate business activities four operating segments pipelines production field services merchant energy segments strategic business units provide variety energy products services managed separately business unit requires different technology marketing strategies pipelines production merchant energy segment information years ended december 31 2002 2001 restated discussed note 1 restatement historical financial statements 2002 2003 reclassified petroleum markets coal mining operations merchant energy segment discontinued operations financial statements merchant energys operating results periods reflect change pipelines segment provides natural gas transmission storage related services primarily us conduct activities primarily seven wholly owned five partially owned interstate transmission systems along five underground natural gas storage entities lng terminalling facility production segment engaged exploration acquisition development production natural gas oil natural gas liquids primarily north america us production onshore coal seam operations properties 20 states offshore operations properties federal state waters gulf mexico internationally exploration production rights australia bolivia brazil canada hungary indonesia turkey field services segment owns interests 22 processing plants related gathering facilities located south texas south louisiana well ownership interest gulfterra merchant energy segment owns interests domestic international power assets conducts energy marketing trading activities held developing merchant lng business activities buy sell trade natural gas power crude oil energy commodities throughout world interests 68 power plants 16 countries customers whose revenues exceeded 10 percent total revenues 2003 2002 2001 use ebit assess operating results effectiveness business segments define ebit net income loss adjusted items impact income loss continuing operations extraordinary items discontinued operations impact accounting changes ii income taxes iii interest debt expense iv distributions preferred interests consolidated subsidiaries business operations consist consolidated businesses well substantial investments unconsolidated affiliates believe ebit useful investors allows effectively evaluate performance businesses investments also exclude interest debt expense distributions preferred interests consolidated subsidiaries investors may evaluate operating results without regard financing methods capital structure ebit may comparable measures used companies additionally ebit considered conjunction net income performance measures operating income operating cash flow reconciliation ebit loss continuing operations three years ended december 31 following tables reflect segment results three years ended december 31 1 includes corporate telecommunication activities eliminations intercompany transactions intersegment revenues along intersegment operating expenses incurred normal course business operating segments record intersegment revenue operation maintenance expense elimination included corporate column remove intersegment transactions losses reflected corporate activities include approximately 396 million related impairment telecommunication business second quarter 2003 inclusive writedown goodwill 163 million see note 2 additional discussion impairment 2 revenues external customers include gains losses related hedging price risk associated natural gas oil production intersegment revenues represent sales marketing affiliate epme responsible marketing production 3 relates intercompany activities continuing operating segments discontinued petroleum markets operations 4 excludes assets discontinued operations 14 billion see note 12 5 amounts net third party reimbursements capital expenditures returns invested capital merchant energy segment includes 1 billion acquire remaining interest chaparral gemstone see note 3 1 includes corporate telecommunication activities eliminations intercompany transactions intersegment revenues along intersegment operating expenses incurred normal course business operating segments record intersegment revenue operation maintenance expense elimination included corporate column remove intersegment transactions 2 revenues external customers include gains losses related hedging price risk associated natural gas oil production intersegment revenues represent sales marketing affiliate epme responsible marketing production 3 relates intercompany activities continuing operating segments discontinued petroleum markets operations 4 excludes assets discontinued operations 41 billion see note 12 5 amounts net third party reimbursements capital expenditures returns invested capital 1 includes corporate telecommunication activities eliminations intercompany transactions intersegment revenues along intersegment operating expenses incurred normal course business operating segments record intersegment revenue elimination included corporate column remove intersegment transactions 2 revenues external customers include gains losses related hedging price risk associated natural gas oil production intersegment revenues represent sales marketing affiliate epme responsible marketing production 3 relates intercompany activities continuing operating segments discontinued petroleum markets operations 4 excludes assets discontinued operations 48 billion 5 amounts net third party reimbursements capital expenditures returns invested capital 27 supplemental cash flow information following table contains supplemental cash flow information continuing operations three years ended december 31 detail shortterm longterm borrowings repayments three years ended december 31 28 investments advances unconsolidated affiliates hold investments various unconsolidated affiliates accounted using equity method accounting principal equity method investees international pipelines interstate pipelines power generation plants gathering systems investment balance greater equity net assets investments 6 million december 31 2003 230 million december 31 2002 differences primarily relate unamortized purchase price adjustments net asset impairment charges net ownership interest investments advances unconsolidated affiliates follows december 31 1 ownership interest december 31 2003 consists effective 50 percent interest one percent general partner gulfterra approximately 178 percent partnerships common units outstanding series c units discussion gulfterra see page 178 2 lp represents limited partnership 3 ownership interest consists 381 percent general partner interest 54 percent limited partner interest 4 includes 46 percent general partner interest great lakes gas transmission limited partnership 4 percent limited partner interest ownership great lakes gas transmission company 5 llc represents limited liability company 6 gp represents general partnership 7 sold 100 percent interest 2003 8 consolidated january 1 2003 9 included diamond power gemstone prior consolidation gemstone april 2003 10 consolidated april 2003 11 june 2004 completed sale interest investment 12 july 2004 purchased remaining 50 percent interest unopaso began consolidating operations earnings losses unconsolidated affiliates follows three years ended december 31 1 sold interest investments 2002 2003 2 consolidated january 2003 3 consolidated april 2003 4 consolidated january 2002 5 acquired january 2003 part consolidation chaparral sold october 2003 6 july 2004 purchased remaining 50 percent interest unopaso began consolidating operations 7 sold interest power plant portion investment december 2002 impairment charges gains losses sales equity investments 2003 2002 2001 consisted following 1 2003 sold 50 percent equity consolidated subsidiary holds 1 percent general partner interest recorded minority interest balance sheet see discussion gulfterra page 178 2 december 2003 transferred ownership interest milford lenders order terminate obligations associated milford summarized financial information proportionate share unconsolidated affiliates information includes affiliates hold less 50 percent interest well hold greater 50 percent interest received distributions dividends 398 million 258 million 2003 2002 includes 53 million 24 million returns capital investments proportional shares unconsolidated affiliates hold greater 50 percent interest net income 119 million 26 million 40 million 2003 2002 2001 total assets 1108 million 389 million december 31 2003 2002 following table shows revenues charges resulting transactions unconsolidated affiliates chaparral gemstone december 31 2002 held equity investments chaparral gemstone first second quarters 2003 acquired remaining third party equity interests voting rights entities discussed note 3 consolidated chaparral effective january 1 2003 gemstone effective april 1 2003 following tables summarize overall investments chaparral gemstone december 31 2002 gulfterra subsidiary field services segment serves general partner gulfterra publicly traded master limited partnership following interests gulfterra december 31 1 181 million indefinitelived intangible assets related general partner interest see note 2 december 31 2003 2002 also 96 million recorded minority interest related effective general partner interest acquired enterprise december 2003 reduced effective ownership interest general partner 50 percent 2 remaining units owned public holders including partnership employees management none individually 10 percent 3 october 2003 gulfterra redeemed series b preference units owned 156 million recorded 11 million loss redemption 4 series c units gulfterra owner managing member interest 50 percent ownership interest general partner field services manages gulfterras daily operations performs gulfterras administrative operational activities general administrative services agreement cases separate operational agreements gulfterra contributes income general partner interest ownership common preference units loans gulfterra majority members board directors governing gulfterra independent us audit conflicts committee governance compensation committee completely comprised independent board members october 2003 sold 99 percent consolidated company owns one percent general partner interest gulfterra goldman sachs 88 million repurchased interest december 2003 prior announcement gulfterras merger enterprise 92 million cash 28 million gulfterras common units addition gulfterra redeemed series b preference units owned 156 million finally part overall transactions gulfterra released us obligation repurchase chaco processing facility contributed communications assets gulfterra prior transaction would obligated repurchase chaco facility approximately 77 million 2021 december 2003 gulfterra wholly owned subsidiary enterprise announced executed definitive agreements merge form second largest publicly traded energy partnership us general partner combined partnership would jointly owned us affiliates privately held enterprise products company owning 50 percent interest definitive agreements included three transactions enterprise agreed acquire 50 percent limited voting interest gulfterra energy company llc gulfterras general partner us 425 million cash giving effective 50 percent ownership gulfterras general partner ii agreed exchange remaining general partner interest 50 percent interest combined general partner gulfterra enterprise partners iii enterprise agreed pay us 500 million cash 29 million common units gulfterras series c units exchange remaining gulfterra common units approximately 135 million enterprise common units based 181 exchange ratio specified merger agreement april 2004 amended agreement enterprise products company reduce interest general partner combined entity 99 percent exchange additional payment us 370 million merger completed july 29 2004 gulfterras unitholders approved adoption merger agreement enterprise gulfterra expects completion merger occur third quarter 2004 although remains subject review federal trade commission ftc satisfaction conditions close sale 50 percent interest gulfterras general partner completed december 2003 recognized 269 million gain sale net 45 million total services payments agreed provide three years following closing transactions cash flows sale reflected 2003 cash flow statement investing activity 84 million proceeds reflected issuance minority interest balance sheet concurrent closing merger enterprise acquire nine natural gas processing plants us 150 million cash plants located south texas discussion impairment assets see note 7 three years ended december 31 2003 conducted following transactions gulfterra 2001 result merger coastal gulfterra sold interest several offshore assets including seven natural gas pipeline systems dehydration facility two offshore platforms proceeds sales approximately 135 million resulted loss approximately 25 million consideration sales committed pay gulfterra series payments totaling 29 million required contribute 40 million trust related one assets sold gulfterra payments recorded mergerrelated costs 2002 sold total 15 billion assets partnership including gathering processing transmission assets substantially assets san juan basin one san juan basin assets included transaction remaining interests chaco cryogenic plant addition 414 million cash received series c units addition 2003 exchanged communications assets release obligation repurchase chaco cryogenic plant 2021 recognized net gain transaction 67 million see note 7 december 31 2003 net deferred gain recorded current noncurrent liabilities balance sheet related san juan chaco sales along asset sales totaling 105 million deferred gains extent overall ownership interest gulfterra upon completion merger enterprise portion deferred amounts transferred income connection sales transmission assets gulfterra agreed reimburse gulfterra portion future pipeline integrity costs related assets 2006 time 2002 sales unable estimate liability associated obligation gulfterra early stages pipeline integrity programs 2003 amended agreement clarify types amounts reimbursable costs also began reviewing gulfterras pipeline integrity projects results review continued 2004 based reviews experience date related pipeline integrity projects determined obligation probable could estimated result recorded 5 million current liability 69 million noncurrent liability related agreement provided material guarantees either monetary performance behalf benefit gulfterra liabilities normal course business arising role general partner gulfterra 2001 sold partnership ngl transportation fractionation assets investment deepwater holdings entity owned several pipeline gathering systems gulf mexico majority assets acquired us one year earlier accordingly recorded fair value result proceeds sales 255 million gains losses recognized detail sales related gains losses recognized sales transactions specific procedures instituted evaluating transactions ensure best interests us partnership based fair values procedures require board directors evaluate approve appropriate transactions gulfterra addition special committee comprised gulfterra general partners independent directors evaluates transactions gulfterras behalf typically involves engaging independent financial advisor assist evaluation opine fairness included supplemental information financial statements consolidated financial statements gulfterra energy partners lp subsidiaries years ended december 31 2003 2002 2001 contingent matters could impact investments economic conditions dominican republic investments power projects dominican republic aggregate exposure approximately 102 million 4833 percent interest 67 mw heavy fuel oil fired power project known cepp project also 2499 percent ownership interest 416 mw power generating complex known itabo 2003 economic crisis developed dominican republic resulting significant devaluation dominican peso approximately 84 percent us dollar september 1 2004 increase local inflation rate approximately 43 percent 2003 additional 33 percent september 1 2004 current government administration currently negotiations imf reinstate standby agreement intended restore confidence banking system economic policy framework stabilize exchange rate alleviate ongoing liquidity crisis country consequence economic conditions described combined high prices imported fuels due inability pass high fuel costs consumers local distribution companies purchase electrical output facilities delinquent payments cepp itabo well generating facilities dominican republic since april 2003 failure pay generators resulted inability generators purchase fuel required produce electricity resulting significant energy shortfalls country currently believe economic difficulties dominican republic mitigated support imf implementation major structural reforms including fiscal package approved congress first week september 2004 pending second reading final approval senate expected take place end september 2004 meizhou wan power project december 31 2003 owned 248 percent equity interest 734 mw coalfired power generating project meizhou wan generating located fuzhou peoples republic china investment project 63 million december 31 2003 also issued guarantees letters credit favor projects lenders amount 21 million project declared ready commercial operations august 2001 however provincial government buys power generated project refused accept project commercial operations dispute resolved signing amended restated longterm power purchase agreement effective january 1 2004 provides certain minimum annual offtake obligation agreed tariff lower tariff power generated project excess minimum offtake obligation new power purchase agreement project able restructure project debt 2004 new local financing favorable terms thus achieving lower cost structure project new project debt collateralized projects assets nonrecourse us guarantees issued prior lenders canceled connection refinancing acquired additional 14 percent interest project issued 11 million guarantee project related potential claim one vendors september 2004 berkshire power project 56 percent direct equity interest 261 mw power plant berkshire power located massachusetts supply natural gas berkshire fuel management agreement berkshire ability delay payment 33 percent amounts due us fuel supply agreement maximum 49 million berkshire available cash meet debt service requirements berkshire delayed total 33 million fuel payments including 5 million interest agreement december 31 2003 2002 berkshires lenders asserted berkshire default loan agreement issues remain unresolved based uncertainty surrounding negotiations berkshires inability generate adequate future cash flow recorded losses 28 million 2003 associated amounts due us fuel supply agreement may incur additional losses 16 million future berkshire continues delay payments fuel supply agreement contingent matters impacting investments brazil see note 22 29 supplemental selected quarterly financial information unaudited financial information quarter restated reflect impacts revisions natural gas oil reserves accounting natural gas oil hedges described note 1 summarized 1 petroleum markets coal mining operations classified discontinued operations see note 12 discussion 1 petroleum markets coal mining operations classified discontinued operations see note 12 discussion 30 supplemental natural gas oil operations unaudited production segment engaged exploration acquisition development production natural gas oil condensate natural gas liquids primarily north america us onshore coal seam operations properties 20 states offshore operations properties federal state waters gulf mexico internationally exploration production rights australia bolivia brazil canada hungary indonesia turkey financial information natural gas oil reserve information presented restated reflect impacts revisions natural gas oil reserves accounting natural gas oil hedges described note 1 summarized capitalized costs relating natural gas oil producing activities related accumulated depreciation depletion amortization follows december 31 millions 1 september 2004 sold production operations canada substantially operations indonesia 2 includes international operations hungary indonesia 3 january 2003 adopted sfas 143 included net capitalized costs december 31 2003 sfas 143 asset values 124 million us less 1 million countries prior period presentation adjusted amounts adjusted onetime cumulative adjustment discussed note 2 costs incurred natural gas oil producing activities whether capitalized expensed follows december 31 millions 1 september 2004 sold production operations canada substantially operations indonesia 2 includes international operations hungary indonesia 3 excludes 130 million paid third parties net profits interest agreements described beginning page 189 4 january 2003 adopted sfas 143 prior period presentation adjusted amounts adjusted onetime cumulative adjustment approximately 3 million tax discussed notes 2 8 5 reclassified development costs exploration costs result restatement natural gas oil reserves january 1 2004 reserve report amounts estimated spent 2004 2005 2006 develop worldwide booked proved undeveloped reserves 544 million 404 million 487 million presented analysis capitalized costs natural gas oil properties year expenditure amortized december 31 2003 pending determination proved reserves capitalized interest 18 million 10 million 4 million years ended december 31 2003 2002 2001 included presentation millions 1 includes operations us canada brazil hungary indonesia 2 september 2004 sold production operations canada substantially operations indonesia projects presently excluded amortization various stages evaluation majority costs expected included amortization calculation years 2004 2007 us total amortization expense per mcfe including ceiling test charges 140 105 409 2003 2002 2001 excluding ceiling test charges amortization expense would 140 105 119 per mcfe 2003 2002 2001 canada total amortization expense per mcfe including ceiling test charges 530 481 1615 2003 2002 2001 excluding ceiling test charges amortization expense would 171 090 254 per mcfe 2003 2002 2001 january 2003 adopted sfas 143 discussion see note 2 accretion expense per mcfe attributable sfas 143 006 2003 included depreciation depletion amortization expense proved properties exception proved reserves brazil hungary indonesia located north america us canada net quantities proved developed undeveloped reserves natural gas liquids including condensate crude oil changes reserves december 31 2003 presented information tables based reserve report dated january 1 2004 prepared internally us ryder scott company huddleston co inc independent petroleum engineering firms performed independent reserve estimates 90 percent 10 percent properties respectively total estimate proved reserves prepared independently ryder scott company huddleston co inc within five percent internally prepared estimates 2003 presented tables information december 31 2003 consistent estimates reserves filed federal agencies except differences less five percent resulting actual product acquisitions property sales necessary reserve revisions additions reflect actual experience tables exclude reserve information related following equity interests ownership interest unopaso brazil merchant energy segments interests sengkang indonesia aguaytia peru field services segments interest gulfterra combined proved natural gas liquids reserve balances equity investment interests 255278 mmcf 7105 mbbls respectively natural gas equivalents 297909 mmcfe net ownership interests reserve information years ended december 31 2001 2002 following tables restated discussion see note 1 july 2004 acquired 50 percent interest uno paso began consolidating operations 1 september 2004 sold production operations canada substantially operations indonesia 2 includes international operations hungary indonesia 3 net proved reserves exclude royalties interests owned others including net profits interest reflects contractual arrangements royalty obligations effect time estimate 4 revisions reflect number items product price changes product differentials 5 sales reserves place include 28779 mcf natural gas conveyed third parties net profits interest agreements described beginning page 189 1 includes oil condensate natural gas liquids year end 2003 natural gas liquids 18550 mbbls 2 september 2004 sold production operations canada substantially operations indonesia 3 includes international operations hungary indonesia 4 net proved reserves exclude royalties interests owned others including net profits interest reflects contractual arrangements royalty obligations effect time estimate 5 revisions reflect number items product price changes product differentials 6 sales reserves place include 1292 mbbl liquids conveyed third parties net profits interest agreements described beginning page 189 considerable uncertainties inherent estimating quantities proved reserves projecting future rates production timing development expenditures including many factors beyond control reserve data represents estimates reservoir engineering subjective process estimating underground accumulations natural gas oil cannot measured exact manner accuracy reserve estimate function quality available data engineering geological interpretations judgment result estimates different engineers often vary estimates subject revision based upon number factors including reservoir performance prices economic conditions government restrictions addition results drilling testing production subsequent date estimate may justify revision estimate reserve estimates often different quantities natural gas oil ultimately recovered meaningfulness reserve estimates highly dependent accuracy assumptions based general volume production natural gas oil properties declines reserves depleted except extent conduct successful exploration development activities acquire additional properties containing proved reserves proved reserves decline reserves produced major discoveries events favorable adverse may considered caused significant change estimated proved reserves since december 31 2003 entered agreements sell interests maximum 124 wells two packages subsidiary lehman brothers wholly owned subsidiary nabors industries ltd wells developed parties pay 70 percent drilling completion costs exchange 70 percent net profits wells sold well commenced parties receive overriding royalty interest form net profits interest well entitled receive 70 percent aggregate net profits wells recovered 1175 percent aggregate investment upon recovery net profits interest convert proportionally reduced 2 percent overriding royalty interest wells remainder wells productive life guarantee return recovery costs return investment parties agreement right cease participation agreement time upon ceasing participation agreement continue receive net profits interest wells previously started relinquish right participate future wells december 31 2003 sold interests 31 wells total production 28779 mmcf natural gas 1292 mbbl natural gas liquids agreement paid 130 million drilling development costs paid 9 million revenues net 1 million expenses associated wells year ended december 31 2003 one party subsequently terminated participation one programs based drilling results portion wells package results operations producing activities fiscal year follows december 31 millions 1 september 2004 sold production operations canada 2 includes international operations hungary 3 includes lease operating costs production related taxes including advalorem severance taxes 4 january 2003 adopted sfas 143 discussed note 2 2003 depreciation depletion amortization includes accretion expense sfas 143 asset retirement obligations 23 million us less 1 million countries 5 amounts restated include net revenues depreciation depletion amortization expenses ceiling test charges income taxes related subtotals totals standardized measure discounted future net cash flows relating proved natural gas oil reserves follows december 31 millions 1 september 2004 sold production operations canada substantially operations indonesia 2 includes international operations hungary indonesia 3 excludes 104 million 85 million future net cash outflows related hedging activities years 2003 2002 4 excludes 255 million future net cash inflows related hedging activities year 2001 calculations preceding table estimated future cash inflows estimated future production proved reserves computed using yearend commodity prices adjusted transportation charges december 31 2003 prices used 3110 per bbl oil 579 per mcf gas 2353 per bbl natural gas liquids may receive amounts different standardized measure discounted cash flow number reasons including price changes effects hedging activities rely upon standardized measure making investment operating decisions based various factors including probable proved reserves different price cost assumptions actual economic conditions capital availability corporate investment criteria following principal sources change standardized measure discounted future net cash flows millions excluding effects hedging activities 1 includes operations us canada brazil hungary indonesia september 2004 sold production operations canada substantially operations indonesia report independent registered public accounting firm board directors stockholders el paso corporation opinion consolidated financial statements listed index appearing item 15a1 present fairly material respects consolidated financial position el paso corporation subsidiaries company december 31 2003 2002 consolidated results operations cash flows three years period ended december 31 2003 conformity accounting principles generally accepted united states america addition opinion financial statement schedule listed index appearing item 15a2 presents fairly material respects information set forth therein read conjunction related consolidated financial statements financial statements financial statement schedule responsibility companys management responsibility express opinion financial statements financial statement schedule based audits conducted audits statements accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements assessing accounting principles used significant estimates made management evaluating overall financial statement presentation believe audits provide reasonable basis opinion discussed note 1 2002 2001 consolidated financial statements restated reflect financial statement impact revision companys estimates proved natural gas oil reserves change accounting certain derivative transactions companys plans regard current liquidity position also discussed note 1 discussed notes 2 5 8 company adopted statement financial accounting standards sfas 143 accounting asset retirement obligations january 1 2003 sfas 146 accounting costs associated exit disposal activities january 1 2003 sfas 150 accounting certain financial instruments characteristics liabilities equity july 1 2003 sfas 142 goodwill intangible assets sfas 144 accounting impairment disposal longlived assets january 1 2002 dig issue c16 scope exceptions applying normal purchases sales exception contracts combine forward contract purchased option contract july 1 2002 eitf issue 023 accounting contracts involved energy trading risk management activities consensus 2 october 1 2002 sfas 133 accounting derivative instruments hedging activities january 1 2001 pricewaterhousecoopers llp houston texas september 28 2004 schedule ii el paso corporation valuation qualifying accounts years ended december 31 2003 2002 2001 millions 1 relates primarily accounts written 2 relates primarily receivables trading counterparties reclassified due bankruptcy declining credit accounted within price risk management activities 3 relates primarily valuation allowances deferred tax assets related western energy settlement foreign ceiling test charges foreign net operating loss carryovers 4 relates western energy settlement 104 million 2003 899 million 2002 june 2004 released approximately 602 including approximately 568 million escrow correspondingly reduced liability amount 5 relates primarily payments various litigation reserves environmental remediation reserves revenue crediting rate settlement reserves 6 relates primarily liabilities previously classified petroleum discontinued operations reclassified continuing operations due retention obligations 7 relates purchase price adjustments legal reserves related 2001 pge acquisition item 9item 8 financial statements supplementary data index financial statements related reports index financial statements notes contained item 8 financial statements supplementary data el paso corporation consolidated statements income millions except per common share amounts see accompanying notes el paso corporation consolidated balance sheets millions except share amounts see accompanying notes el paso corporation consolidated balance sheets continued millions except share amounts see accompanying notes el paso corporation consolidated statements cash flows millions 1 individual line items cash flows operating activities restated total cash flows continuing operating activities investing activities financing activities well discontinued operations unaffected restatement see accompanying notes el paso corporation consolidated statements cash flows continued millions 1 individual line items cash flows operating activities restated total cash flows continuing operating activities investing activities financing activities well discontinued operations unaffected restatement see accompanying notes el paso corporation consolidated statements stockholders’ equity millions except per share amounts see accompanying notes el paso corporation consolidated statements comprehensive income millions see accompanying notes el paso corporation notes consolidated financial statements 1 basis presentation significant accounting policies basis presentation consolidated financial statements include accounts majorityowned controlled subsidiaries elimination significant intercompany accounts transactions results periods presented reflect canadian certain international natural gas oil production operations petroleum markets coal mining businesses discontinued operations additionally financial statements prior periods include reclassifications made conform current year presentation reclassifications impact reported net loss stockholders’ equity restatement completion financial statements year ended december 31 2004 identified error manner originally adopted provisions statement financial accounting standards sfas 141 business combinations sfas 142 goodwill intangible assets 2002 upon adoption standards incorrectly adjusted cost investments unconsolidated affiliates cumulative effect change accounting principle excess share affiliates’ fair value net assets original cost believed negative goodwill amount originally recorded cumulative effect accounting change 154 million related investments citrus corporation portland natural gas several australian investments investment korea independent energy corporation subsequently determined amounts adjusted negative goodwill rather amounts allocated longlived assets underlying investments result required restate 2002 financial statements reverse amount recorded cumulative effect accounting change january 1 2002 adjustment also impacted related deferred tax adjustment unrealized loss recorded australian investments 2002 requiring restatement year restatements also affected investment deferred tax liability stockholders’ equity balances reported december 31 2002 2003 effects restatements restatement impact 2003 2004 reported income amounts except recorded adjustment related periods 19 million fourth quarter 2004 components adjustment immaterial previously reported interim annual periods principles consolidation consolidate entities either ability control operating financial decisions policies entity ii allocated majority entity’s losses andor returns variable interests entity determination ability control exert significant influence entity allocated majority entity’s losses andor returns involves use judgment apply equity method accounting exert significant influence control policies decisions entity allocated majority entity’s losses andor returns use cost method accounting unable exert significant influence entity see note 2 discussion adoption accounting standard impacted consolidation principles 2004 use estimates preparation financial statements conformity accounting principles generally accepted us requires use estimates assumptions affect amounts report assets liabilities revenues expenses disclosures financial statements actual results often differ estimates accounting regulated operations interstate natural gas pipelines storage operations subject jurisdiction ferc accordance natural gas act 1938 natural gas policy act 1978 regulated pipelines tgp epng sng cig wic cpg mpc follow regulatory accounting principles prescribed sfas 71 accounting effects certain types regulation anr discontinued application sfas 71 1996 accounting required sfas 71 differs accounting required businesses apply provisions transactions generally recorded differently result applying regulatory accounting requirements include capitalization equity return component regulated capital projects postretirement employee benefit plans costs included expected included future rates effective december 31 2004 anr storage began reapplying provisions sfas 71 perform annual review assess applicability provisions sfas 71 financial statements outcome could result reapplication accounting regulated systems discontinuance accounting others cash equivalents consider shortterm investments original maturity less three months cash equivalents maintain cash deposit banks insurance companies pledged particular use restricted support potential liability classify balances restricted cash current noncurrent assets balance sheet based expect cash used december 31 2004 180 million restricted cash current assets 180 million noncurrent assets december 31 2003 590 million restricted cash current assets 349 million noncurrent assets 2003 amounts 468 million related funds escrowed western energy settlement discussed note 17 allowance doubtful accounts establish provisions losses accounts notes receivable natural gas imbalances due shippers operators determine collect part outstanding balance regularly review collectibility establish adjust allowance necessary using specific identification method inventory consists spare parts natural gas storage optic fiber power turbines classify inventory current noncurrent based whether sold used normal operating cycle assets relates typically within next twelve months use average cost method account inventories value inventory lower cost market value property plant equipment property plant equipment recorded original cost construction upon acquisition fair value assets acquired assets construct capitalize direct costs labor materials indirect costs overhead interest regulated businesses apply provisions sfas 71 equity return component capitalize major units property replacements improvements expense minor items included pipeline property balances additional acquisition costs represent excess purchase costs associated purchase business combinations allocated regulated interstate systems costs amortized straightline basis recover excess costs rates following table presents property plant equipment type depreciation method depreciable lives 1 regulated interstate systems use composite group method depreciate property plant equipment method assets similar useful lives characteristics grouped depreciated one asset apply depreciation rate approved rate settlements total cost group net book value equals salvage value reevaluate depreciation rates time redevelop transportation rates file ferc increase decrease rates retire regulated property plant equipment charge accumulated depreciation amortization original cost plus cost remove sell dispose less salvage value recognize gain loss unless sell entire operating unit include gains losses dispositions operating units income capitalize carrying cost funds related construction longlived assets carrying cost consists interest cost debt could attributed assets applies regulated transmission businesses ii return equity could attributed assets applies regulated transmission businesses apply sfas 71 debt portion calculated based average cost debt interest cost debt amounts capitalized years ended december 31 2004 2003 2002 39 million 31 million 28 million amounts included reduction interest expense income statements equity portion calculated using recent ferc approved equity rate return equity amounts capitalized years ended december 31 2004 2003 2002 22 million 19 million 8 million amounts included nonoperating income statement capitalized carrying costs debt equityfinanced construction reflected increase cost asset balance sheet asset investment impairments apply provisions sfas 144 accounting impairment disposal longlived assets accounting principles board opinion apb 18 equity method accounting investments common stock account asset investment impairments standards evaluate asset investment impairment events circumstances indicate carrying value may recovered events include market declines believed temporary changes manner intend use longlived asset decisions sell asset investment adverse changes legal business environment adverse actions regulators event occurs evaluate recoverability carrying value based either longlived asset’s ability generate future cash flows undiscounted basis ii fair value investment unconsolidated affiliates impairment indicated decide exit sell longlived asset group assets adjust carrying value assets downward necessary estimated fair value less costs sell fair value estimates generally based market data obtained sales process analysis expected discounted cash flows magnitude impairments impacted number factors including nature assets sold established time frame completing sales among factors also reclassify asset assets either heldforsale discontinued operations depending among criteria whether continuing involvement cash flows assets sold natural gas oil properties use full cost method account natural gas oil properties full cost method substantially costs incurred connection acquisition development exploration natural gas oil reserves capitalized amounts include costs unproved properties internal costs directly related acquisition development exploration activities asset retirement costs capitalized interest method differs successful efforts method accounting activities primary differences two methods treatment exploratory dry hole costs generally expensed successful efforts determination made measurable reserves exist geological geophysical costs also expensed successful efforts method full cost method dry hole costs geological geophysical costs capitalized full cost pool periodically assessed recoverability discussed amortize capitalized costs using unit production method life proved reserves capitalized costs associated unproved properties excluded amortizable base properties evaluated future development costs dismantlement restoration abandonment costs net estimated salvage values included amortizable base beginning january 1 2003 began capitalizing asset retirement costs associated proved developed natural gas oil reserves full cost pool pursuant sfas 143 accounting asset retirement obligations discussed capitalized costs net related income tax effects limited ceiling based present value future net revenues using end period spot prices discounted 10 percent plus lower cost fair market value unproved properties net related income tax effects discounted revenues greater equal total capitalized costs required writedown capitalized costs level perform ceiling test calculation quarter required writedowns included income statement ceiling test charge ceiling test calculations include effects derivative instruments designated qualify cash flow hedges anticipated future natural gas oil production sell convey interests including net profits interests natural gas oil properties reduce reserves amount attributable sold conveyed interest recognize gain loss sales natural gas oil properties unless sales would significantly alter relationship capitalized costs proved reserves treat sales proceeds nonsignificant sales adjustment cost properties goodwill intangible assets intangible assets consist goodwill resulting acquisitions intangible assets apply sfas 141 business combinations sfas 142 goodwill intangible assets account intangibles standards goodwill intangibles indefinite lives amortized instead periodically tested impairment least annually whenever event occurs indicates impairment may occurred amortize intangible assets straightline basis estimated useful lives net carrying amounts goodwill december 31 2004 2003 changes net carrying amounts goodwill years ended december 31 2004 2003 segments follows field services impairments resulted sale substantially interests gulfterra energy partners well certain processing assets field services segment affiliates enterprise products partners lp result sales determined remaining assets field services segment could support goodwill segment see note 22 discussion enterprise transactions power segment recorded 22 million goodwill may 2003 connection acquisition chaparral december 2003 determined would sell substantially chaparral’s power plants based bids received determined goodwill recoverable fully impaired amount corporate impairments resulted weak industry conditions telecommunications operations also disposed 42 million goodwill related financial services businesses 2003 previously impaired 44 million 2002 based weak industry conditions decision invest capital businesses addition goodwill 181 million intangible asset december 31 2003 related excess investment general partnership interest gulfterra disposed asset part enterprise sales described also intangible assets 15 million 5 million december 31 2004 2003 primarily related customer lists miscellaneous intangible assets pension postretirement benefits maintain several pension postretirement benefit plans require us make contributions fund benefits paid plans contributions invested benefits paid plan participants record benefit expense related plans income statement benefit expense function many factors including benefits earned year plan participants function employee’s salary level benefits provided plan actuarial assumptions passage time expected return plan assets recognition certain deferred gains losses well plan amendments compare benefits earned accumulated benefit obligation plan’s fair value assets annual basis extent plan’s accumulated benefit obligation exceeds fair value plan assets record minimum pension liability balance sheet equal difference two amounts record additional minimum liability less liability already accrued plan difference greater pension liability recorded balance sheet however record additional liability amount comprehensive loss net income taxes financial statements 2004 adopted fasb staff position fsp 1062 accounting disclosure requirements related medicare prescription drug improvement modernization act 2003 pronouncement required us record impact medicare prescription drug improvement modernization act 2003 postretirement benefit plans provide drug benefits covered legislation adoption fsp 1062 decreased accumulated postretirement benefit obligation 49 million deferred actuarial gain postretirement benefit liabilities december 31 2004 expect adoption guidance reduce postretirement benefit expense approximately 6 million 2005 revenue recognition business segments provide number services sell variety products revenue recognition policies segment follows pipelines revenues pipelines segment derives revenues primarily transportation storage services also derive revenue sales natural gas transportation storage services recognize reservation revenues firm contracted capacity contract period regardless amount actually used interruptible volumetric based services revenues natural gas sales contracts record revenues complete delivery natural gas agreed upon delivery point natural gas injected withdrawn storage facility revenues services generally based thermal quantity gas delivered subscribed price specified contract tariff subject ferc regulations result revenues collect may refunded final order pending future rate proceeding result rate settlement establish reserves potential refunds production revenues production segment derives revenues primarily physical sale natural gas oil condensate natural gas liquids revenues sales products recorded upon passage title using sales method net royalty interests profit interests produced product actual natural gas sales volumes exceed entitled share sales volumes overproduced imbalance occurs extent overproduced imbalance exceeds share remaining estimated proved natural gas reserves given property record liability costs associated transportation delivery production included cost sales field services revenues field services segment derives revenues primarily gathering processing services sale commodities retained providing services two general types services feebased makewhole feebased services recognize revenues time service rendered based upon volume gas gathered treated processed contracted fee makewhole services fee consists retainage natural gas liquids byproducts result processing recognize revenues services time sell products generally coincides provide service power marketing trading revenues power marketing trading segments derive revenues physical sales natural gas power management derivative contracts derivative transactions recorded fair value changes fair value reflected operating revenues see discussion income recognition policies derivatives price risk management activities revenues physical sales recognized time commodity delivered based volumes delivered contractual market price corporate revenue producing activities corporate operations primarily consist revenues telecommunications business recognize revenues metro transport collocation crossconnect services month services actually used customer environmental costs contingencies record liabilities environmental assessments indicate remediation efforts probable costs reasonably estimated recognize current period expense liability cleanup efforts benefit future periods capitalize costs benefit one accounting period except instances separate agreements legal regulatory guidelines dictate otherwise estimates liabilities based currently available facts existing technology presently enacted laws regulations taking consideration likely effects societal economic factors include estimates associated legal costs amounts also consider prior experience remediating contaminated sites companies’ cleanup experience data released epa organizations estimates subject revision future periods based actual costs new circumstances included balance sheet current longterm liabilities undiscounted amounts evaluate recoveries insurance coverage government sponsored programs separately liability recovery assured record report asset separately associated liability financial statements recognize liabilities contingencies exposure fully analyzed indicates probable asset impaired liability incurred amount impairment loss reasonably estimated funds spent remedy contingencies charged reserve one exists expensed range probable loss estimated accrue likely amount least minimum range probable loss price risk management activities price risk management activities consist following activities • derivatives entered hedge commodity interest rate foreign currency exposures primarily natural gas oil production longterm debt • derivatives related power contract restructuring business • derivatives related trading activities historically entered objective generating profits exposure shifts changes market prices account derivative instruments sfas 133 accounting derivative instruments hedging activities sfas 133 derivatives reflected balance sheet fair value assets liabilities price risk management activities classify derivatives either current noncurrent assets liabilities based anticipated settlement date net derivative assets liabilities counterparties legal right offset see note 10 discussion price risk management activities prior 2002 also accounted nonderivative contracts transportation storage capacity contracts physical natural gas inventories exchanges used energy trading business fair values emerging issues task force eitf issue 9810 accounting contracts involved energy trading risk management activities 2002 adopted eitf issue 023 issues related accounting contracts involving energy trading risk management activities result adjusted carrying value nonderivative instruments zero account accrual basis accounting also adjusted physical natural gas inventories used historical trading business cost lower market physical natural gas exchanges expected settlement amounts reclassified amounts inventory accounts receivable payable balance sheet upon adoption eitf issue 023 recorded net loss 343 million 222 million net income taxes cumulative effect accounting change income statement 118 million net adjustment natural gas inventories exchanges 225 million net adjustment nonderivative instruments income statement treatment changes fair value settlements derivatives depends nature derivative instrument derivatives used hedging activities reflected either revenues expenses income statements based nature timing hedged transaction derivatives related power contract restructuring activities reflected either revenues settlements changes fair values power sales contracts expenses settlements changes fair values power supply agreements income statement presentation derivative contracts used historical energy trading activities reported revenue net basis revenues net expenses physically settled purchases cash flow statement cash inflows outflows associated settlement derivative instruments recognized operating cash flows receivables payables resulting settlements reported trade receivables payables balance sheet 2002 also adopted derivatives implementation group dig issue c16 scope exceptions applying normal purchases sales exception contracts combine forward contract purchased option contract dig issue c16 requires fixedprice fuel supply contract allows buyer purchase option additional quantities fixedprice contract derivative must recorded fair value one unconsolidated affiliates midland cogeneration venture limited partnership recognized gain one fuel supply contract upon adoption new rules recorded proportionate share gain 14 million net income taxes cumulative effect accounting change income statement income taxes record current income taxes based current taxable income provide deferred income taxes reflect estimated future tax payments receipts deferred taxes represent tax impacts differences financial statement tax bases assets liabilities carryovers year end account tax credits flowthrough method reduces provision income taxes year tax credits first become available reduce deferred tax assets valuation allowance based estimates likely portion assets realized future period estimates utilized recognition deferred tax assets subject revision either future periods based new facts circumstances maintain tax accrual policy record regular alternative minimum taxes companies included consolidated federal state income tax returns policy provides among things company taxable income position accrue current expense equivalent federal state income taxes ii company tax loss position accrue benefit extent deductions including general business credits utilized consolidated returns pay consolidated us federal state income taxes directly appropriate taxing jurisdictions separate tax billing agreement may bill refund subsidiaries portion income tax payments foreign currency transactions translation record currency transaction gains losses income gains losses classified income statement based upon nature transaction gives rise currency gain loss sales purchases commodities goods gains losses included operating revenue expense gains losses insignificant 2004 2003 2002 gains losses arising equity investees record gains losses equity earnings gains losses foreign denominated debt include gains losses component expense years ended december 31 2004 2003 2002 recorded net foreign currency losses 17 million 100 million 91 million primarily related currency losses eurodenominated debt us dollar functional currency majority foreign operations foreign operations whose functional currency deemed us dollar assets liabilities translated yearend exchange rates translation effects included separate component accumulated comprehensive income loss stockholders’ equity net cumulative currency translation gain recorded accumulated comprehensive income 52 million 45 million december 31 2004 2003 revenues expenses translated average exchange rates prevailing year treasury stock account treasury stock using cost method report balance sheet reduction stockholders’ equity treasury stock sold issued valued firstin firstout basis included treasury stock december 31 2004 2003 approximately 16 million shares 17 million shares common stock held trust deferred compensation programs stockbased compensation account stockbased compensation plans using intrinsic value method provisions accounting principles board opinion apb 25 accounting stock issued employees related interpretations fixed variable compensation plans account plans using fixed variable accounting appropriate compensation expense variable plans including restricted stock grants measured using market price stock date number shares grant becomes determinable measured expense amortized income period service grant earned stock options granted fixed plan market value date grant accordingly compensation expense recognized accounted stockbased compensation using sfas 123 accounting stockbased compensation rather apb 25 income loss per share impacts financial statements would different following shows impact net loss per share applied sfas 123 accounting asset retirement obligations january 1 2003 adopted sfas 143 requires record liability retirement removal costs longlived assets used business asset retirement obligations associated natural gas oil wells related infrastructure production segment natural gas storage wells pipelines segment obligations plug wells production wells exhausted abandon currently forecast obligations met various times generally next fifteen years based expected productive lives wells estimated timing plugging abandoning wells estimating liability associated asset retirement obligations utilize several assumptions including creditadjusted discount rates projected inflation rates estimated timing amounts settling obligations based internal models external quotes following summary asset retirement liabilities significant assumptions used december 31 1 estimate approximately 61 percent noncurrent asset retirement liability december 31 2004 settled next five years asset retirement liabilities recorded estimated fair value utilizing assumptions corresponding increase property plant equipment increase property plant equipment depreciated remaining useful life longlived asset liability relates ongoing expense also recognized changes value liability result passage time record depreciation depletion amortization expense income statement first quarter 2003 recorded charge cumulative effect accounting change approximately 9 million net income taxes related adoption sfas 143 net asset retirement liability december 31 reported current noncurrent liabilities balance sheet changes net liability year ended december 31 follows millions changes estimate represent changes expected amount timing payments settle asset retirement obligations changes primarily result obtaining new information timing obligations plug natural gas oil wells costs adopted sfas 143 january 1 2002 aggregate current noncurrent retirement liabilities date would approximately 187 million income continuing operations net income year ended december 31 2002 would lower 15 million basic diluted earnings per share year ended december 31 2002 would materially affected accounting certain financial instruments characteristics liabilities equity may 2003 financial accounting standards board fasb issued sfas 150 accounting certain financial instruments characteristics liabilities equity statement provides guidance classification financial instruments equity liabilities equity particular standard requires classify mandatorily redeemable securities liabilities balance sheet july 1 2003 adopted provisions sfas 150 reclassified 625 million capital trust coastal finance preferred interests preferred interests consolidated subsidiaries longterm financing obligations balance sheet also began classifying dividends accrued preferred interests interest debt expense income statement dividends 40 million 2004 2003 dividends recorded interest debt expense 2004 20 million 2003 dividends recorded interest expense 20 million recorded distributions preferred interests income statement 2003 new accounting pronouncements issued yet adopted december 31 2004 several accounting standards interpretations yet adopted us discussion significant standards may impact us accounting stockbased compensation december 2004 fasb issued sfas 123r sharebased payment amendment sfas 123 95 standard requires companies measure record fair value stock based compensation awards fair value date granted employees fair value determined based variety assumptions including volatility rates forfeiture rates option pricing model used eg binomial black scholes assumptions could significantly differ currently utilize determining proforma compensation expense included disclosures required sfas 123 standard also impact manner recognize income tax impacts stock compensation programs financial statements standard effective interim periods beginning june 15 2005 time companies select whether apply standard retroactively restating historical financial statements prospectively new stockbased compensation arrangements unvested portion existing arrangements adopt pronouncement third quarter 2005 currently evaluating impact consolidated financial statements accounting deferred taxes foreign earnings december 2004 fasb issued fasb staff position fsp 1092 accounting disclosure guidance foreign earnings repatriation provision within american jobs creation act 2004 fsp 1092 clarified existing accounting literature requires companies record deferred taxes foreign earnings unless intend indefinitely reinvest earnings outside us pronouncement temporarily allow companies evaluating whether repatriate foreign earnings american jobs creation act 2004 delay recognizing related taxes decision made pronouncement also requires companies considering repatriating earnings disclose status evaluation potential amounts considered repatriation us treasury department issued final guidelines applying repatriation provisions american jobs creation act yet determined potential range foreign earnings could impacted legislation fsp 1092 continue evaluate whether repatriate foreign earnings impact pronouncement financial statements 2 acquisitions consolidations acquisitions 2003 acquired remaining third party interests chaparral gemstone investments began consolidating first second quarters 2003 respectively historically accounted investments using equity method accounting acquisitions discussed chaparral entered chaparral investment 1999 expand domestic power generation business chaparral owned interests 34 power plants united states total generating capacity 3470 megawatts based chaparral’s interest plants primarily concentrated northeastern western united states chaparral also owned several companies longterm derivative power agreements december 31 2002 owned 20 percent chaparral remaining 80 percent owned limestone electron trust limestone 2003 paid 1175 million acquire limestone’s 80 percent interest chaparral limestone used 1 billion proceeds retire notes previously guaranteed us reflected chaparral’s results operations income statement though acquired january 1 2003 acquired chaparral effective january 1 2002 net increases decreases income statement year ended december 31 2002 would follows millions first quarter 2003 recorded impairment investment chaparral 207 million income taxes discussed note 22 following table presents allocation purchase price chaparral assets liabilities prior consolidation prior elimination intercompany transactions allocation reflects allocation purchase price 1175 million ii carrying value initial investment 252 million iii impairment 207 million millions 1 debt recourse project contract plant relates allocation purchase price based valuations performed independent third party consultant finalized december 2003 significant changes initial purchase price allocation valuations derived using discounted cash flow analyses valuation methods valuations indicated fair value net assets purchased chaparral less purchase price paid chaparral 22 million recorded goodwill financial statements see note 1 discussion subsequent impairment goodwill gemstone entered gemstone investment 2001 finance five major power plants brazil gemstone investments three power projects macae porto velho araucaria also owned preferred interest two consolidated power projects rio negro manaus 2003 acquired thirdparty investor’s rabobank interest gemstone approximately 50 million gemstone’s results operations included consolidated financial statements since april 1 2003 acquired gemstone effective january 1 2003 net income basic diluted earnings per share year ended december 31 2003 would affected revenues operating income would higher 58 million 41 million amounts unaudited acquisition effective january 1 2002 net income basic diluted earnings per share would affected revenues operating income would higher 187 million 134 million amounts unaudited allocation purchase price assets acquired liabilities assumed upon consolidation gemstone follows millions allocation purchase price based valuations performed independent third party consultant finalized december 2003 significant changes initial purchase price allocation valuations derived using discounted cash flow analyses valuation methods prior acquisitions chaparral gemstone balances including loans notes chaparral gemstone eliminated upon consolidation result overall impact consolidated balance sheet acquiring investments different individual assets liabilities acquired overall impact acquisitions consolidated balance sheet increase consolidated assets 21 billion increase consolidated liabilities approximately 24 billion including increase consolidated debt approximately 22 billion reduction preferred interests consolidated subsidiaries approximately 03 billion consolidations variable interest entities 2003 fasb issued financial interpretation fin 46 consolidation variable interest entities interpretation arb 51 interpretation defines variable interest entity legal entity whose equity owners sufficient equity risk controlling financial interest entity standard requires company consolidate variable interest entity allocated majority entity’s losses returns including fees paid entity january 1 2004 adopted standard upon adoption consolidated blue lake gas storage company several minor entities deconsolidated previously consolidated entity ema power kft overall impact actions described following table blue lake gas storage owns operates 47 bcf gas storage facility michigan one subsidiaries operates natural gas storage facility inject withdraw natural gas stored facility 75 percent equity interest blue lake entity 8 million third party debt december 31 2004 nonrecourse us consolidated blue lake allocated majority blue lake’s losses returns equity interest blue lake ema power kft owns operates 69 gross mw dualfuelfired power facility located hungary 50 percent equity interest ema equity partner 50 percent interest ema supplies fuel consumed purchases power generated facility exposure entity limited equity interest ema approximately 43 million december 31 2004 deconsolidated ema equity partner allocated majority ema’s losses returns equity interest fuel supply power purchase agreements ema significant interests number variable interest entities required consolidate entities fin 46 result method accounting entities change december 31 2004 entities consisted primarily 20 equity cost investments held power segment interests power generation transmission facilities total generating capacity approximately 7300 gross mw operate many facilities supply significant portion fuel consumed purchase significant portion power generated facilities longterm debt issued entities recourse power project result exposure entities limited equity investments advances entities 11 billion december 31 2004 guarantees agreements associated entities maximum 80 million december 31 2004 adoption fin 46 attempted obtain financial information several potential variable interest entities unable obtain information significant entities cordova power project counterparty largest tolling arrangement tolling arrangement supply average total 54000 mmbtu natural gas per day entity’s two 274 gross mw power facilities obligated market power generated facilities 2019 addition pay entity capacity charge ranges 27 million 32 million per year related power plants following summary financial statement impacts transactions entity year ended december 31 2004 2003 december 31 2004 december 31 2003 december 31 2004 financial statements included two consolidated entities 238 mw power facility 158 mw power facility manaus brazil january 2005 entered agreements manaus energia manaus energia supply substantially fuel consumed purchase power generated projects january 2008 time manaus energia assume ownership plants deconsolidated two entities january 2005 manaus energia assume ownership plants since absorb majority potential losses entities new agreements impact deconsolidation increase investments unconsolidated affiliates 103 million decrease property plant equipment 74 million net decrease assets liabilities 29 million first quarter 2005 lakeside 2003 amended operating lease agreement lakeside technology center add guarantee benefiting party invested lessor allow third party certain lenders share collateral package provided banks previous 3 billion revolving credit facility guarantee reduced investor’s risk loss investment resulting controlling lessor result consolidated lessor consolidation lakeside technology center resulted increase property plant equipment approximately 275 million increase longterm debt approximately 275 million 2004 repaid 275 million scheduled mature 2006 additionally upon consolidation recorded asset impairment charge approximately 127 million representing difference facility’s estimated fair value residual value guarantee lease prior consolidation difference periodically expensed part operating lease expense term lease clydesdale 2003 modified clydesdale financing arrangement convert thirdparty investor’s mustang investors llc preferred ownership interest one consolidated subsidiaries term loan matures equal quarterly installments 2005 also acquired 10 million preferred interest mustang guaranteed mustang’s equity holder’s obligations result consolidated mustang increased longterm debt 743 million decreased preferred interests consolidated subsidiaries 753 million 10 million preferred interest acquired mustang eliminated upon consolidation december 2003 repaid remaining clydesdale debt obligation see notes 15 16 3 divestitures sales assets investments 2004 2003 2002 completed announced sale number assets investments business segments following table summarizes proceeds sales 1 proceeds exclude returns invested capital cash transferred assets sold include costs incurred preparing assets disposal items decreased sales proceeds 85 million 30 million 25 million years ended december 31 2004 2003 2002 proceeds also exclude noncash consideration received sales receipt 350 million series c units gulfterra sale assets field services segment 2002 following table summarizes significant assets sold pipelines • australian pipelines • interest gathering systems • 21 interest alliance pipeline • equity interest portland natural gas transmission system • horsham pipeline australia • natural gas oil properties located tx ks ok • 123 equity interest alliance pipeline • typhoon natural gas pipeline production • brazilian exploration production acreage • natural gas oil properties nm tx la ok gulf mexico • natural gas oil properties located tx co utah power • utility contract funding • 31 domestic power plants several turbines • interest ce generation llc • mt carmel power plant • capsacapex investments • east coast power • 40 equity interest samalayuca power ii power project mexico field services • remaining general partnership interest common units series c units gulfterra • south tx processing plants • dauphin island mobile bay investments • gathering systems located wy • midstream assets north la midcontinent regions • common series b preference units gulfterra • 50 gulfterra general partnership • tx nm midstream assets • dragon trail gas processing plant • san juan basin gathering treating processing assets • gathering facilities utah corporate • aircraft • aircraft • enerplus global energy management company financial operations • encap funds management business investments • none discontinued • natural gas oil production properties canada international production assets • aruba eagle point refineries petroleum assets • corpus christi refinery • florida petroleum terminals • louisiana lease crude • coal reserves • canadian natural gas oil properties • asphalt facilities • coal reserves properties petroleum assets • natural gas oil properties located western canada see note 5 discussion gains losses asset impairments related sales 2005 either completed announced following sales • remaining 99 membership interest general partner enterprise approximately 135 million units enterprise 425 million • interests cedar brakes ii 94 million • interest paraxylene power plant 74 million • interest natural gas gathering system processing facility 75 million • pipeline facilities 31 million • interest indian power plant 20 million • mtbe processing facility 5 million • eagle point power facility 3 million • interest rensselaer power facility obligations sfas 144 accounting impairment disposal longlived assets classify assets disposed held sale appropriate discontinued operations received appropriate approvals management board directors meet criteria assets consist certain domestic power plants natural gas gathering processing assets field services segment december 31 2004 assets held sale 75 million related indian springs natural gas gathering processing facility sold january 2005 four domestic power assets impaired previous years expect sell within next twelve months following table details items reflected current assets liabilities held sale balance sheet december 31 2003 millions discontinued operations international natural gas oil production operations 2004 canadian certain international natural gas oil production operations approved sale december 31 2004 completed sale canadian operations substantially operations indonesia total proceeds approximately 389 million 2004 recognized approximately 99 million losses based decision sell assets expect complete sale remainder properties mid2005 petroleum markets 2003 sales petroleum markets businesses operations approved businesses operations consisted eagle point aruba refineries asphalt business florida terminal tug barge business lease crude operations unilube blending operations domestic international terminalling facilities petrochemical chemical plants based intent dispose operations required adjust assets estimated fair value result recognized pretax impairment charges 2003 approximately 15 billion related assets impairments based comparison carrying value assets estimated fair value less selling costs also recorded realized gains approximately 59 million 2003 sale corpus christi refinery asphalt assets florida terminalling marine assets 2004 completed sales aruba eagle point refineries 880 million used portion proceeds repay 370 million debt associated aruba refinery recorded realized losses approximately 32 million 2004 primarily sale aruba eagle point refineries addition 2004 reclassified petroleum ship charter operations discontinued operations continuing operations financial statements based decision retain operations financial statements periods presented reflect change coal mining 2002 board directors authorized sale coal mining operations recorded impairment 185 million operations consisted fifteen active underground two surface mines located kentucky virginia west virginia sale operations completed 2003 92 million cash 24 million notes receivable settled second quarter 2004 record significant gain loss sales petroleum markets coal mining international natural gas oil production operations discussed classified discontinued operations financial statements historical periods presented assets liabilities discontinued businesses classified current assets liabilities december 31 2004 summarized financial results financial position data discontinued operations follows 4 restructuring costs result actions taken 2002 2003 2004 incurred certain organizational restructuring costs included operation maintenance expense january 1 2003 adopted provisions sfas 146 accounting costs associated exit disposal activities recognized restructuring costs applying provisions standard prior date recognized restructuring costs according provisions eitf issue 943 liability recognition certain employee termination benefits costs exit activity segment restructuring costs years ended december 31 follows period 2002 2004 incurred substantial restructuring charges part ongoing liquidity enhancement cost reduction efforts summary costs employee severance retention transition costs 2002 2003 2004 incurred employee severance costs included severance payments costs pension benefits settled existing benefit plans period eliminated approximately 1900 fulltime positions continuing business approximately 1200 positions related businesses discontinued 2004 900 fulltime positions continuing businesses approximately 1800 positions related businesses discontinued 2003 900 fulltime positions terminations 2002 december 31 2004 15 million total employee severance retention transition costs paid office relocation consolidation may 2004 announced would begin consolidating houstonbased operations one location consolidation substantially completed end 2004 result december 31 2004 established accrual totaling 80 million record discounted liability net estimated sublease rentals obligations existing lease terms leases expire various times 2014 approximate 888000 square feet office space lease vacated approximately 741000 square feet december 31 2004 addition subleased approximately 238000 square feet space third fourth quarters 2004 actual moving expenses related relocation insignificant expensed period incurred amounts related relocation expensed corporate operations 2003 contract termination costs included charges approximately 44 million related amounts paid canceling restructuring obligations transport lng supply areas domestic international market centers 2002 incurred paid fees 40 million eliminate stock price credit rating triggers related chaparral gemstone investments 5 loss longlived assets loss longlived assets continuing operations consists realized gains losses sales longlived assets impairments longlived assets including goodwill intangibles three years ended december 31 losses longlived assets follows 1 see note 22 description gains losses net realized gain loss 2004 net realized gain primarily related 10 million gains power segment 8 million gains corporate operations disposition assets offset 11 million loss sale south texas assets field services segment 2003 net realized loss primarily related 74 million loss agreement reimburse gulfterra portion future pipeline integrity costs previously sold assets reduced accrual 9 million 2004 see note 22 also recorded 67 million gain release purchase obligation chaco facility 14 million gain sale north louisiana midcontinent midstream assets field services segment well 75 million loss termination energy bridge contracts corporate segment 10 million loss sale mohawk river funding power segment 2002 net realized gain primarily related 245 million net gains sales san juan gathering assets natural buttes ouray gathering systems dragon trail gas processing plant texas new mexico assets field services segment see note 3 discussion divestitures asset impairments impairment charges years ended december 31 2004 2003 2002 recorded primarily connection intent dispose reduce involvement number assets 2004 power segment charges include 227 million impairment sale domestic equity interests cedar brakes ii closed first quarter 2005 167 million impairment manaus rio negro power facilities brazil result renegotiating extending power purchase agreements 30 million impairment consolidated asian assets connection decision sell assets addition 2004 impaired ucf prior sale 98 million recorded impairments 73 million related sales various power assets turbines 2003 2002 power segment impairment charges primarily result planned sale domestic power assets including turbines classified longterm assets field services charges include 480 million impairment goodwill associated enterprise sale 2004 realized offsetting pretax gain 507 million recorded earnings unconsolidated affiliates 24 million impairment sales abandonment assets 2004 impairment south texas processing facilities 167 million 2003 based planned sale facilities enterprise see note 22 66 million impairment resulted decision sell north louisiana gathering facilities 2002 corporate telecommunications charge includes impairment investment wholesale metropolitan transport services primarily texas 269 million 2003 including writedown goodwill 163 million 2003 impairment lakeside technology center facility 127 million based estimate asset could sold current market 2002 incurred 168 million corporate telecommunication charges related impairment longhaul fiber network rightofway assets additional asset impairments discontinued operations investments unconsolidated affiliates see notes 3 22 additional discussion goodwill intangibles see note 1 6 income expenses following components income expenses continuing operations three years ended december 31 1 amounts 2004 2003 2002 primarily related losses eurodenominated debt 2 impaired investment costañera power plant 2002 7 income taxes pretax loss continuing operations composed following three years ended december 31 following table reflects components income tax expense benefit included loss continuing operations three years ended december 31 income taxes included loss continuing operations differs amount computed applying statutory federal income tax rate 35 percent following reasons three years ended december 31 following components net deferred tax liability related continuing operations december 31 2004 congress proposed failed enact legislation would disallow deductions certain settlements made behalf governmental entities possible congress reintroduce similar legislation 2005 enacted tax legislation could impact deductibility western energy settlement could result writeoff associated tax benefits event tax expense would increase total tax benefits related western energy settlement approximately 400 million december 31 2004 historically recorded us deferred tax liabilities book versus tax basis differences asian power investments historical intent indefinitely reinvest earnings projects outside us 2004 intent assets changed intend use proceeds sale within us result recorded deferred tax liabilities december 31 2004 39 million representing instances book basis investments asian power projects exceeded tax basis time however due uncertainties manner timing approval sales recorded deferred tax assets instances tax basis investments exceeded book basis except instances believe realization asset assured december 31 2004 total deferred tax assets recorded asian investments 6 million cumulative undistributed earnings remainder foreign subsidiaries foreign corporate joint ventures excluding asian power assets discussed intended indefinitely reinvested foreign operations therefore provision made us taxes foreign withholding taxes may applicable upon actual deemed repatriation december 31 2004 portion cumulative undistributed earnings investments recorded us income taxes approximately 551 million distribution earnings made might subject foreign withholding taxes us income taxes net allowable foreign tax credits deductions however estimate taxes practicable reasons recorded provision us income taxes foreign currency translation adjustments recorded accumulated comprehensive income 4 million included deferred tax liability recorded related investment asian power projects tax effects associated employees’ nonqualified dispositions employee stock purchase plan stock exercise nonqualified stock options vesting restricted stock well restricted stock dividends included additional paidincapital balance sheets december 31 2004 us federal alternative minimum tax credits 283 million state alternative minimum assessment tax credits 1 million carryover indefinitely 1 million general business credit carryovers carryover periods end various times years 2012 2021 capital loss carryovers 87 million charitable contributions carryovers 2 million carryover periods end 2008 table presents details federal state net operating loss carryover periods december 31 2004 also 103 million foreign net operating loss carryovers carryover indefinitely usage us federal carryovers subject limitations provided sections 382 383 internal revenue code well separate return limitation year rules irs regulations record valuation allowance reflect estimated amount deferred tax assets may realize due uncertain availability future taxable income expiration net operating loss tax credit carryovers december 31 2004 maintained valuation allowance 37 million related state net operating loss carryovers 7 million related estimated ability realize state tax benefits deduction charge took related western energy settlement 5 million related foreign deferred tax assets book impairments ceiling test charges 1 million related general business credit carryover 1 million related carryovers december 31 2003 maintained valuation allowance 5 million related state tax benefits western energy settlement 1 million related state net operating loss carryovers 1 million related foreign deferred tax assets ceiling test charges 1 million related general business credit carryover 1 million related carryovers change valuation allowances december 31 2003 december 31 2004 primarily related additional valuation allowance state new jersey legislation limited use net operating loss carryovers increase valuation allowances foreign impairments assets increase state valuation allowance related western energy settlement currently audit irs taxing authorities audits various stages completion tax years 19952000 pending irs appeals office related coastal corporation merged 2001 anticipate appeals proceedings 19951997 finalized within 12 months years take longer complete irs completed examination el paso’s tax years 2000 20012002 tax years currently examination anticipate completed within 12 months may additional proceedings irs appeals office respect examination maintain reserve tax contingencies management believes adequate audits finalized make appropriate adjustments estimates 8 earnings per share incurred losses continuing operations three years ended december 31 2004 accordingly excluded number securities years ended december 2004 2003 2002 determination diluted earnings per share due antidilutive effect loss per common share included stock options restricted stock trust preferred securities equity security units convertible debentures additionally 2003 excluded shares related remaining stock obligation western energy settlement see note 17 information discussion instruments see notes 15 20 9 fair value financial instruments following table presents carrying amounts estimated fair values financial instruments december 31 2004 2003 december 31 2004 2003 carrying amounts cash equivalents shortterm borrowings trade receivables payables represented fair value shortterm nature instruments fair value longterm debt variable interest rates approximates carrying value marketbased nature interest rate estimated fair value debt fixed interest rates based quoted market prices similar issues see note 10 discussion methodology determining fair value derivative instruments used price risk management activities 10 price risk management activities following table summarizes carrying value derivatives used price risk management activities december 31 2004 2003 table derivatives designated hedges consist instruments used hedge natural gas oil production well instruments hedge interest rate currency risks longterm debt derivatives power contract restructuring activities relate power purchase sale agreements arose activities business commoditybased derivative contracts relate historical energy trading activities 1 december 2004 designated commoditybased derivative contracts fair value loss 592 million hedges 2005 2006 natural gas production result reclassified amount derivatives designated hedges beginning fourth quarter 2004 2 includes derivative contracts fair value 596 million december 31 2004 sold connection sale cedar brakes ii first quarter 2005 942 million december 31 2003 sold connection sales ucf mohawk river funding iv 2004 3 included current noncurrent assets liabilities price risk management activities balance sheet derivative contracts recorded financial statements fair value best indication fair value quoted market prices however quoted market prices available estimate fair value derivatives due major industry participants exiting reducing trading activities 2002 2003 availability reliable commodity pricing data marketbased sources used estimating fair value derivatives significantly limited certain locations longer time periods consequently use independent pricing source substantial amount forward pricing data beyond current twoyear period forward pricing data within two years use commodity prices marketbased sources new york mercantile exchange periods beyond two years use combination commodity prices marketbased sources forecasted settlement prices independent pricing source develop price curves use estimate value settlements future periods based contractual settlement quantities dates finally discount estimated settlement values using libor curve except described restructured power contracts additionally contracts denominated foreign currencies converted us dollars using marketbased foreign exchange spot rates record valuation adjustments reflect uncertainties associated estimates use determining fair value common valuation adjustments include market liquidity creditworthiness contractual counterparties extent possible use marketbased data together quantitative methods measure risks record valuation adjustments determine level valuation adjustments valuation techniques used valuing derivative contracts historically accounted trading activities well used hedge natural gas oil production adjusted method determine fair value restructured power contracts restructured power derivatives use methodology discussed determining forward settlement prices discounted using risk free interest rate adjusted individual credit spread counterparty contract additionally liquidity valuation adjustment provided derivative contracts since intended held maturity derivatives designated hedges engage two types hedging activities hedges cash flow exposure hedges fair value exposure hedges cash flow exposure primarily relate natural gas oil production hedges foreign currency interest rate risks longterm debt designed hedge forecasted sales transactions limit variability cash flows received paid related recognized asset liability hedges fair value exposure entered protect fair value recognized asset liability firm commitment enter derivative contract designate derivative either cash flow hedge fair value hedge hedges foreign currency exposure designated either cash flow hedges fair value hedges based whether interest underlying debt converted either fixed floating interest rate changes derivative fair values designated cash flow hedges deferred accumulated comprehensive income loss extent effective included income hedged transactions occur recognized earnings ineffective portion cash flow hedge’s change value recognized immediately earnings component operating revenues income statement changes fair value derivatives designated fair value hedges recognized earnings offsets changes fair values related hedged assets liabilities firm commitments formally document relationships hedging instruments hedged items well risk management objectives strategies undertaking various hedge transactions methods assessing testing correlation hedge ineffectiveness hedging instruments linked hedged asset liability firm commitment forecasted transaction also assess whether derivatives highly effective offsetting changes cash flows fair values hedged items discontinue hedge accounting prospectively determine derivative longer highly effective hedge decide discontinue hedging relationship discussion hedging activities follows cash flow hedges majority commodity sales purchases spot market forward market prices use futures forward contracts swaps limit exposure fluctuations commodity markets objective realizing fixed cash flow stream activities also fixed rate foreign currency denominated debt exposes us changes exchange rates foreign currency us dollar use currency swaps convert fixed amounts foreign currency due foreign currency denominated debt us dollar amounts december 31 2004 2003 swaps convert approximately 275 million debt 255 million substantially cancelled payoff underlying hedged debt march 2005 summary impacts cash flow hedges included accumulated comprehensive loss net income taxes december 31 2004 2003 follows 1 reclassifications occur upon physical delivery hedged commodity corresponding expiration hedge forecasted transaction longer probable 2 substantially amounts reclassified income repurchase approximately 528 million debt march 2005 3 december 2002 removed hedging designation derivatives related eurodenominated debt 4 accumulated comprehensive income loss also includes 52 million 45 million net cumulative currency translation adjustments 46 million 24 million additional minimum pension liability december 31 2004 2003 amounts net taxes december 2004 designated number commoditybased derivative contracts fair value loss 592 million hedges 2005 2006 natural gas production result reclassified amount derivatives designated hedges specifically cash flow hedges beginning fourth quarter 2004 years ended december 31 2004 2003 2002 recognized net losses 1 million 2 million 4 million net income taxes loss continuing operations related ineffective portion cash flow hedges fair value hedges fixed rate us dollar foreign currency denominated debt exposes us paying higher market rates interest rates decline use interest rate swaps effectively convert fixed amounts interest due debt agreements variable interest payments based libor plus spread december 31 2004 2003 derivatives net fair value 117 million 33 million specifically derivatives fair value losses 20 million 19 million december 31 2004 2003 converted interest rate 440 million 350 million us dollar denominated debt floating weighted average interest rate libor plus 42 additionally derivatives fair values 137 million 52 million december 31 2004 2003 converted approximately 450 million 350 million debt 511 million 390 million derivatives also converted interest rate debt floating weighted average interest rate libor plus 39 december 31 2004 libor plus 37 december 31 2003 recorded fair value derivatives component longterm debt related accrued interest year ended december 31 2002 net financial statement impact fair value hedges immaterial march 2005 repurchased approximately 528 million debt approximately 100 million hedged fair value hedges result repurchase removed hedging designation subsequently cancelled derivative contracts december 2002 reduced volumes foreign currency exchange risk hedged debt removed hedging designation derivatives net fair value gain 3 million 6 million december 31 2004 2003 amounts reflected longterm debt reclassified income interest principal debt paid 2009 power contract restructuring activities 2001 2002 conducted power contract restructuring activities involved amending terminating power purchase contracts existing power facilities restructuring transaction would eliminate requirement plant provide power generation customer contract usually regulated utility replace requirement new contract gave us ability provide power customer wholesale power market conjunction power restructuring activities marketing trading segment generally entered additional marketbased contracts third parties provide power wholesale power market effectively “locked in” margin restructured transaction difference contracted rate restructured sales contract wholesale market rates purchase contract time prior restructuring power plant related power purchase contract accounted historical cost either cost construction acquired acquisition cost revenues expenses prior restructuring cases accounted accrual basis power generated sold plant following restructuring accounting treatment power purchase agreement changed since restructured contract met definition derivative addition since power plant longer exclusive obligation provide power original dedicated power purchase contract operated peaking merchant facility generating power economical significant change use plant’s carrying value typically written estimated fair value changes also often required us terminate amend related fuel supply andor steam agreements enter third party intercompany contracts transportation agreements associated operating merchant facility finally many cases power contract restructuring activities also involved contract terminations resulted cash payments customer cancel underlying dedicated power contract 2002 completed power contract restructuring consolidated eagle point power facility applied accounting described transaction also employed principles power contract restructuring business reaching settlement dispute nejapa power contract included cash payment us recorded payments operating revenues power segment also terminated power contract consolidated mount carmel facility exchange 50 million cash payment year ended december 31 2002 consolidated power restructuring activities following effects consolidated financial statements millions 1 restructuring activities thirdparty owners also held ownership interests plants allocated portion income loss result credit downgrade economic changes power market longer pursuing additional power contract restructuring activities actively seeking sell otherwise dispose existing restructured power contracts 2004 completed sales ucf restructured eagle point power contract mohawk river funding iv see note 3 discussion sales mohawk river funding iii “mrf iii” prior purchase agreement “usgen ppa” usgen new england inc “usgen” usgen filed chapter 11 bankruptcy protection usgen ppa terminated automatically result bankruptcy filing mrf iii filed proof claim bankruptcy case bankruptcy court issued order resolving claim order final time may subject change could result final award either less receivable recorded additionally march 2005 completed sale cedar brakes ii related restructured derivative power contracts commoditybased derivatives commoditybased derivatives primarily relate historical trading activities include services provide energy sector entered objective generating profits benefiting movements market prices primarily related purchase sale energy commodities derivatives trading portfolio fair value liability 61 million 488 million december 31 2004 2003 december 2004 designated number commoditybased derivative contracts fair value loss 592 million hedges 2005 2006 natural gas production result reclassified amount derivatives designated hedges beginning fourth quarter 2004 credit risk subject credit risk related financial instrument assets credit risk relates risk loss would incur result nonperformance counterparties pursuant terms contractual obligations measure credit risk estimated replacement costs commodities would purchase sell future plus amounts owed counterparties delivered unpaid commodities exposures netted legally enforceable right setoff maintain credit policies regard counterparties price risk management activities minimize overall credit risk policies require evaluation potential counterparties’ financial condition including credit rating ii collateral certain circumstances including cash advance letters credit guarantees iii use margining provisions standard contracts iv use master netting agreements allow netting positive negative exposures various contracts associated single counterparty use daily margining provisions financial contracts physical power agreements master netting agreements require counterparty post cash letters credit fair value contract exceeds daily contractual threshold amount typically tied published credit rating counterparty margining collateral provisions also allow us terminate contract liquidate positions counterparty unable provide required collateral margining provisions required return collateral amount posted collateral exceeds amount collateral required collateral received returned vary significantly day based changes market values counterparty’s credit ratings furthermore amount collateral hold may less fair value derivative contracts counterparty given period following table presents summary counterparties net financial instrument asset exposure december 31 2004 2003 1 “investment grade” “below investment grade” determined using publicly available credit ratings “investment grade” includes counterparties minimum standard poor’s rating bbb moody’s rating baa3 “below investment grade” includes counterparties public credit rating meet criteria “investment grade” “not rated” includes counterparties rated public rating service 2 net asset exposure financial instrument assets primarily relates assets liabilities price risk management activities exposures prepared netting assets liabilities counterparties contractual right offset positions netted include current noncurrent amounts include amounts already billed delivered derivative contracts would netted exposures approximately 125 counterparties energy marketers although counterparties currently rated investment grade one counterparties fails perform case enron see note 17 discussion enron bankruptcy may recognize immediate loss earnings well additional financial impacts future delivery periods extent replacement contract prices quantities cannot established one electric utility customer public service electric gas company pseg comprised 42 percent 66 percent net financial instrument asset exposure december 31 2004 2003 net financial instrument asset exposure pseg eliminated sale interests cedar brakes ii first quarter 2005 concentration counterparties may impact overall exposure credit risk either positively negatively counterparties may similarly affected changes economic regulatory conditions 11 inventory following current inventory december 31 also following noncurrent inventory included assets balance sheets december 31 12 regulatory assets liabilities regulatory assets liabilities included current noncurrent assets liabilities balance sheets balances presented balance sheets gross basis details regulatory assets liabilities regulated interstate systems apply provisions sfas 71 december 31 recoverable various periods 1 amounts included rate base earn current return 13 assets liabilities detail current noncurrent assets liabilities balance sheets december 31 14 property plant equipment december 31 2004 2003 approximately 08 billion 10 billion construction workinprogress included property plant equipment december 31 2004 2003 tgp epng anr excess purchase costs associated acquisition total excess costs pipelines approximately 5 billion accumulated depreciation approximately 13 billion excess costs amortized life related pipeline assets amortization expense three years ended december 31 2004 2003 2002 approximately 76 million 74 million 71 million adoption sfas 142 impact amounts since included part property plant equipment rather goodwill currently earn return excess purchase costs rate payers 15 debt financing obligations credit facilities debt credit facilities consist short longterm borrowings third parties notes affiliated companies 2004 entered new 3 billion credit agreement sold entities debt obligations summary actions follows millions 1 includes proceeds 125 billion term loan new 3 billion credit agreement 2 includes 850 million repayments previous revolving credit facility 3 consists 815 million debt related utility contract funding llc 72 million debt related mohawk river funding iv shortterm financing obligations following shortterm borrowings financing obligations december 31 longterm financing obligations longterm financing obligations outstanding consisted following december 31 2004 date 2005 following changes longterm financing obligations 1 debt consolidated result adopting fin 46 see note 2 fourth quarter 2004 entered agreement enron liquidated two derivative swap agreements approximately 221 million exchange approximately 213 million 65 one year notes subsequent closing new credit agreement notes paid full 3 proceeds 125 billion term loan new credit agreement entered november 2004 4 remaining balance debt obligations eliminated sold interests mohawk river funding iv ucf cedar brakes ii 5 december 2004 january 2005 repurchased 4 yieldtomaturity zerocoupon debentures amount shown principal carrying value date debt retired compared maturity value 2021 206 million december 2004 351 million january 2005 6 march 2005 repaid debt principal balance 528 million carrying value 724 million longterm debt balance sheet december 31 2004 conjunction repayment also terminated derivative contracts fair value 152 million december 31 2004 hedged debt total net payment 579 million see note 10 additional information repurchase derivative contracts aggregate maturities principal amounts longterm financing obligations next 5 years total thereafter follows millions 1 excludes 08 billion zero coupon debentures discussed included 2005 320 million debt associated macae project brazil result event default macae’s nonrecourse debt see note 17 additional details event default also included 2005 approximately 114 million notes debentures holders option redeem 2005 prior stated maturities amount 75 million eligible redemption solely 2005 redeemed reclassified longterm debt 2006 included “thereafter” line table 600 million debentures holders option redeem 2007 prior stated maturities 822 million zero coupon convertible debentures zerocoupon debentures maturity value 16 billion due 2021 yield maturity 4 percent holders cause us repurchase debentures option years 2006 2011 2016 make election choose settle cash common stock price approximates market debentures convertible 7468726 shares common stock based conversion rate 47872 shares per 1000 principal amount maturity rate equal conversion price 94604 per share common stock credit facilities november 2004 replaced previous 3 billion revolving credit facility scheduled mature june 2005 new 3 billion credit agreement group lenders 3 billion credit agreement consists 125 billion fiveyear term loan 1 billion threeyear revolving credit facility 750 million fiveyear letter credit facility certain subsidiaries epng tgp anr cig also continue eligible borrowers new credit agreement additionally el paso certain subsidiaries guaranteed borrowings new credit agreement collateralized interests epng tgp anr cig wic anr storage company southern gas storage company december 31 2004 125 billion outstanding term loan utilized approximately 750 million letter credit facility approximately 04 billion 1 billion revolving credit facility issue letters credit term loan accrues interest libor plus 275 percent matures november 2009 repaid increments 5 million per quarter unpaid balance due maturity new revolving credit facility matures november 2007 borrow funds libor plus 275 percent issue letters credit 275 percent plus fee 025 percent amount issued pay annual commitment fee 075 percent unused capacity revolving credit facility terms new 750 million letter credit facility provides us ability issue letters credit borrow unused capacity letter credit facility revolving loans maturity november 2009 pay libor plus 275 percent amounts borrowed letter credit facility 285 percent letters credit unborrowed funds restrictive covenants restrictive covenants includes restrictions debt levels restrictions liens securing debt guarantees restrictions mergers sales assets capitalization requirements dividend restrictions cross default crossacceleration prepayment debt provisions breach covenants could result acceleration debt financial obligations subsidiaries new credit agreement significant debt covenants cross defaults el paso’s ratio debt consolidated ebitda defined new credit agreement shall exceed 650 10 time prior september 30 2005 625 10 time september 30 2005 prior june 30 2006 600 10 time june 30 2006 maturity b el paso’s ratio consolidated ebitda defined new credit agreement interest expense plus dividends paid shall less 160 10 prior march 31 2006 175 10 march 31 2006 prior march 31 2007 180 10 march 31 2007 maturity c epng tgp anr cig cannot incur incremental debt incurrence incremental debt would cause debt consolidated ebitda ratio defined new credit agreement particular company exceed 5 1 proceeds issuance debt pipeline company borrowers used maintenance expansion capital expenditures investments fercregulated assets fund working capital requirements refinance existing debt e occurrence event default expiration applicable grace period respect debt aggregate principal amount 200 million addition restrictions default provisions andor subsidiaries subject number additional restrictions covenants restrictions covenants include limitations additional debt subsidiaries limitations use proceeds borrowing subsidiaries limitations cases transactions affiliates limitations occurrence liens potential limitations abilities subsidiaries declare pay dividends potential limitations subsidiaries participate cash management program limitations ability prepay debt also issued various guarantees securing financial obligations subsidiaries unaudited affiliates similar covenants facilities respect guarantees issued subsidiaries significant debt covenant addition covenants discussed el paso cgp must maintain minimum net worth 850 million breached amounts guaranteed guaranty agreements could accelerated guaranty agreements also 30 million crossacceleration provision addition three subsidiaries indentures associated public debt contain 5 million crossacceleration provisions indentures state event default occur resulting acceleration debt obligations subsidiaries excess 5 million longterm debt obligations containing provisions could accelerated acceleration debt would adversely affect liquidity position turn financial condition financing arrangements capital trust march 1998 formed el paso energy capital trust wholly owned subsidiary issued 65 million 475 percent trust convertible preferred securities 325 million common securities trust exists sole purpose issuing preferred securities investing proceeds 475 percent convertible subordinated debentures issued due 2028 sole asset trust i’s sole source income interest earned debentures interest income used pay obligations trust i’s preferred securities provide full unconditional guarantee trust i’s preferred securities trust i’s preferred securities nonvoting except limited circumstances pay quarterly distributions annual rate 475 percent carry liquidation value 50 per security plus accrued unpaid distributions convertible common shares time prior close business march 31 2028 option holder rate 12022 common shares trust preferred security equivalent conversion price 4159 per common share 2003 outstanding amounts securities reclassified longterm debt preferred interests subsidiaries result new accounting standard coastal finance coastal finance indirect wholly owned business trust formed may 1998 coastal finance completed public offering 12 million mandatory redemption preferred securities 300 million coastal finance holds subordinated debt securities issued wholly owned subsidiary el paso cgp purchased proceeds preferred securities offering cumulative quarterly distributions paid preferred securities annual rate 8375 percent liquidation amount 25 per preferred security coastal finance i’s source income interest earned subordinated debt securities interest income used pay obligations coastal finance i’s preferred securities preferred securities mandatorily redeemable maturity date may 13 2038 may redeemed option may 13 2003 redemption price paid 25 per preferred security plus accrued unpaid distributions date redemption el paso cgp provides guarantee payment obligations coastal finance related preferred securities extent coastal finance funds available obligation provide funds coastal finance payment redemption preferred securities outside obligation pay interest principal subordinated debt securities 2003 amounts outstanding securities reclassified longterm debt preferred interests subsidiaries result new accounting standard equity security units june 2002 issued 115 million 9 percent equity security units equity security units consist two securities purchase contract pay quarterly contract adjustment payments annual rate 286 percent requires holder buy common stock stated settlement date august 16 2005 ii senior note due august 16 2007 principal amount 50 per unit pay quarterly interest payments annual rate 614 percent senior notes issued total principal value 575 million pledged secure holders’ obligation purchase shares common stock purchase contracts december 2003 completed tender offer exchange 6057953 outstanding equity security units represented approximately 53 percent total units outstanding exchange issued total 15182972 shares common stock total market value 119 million paid 59 million cash remaining purchase contracts settled 2005 contract provides us issue common stock time proceeds allocated common stock additional paidin capital number common shares issued depend prior consecutive 20trading day average closing price common stock determined third trading day immediately prior stock purchase date issue minimum approximately 11 million shares maximum approximately 14 million shares settlement date depending average stock price nonrecourse project financings many power subsidiaries investments borrowed material portion costs acquire construct domestic international power assets borrowings made recourse project company assets ie without recourse el paso occasion events occurred connection several projects either constituted event default loan agreements could constitute event default upon delivery notice lenders failure subsidiary investee cure event applicable grace period currently one consolidated subsidiary macae power taker project petrobras paid amounts owed contract plant nonpayment created event default project loan agreements accordingly classified approximately 320 million current debt december 31 2004 see note 17 additional information investment macae addition several projects account equity investments default loan agreements including saba berkshire east asia power written investment berkshire east asia power facilities 9 million interest saba recourse el paso loans investments addition events default events could lead event default upon notice lenders projects believe defaults material impact subsidiaries’ financial statements letters credit enter letters credit ordinary course operating activities december 31 2004 outstanding letters credit approximately 13 billion 107 million supported cash collateral 12 billion issued credit agreement included amount 09 billion letters credit securing recorded obligations related price risk management activities available capacity shelf registration statements maintain shelf registration statement sec allows us issue combination debt equity instruments including trust preferred securities two wholly owned trusts el paso capital trust ii el paso capital trust iii issue securities trusts would required issue full unconditional guarantees securities december 31 2004 926 million remaining capacity shelf registration statement however unable access capacity january 2006 due untimely filing 2003 annual quarterly 2004 financial statements 16 preferred interests consolidated subsidiaries past entered financing transactions accomplished sale preferred interests consolidated subsidiaries 2003 repaid approximately 2 billion preferred interests reclassified 625 million longterm financing obligations result adopting sfas 150 see note 1 eliminated 300 million consolidation acquired holder preferred interests remaining preferred interest discussed el paso tennessee preferred stock 1996 el paso tennessee pipeline co eptp issued 6 million shares publicly registered 825 percent cumulative preferred stock par value 50 per share 300 million preferred stock redeemable option redemption price equal 50 per share plus accrued unpaid dividends time eptp indirectly owns marketing trading businesses substantially domestic international power businesses tgp required following financial information intended provide additional information eptp preferred security holders 17 commitments contingencies legal proceedings western energy settlement june 2004 master settlement agreement along separate settlement agreements became effective number public private claimants including states california washington oregon nevada resolves principal litigation investigations claims regulatory proceedings arising sale delivery natural gas andor electricity western us western energy settlement part western energy settlement admitted wrongdoing agreed among things make various cash payments modify existing power supply contract also entered joint settlement agreement jsa agreed subject limitations jsa 1 make 329 bcfd capacity available california extent shippers sign firm contracts capacity 2 maintain facilities sufficient physically deliver 329 bcfd california 3 construct facilities completed 2004 4 clarify certain shippers’ recall rights system 5 bar affiliated companies obtaining additional firm capacity epng pipeline system five year period effective date settlement june 2003 el paso california public utilities commission cpuc pacific gas electric company southern california edison company city los angeles filed jsa described ferc november 2003 ferc approved jsa minor modifications east california shippers filed requests rehearing denied ferc march 30 2004 certain shippers appealed ferc’s ruling us court appeals district columbia matter pending expect appeal fully briefed summer 2005 fourth quarter 2002 recorded 899 million pretax charge related western energy settlement 2003 recorded additional pretax charges 104 million based upon reaching definitive settlement agreements charges expenses associated western energy settlement included operations maintenance expense consolidated statements income settlement became effective june 2004 602 million released settling parties amount shown reduction cash flows operations second quarter 2004 amount released 568 million previously held escrow account pending final approval settlement release restricted funds included increase cash flows investing activities remaining obligation december 31 2004 western energy settlement consists discounted 20year cash payment obligation 395 million price reduction power supply contract included price risk management activities connection western energy settlement provided collateral form natural gas oil properties secure remaining cash payment obligation collateral requirement reduced payments 20 year obligation made issue regarding potential tax deductibility western energy settlement charges see note 7 shareholderderivativeerisa litigation shareholder litigation since 2002 twentynine purported shareholder class action lawsuits alleging violations federal securities laws filed us several current former officers directors one lawsuits dismissed remaining 28 lawsuits consolidated federal court houston texas consolidated lawsuit generally challenges accuracy completeness press releases public statements made class period 2001 early 2004 related wash trades marktomarket accounting offbalance sheet debt overstatement oil gas reserves manipulation california energy market consolidated lawsuit currently stayed derivative litigation since 2002 five shareholder derivative actions also filed three actions allege claims consolidated shareholder class action suit described one actions including claim compensation disgorgement certain individuals actions currently stayed two actions consolidated state court houston texas generally allege manipulation california gas prices exposed us claims antitrust conspiracy ferc penalties erosion share value erisa class action suits december 2002 purported class action lawsuit entitled william h lewis iii v el paso corporation et al filed us district court southern district texas alleging generally direct indirect communications participants el paso corporation retirement savings plan included misrepresentations omissions caused members class hold maintain investments el paso stock violation employee retirement income security act erisa lawsuit subsequently amended include allegations relating reporting natural gas oil reserves lawsuit stayed representatives insurance coverages applicable shareholder derivative erisa lawsuits certain deductibles copay obligations insurance coverages established certain accruals believe adequate cash balance plan lawsuit december 2004 lawsuit entitled tomlinson et al v el paso corporation el paso corporation pension plan filed us district court denver colorado lawsuit seeks class action status alleges change final average earnings formula pension plan cash balance pension plan accrual benefits plan communications change violate erisa andor age discrimination employment act costs legal exposure related lawsuit currently determinable retiree medical benefits matters currently serve plan administrator medical benefits plan covers closed group retirees case corporation retired june 30 1994 case formerly subsidiary tenneco inc spun prior acquisition tenneco 1996 connection tennecocase reorganization agreement 1994 tenneco assumed obligation provide certain medical prescription drug benefits eligible retirees spouses assumed obligation result merger tenneco however believe liability benefits limited certain maximums caps costs excess maximums assumed plan participants 2002 case sued individual retirees federal court detroit michigan action entitled yolton et al v el paso tennessee pipeline company case corporation suit alleges among things el paso violated erisa case required pay amounts cap although amounts vary time amounts cap recently approximately 18 million per month case filed claims el paso asserting el paso obligated indemnify defend hold case harmless amounts would required pay february 2004 judge ruled case would required pay amounts incurred cap furthermore september 2004 judge ruled pending resolution matter el paso must indemnify reimburse case monthly amounts cap motion reconsideration orders denied november 2004 rulings appealed meantime el paso indemnify case payments case makes cap believe meritorious defenses plaintiffs’ claims case’s crossclaim required ultimately pay future amounts cap case found responsible amounts exposure could high 400 million undiscounted basis natural gas commodities litigation beginning august 2003 several lawsuits filed el paso el paso marketing lp epm formerly el paso merchant energy lp affiliate plaintiffs alleged part el paso epm energy companies conspired manipulate price natural gas providing false price reporting information industry trade publications published gas indices cases filed united states district court southern district new york follows cornerstone propane partners lp v reliant energy services inc et al roberto e calle gracey v american electric power company inc et al dominick viola v reliant energy services inc et al december 2003 cases consolidated others single master file federal court new york pretrial purposes september 2004 court dismissed el paso master litigation epm approximately 27 energy companies remain litigation january 2005 purported class action lawsuit styled leggett et al v duke energy corporation et al filed el paso epm number energy companies chancery court tennessee twentyfifth judicial district somerville behalf residential commercial purchasers natural gas state tennessee past three years plaintiffs allege defendants conspired manipulate price natural gas providing false price reporting information industry trade publications published gas indices company also similar claims asserted individual commercial customers costs legal exposure related lawsuits claims currently determinable grynberg number subsidiaries named defendants actions filed 1997 brought jack grynberg behalf us government false claims act generally complaints allege industrywide conspiracy underreport heating value well volumes natural gas produced federal native american lands deprived us government royalties plaintiff case seeks royalties contends government received volume heating value differently measured analyzed calculated reported together interest treble damages civil penalties expenses future injunctive relief require defendants adopt allegedly appropriate gas measurement practices monetary relief specified case matters consolidated pretrial purposes natural gas royalties qui tam litigation us district court district wyoming filed june 1997 motions dismiss filed behalf defendants costs legal exposure related lawsuits claims currently determinable price formerly quinque number subsidiaries named defendants price et al v gas pipelines predecessors et al filed 1999 district court stevens county kansas plaintiffs allege defendants mismeasured natural gas volumes heating content natural gas nonfederal nonnative american lands seek recover royalties contend received volume heating value natural gas produced properties differently measured analyzed calculated reported together prejudgment postjudgment interest punitive damages treble damages attorneys’ fees costs expenses future injunctive relief require defendants adopt allegedly appropriate gas measurement practices monetary relief specified case plaintiffs’ motion class certification nationwide class natural gas working interest owners natural gas royalty owners denied april 2003 plaintiffs granted leave file fourth amended petition narrows proposed class royalty owners wells kansas wyoming colorado removes claims heating content second class action since filed heating content claims plaintiffs filed motions class certification proceedings defendants filed briefs opposition thereto costs legal exposure related lawsuits claims currently determinable bank america named defendant along burlington resources inc two class action lawsuits styled bank america et al v el paso natural gas company et al deane w moore et al v burlington northern inc et al filed 1997 district court washita county state oklahoma subsequently consolidated court plaintiffs seek accounting damages alleged royalty underpayments 1982 present natural gas produced specified wells oklahoma plus interest time amounts allegedly due well punitive damages court certified plaintiff classes royalty overriding royalty interest owners parties completed discovery plaintiffs filed expert reports alleging damages excess 1 billion pursuant recent summary judgment decision court ruled claims previously released settlement altheide v meridian nationwide royalty class action burlington affiliates barred reasserted action believe ruling eliminates material yet unquantified portion alleged class damages burlington accepted tender defense cases 1997 pursuant spinoff agreement entered 1992 epng burlington resources inc defending matter since time end 2003 asserted contractual claims indemnity us third action styled bank america et al v el paso natural gas burlington resources oil gas company filed october 2003 district court kiowa county oklahoma asserting similar claims specified shallow wells oklahoma texas new mexico defendants succeeded transferring action washita county class certified filed action styled el paso natural gas company v burlington resources inc burlington resources oil gas company lp burlington state court harris county relating indemnity issues burlington us action currently stayed believe substantial defenses plaintiffs’ claims well claims indemnity burlington costs legal exposure related lawsuits claims currently determinable araucaria 60 percent interest 484 mw gasfired power project known araucaria project located near curitiba brazil araucaria project 20year power purchase agreement ppa governmentcontrolled regional utility december 2002 utility ceased making payments project result araucaria project utility currently involved international arbitration ppa curitiba court ruled arbitration clause ppa invalid enjoined project company prosecuting arbitration penalty approximately 173000 daily fines project company appealing ruling obtained stay order imposition daily fines pending outcome appeal investment araucaria project 186 million december 31 2004 political risk insurance covers portion investment project based future outcome dispute ppa depending ability collect amounts utility political risk insurance policies could required write value investment macae 928 mw gasfired power plant known macae project located near city macae brazil property plant equipment net book value 700 million december 31 2004 macae project revenues derived sales spot market bilateral contracts minimum capacity revenue payments minimum capacity energy revenue payments macae project paid petrobras august 2007 participation agreement petrobras failed make payments due participation agreement december 2004 january 2005 petrobras obtained ruling brazilian court directing petrobras deposit onehalf payments court account pay us half appealing ruling petrobras also failed make payments required court order december 31 2004 accounts receivable balance approximately 20 million petrobras also filed notice arbitration international arbitration institution effectively seeks rescission participation agreement reimbursement portion capacity payments made claim successful would result termination minimum revenue payments well petrobras’s obligation provide firm gas supply project 2012 believe substantial defenses claims petrobras vigorously defend legal rights addition continue seek reasonable negotiated settlements dispute including restructuring participation agreement sale plant macae nonrecourse debt approximately 320 million december 31 2004 petrobras’ nonpayment created event default applicable loan agreements result classified entire 320 million debt current also restricted cash balances approximately 76 million december 31 2004 reflected current assets related required debt service reserve balances debt service payment accounts funds held future distribution macae also issued cash collateralized letters credit approximately 47 million part funding required debt service reserve accounts restricted cash related letters credit also classified current asset light default petrobras participation agreement potential inability macae continue make ongoing payments loan agreements one lenders could exercise certain remedies loan agreements future one could acceleration amounts owed loan agreements could ultimately result lenders foreclosing macae project light pending arbitration proceedings evaluated whether impairment investment project required december 31 2004 based upon review possible outcomes arbitration potential settlements dispute believe impairment investment required time however assessment potential outcomes arbitration settlement opportunities changes may required write investment project event lenders call loans ultimately foreclose project loss would approximately 500 million december 31 2004 new information becomes available future material developments occur reassess carrying value investment mtbe compliance 1990 amendments clean air act used gasoline additive methyl tertiarybutyl ether mtbe gasoline also produced bought sold distributed mtbe number lawsuits filed throughout us regarding mtbe’s potential impact water supplies subsidiaries among defendants 60 lawsuits result ruling issued march 16 2004 suits process consolidated pretrial purposes multidistrict litigation us district court southern district new york plaintiffs certain state attorneys general various water districts seek remediation groundwater prevention future contamination variety compensatory damages punitive damages attorney’s fees court costs legal exposure related lawsuits currently determinable wise arbitration william wise former chief executive officer initiated arbitration proceeding alleging breached employment agreements failing make certain payments following departure el paso 2003 discovery underway hearing scheduled summer 2005 government investigations power restructuring october 2003 announced sec authorized staff fort worth regional office conduct investigation certain aspects periodic reports filed sec investigation appears focused principally power plant contract restructurings related disclosures accounting treatment restructured power contracts including particular eagle point restructuring transaction completed 2002 cooperated sec investigation wash trades june 2002 received informal inquiry sec regarding issue round trip trades although believe round trip trades occurred submitted data sec july 2002 july 2002 received federal grand jury subpoena documents concerning round trip wash trades complied requests also cooperated us attorney regarding investigation specific transactions executed connection hedges natural gas oil production restatement hedges price reporting october 2002 ferc issued data requests regarding price reporting transactional data energy trade press provided information ferc commodity futures trading commission cftc us attorney response requests first quarter 2003 announced settlement cftc price reporting matter providing payment civil monetary penalty epm 20 million 10 million payable 2006 without admitting denying cftc holdings order continuing cooperate us attorney’s investigation matter reserve revisions march 2004 received subpoena sec requesting documents relating december 31 2003 natural gas oil reserve revisions also received federal grand jury subpoenas documents regard reserve revisions cooperating sec’s us attorney’s investigations matter storage reporting november 2004 anr tgp received data request ferc connection investigation weekly storage withdrawal number reported energy information administration eia eastern region november 24 2004 subsequently revised downward eia specifically anr tgp provided information weekly eia submissions two weeks november 2004 neither anr tgp’s submissions eia revised subsequent original submissions although anr made correction one daily posting electronic bulletin board period postings unrelated eia submissions december 2004 anr received similar data request cftc anr provided requested information december 17 2004 ferc held press conference disclosed inquiry determined unaffiliated third party source downward revision iraq oil sales september 2004 coastal corporation known el paso cgp company acquired january 2001 received subpoena grand jury us district court southern district new york produce records regarding united nations’ oil food program governing sales iraqi oil subpoena seeks various records relating transactions oil iraqi origin period 1995 2003 november 2004 received order sec provide written statement connection coastal el paso’s participation oil food program also received informal requests information documents united states senate’s permanent subcommittee investigations house representatives international relations committee related coastal’s purchases iraqi crude oil food program cooperating us attorney’s sec’s senate subcommittee’s house committee’s investigations matter carlsbad august 2000 main transmission line owned operated epng ruptured crossing pecos river near carlsbad new mexico twelve individuals site fatally injured june 2001 us department transportation’s office pipeline safety issued notice probable violation proposed civil penalty epng notice alleged five violations dot regulations proposed fines totaling 25 million proposed corrective actions epng fully accrued fines october 2001 epng filed response office pipeline safety disputing alleged violations december 2003 matter referred department justice public hearing conducted national transportation safety board ntsb investigation carlsbad rupture ntsb published final report april 2003 ntsb stated determined probable cause august 2000 rupture significant reduction pipe wall thickness due severe internal corrosion occurred epng’s corrosion control program “failed prevent detect control internal corrosion” pipeline ntsb also determined ineffective federal preaccident inspections contributed accident identifying deficiencies epng’s internal corrosion control program november 2002 epng received federal grand jury subpoena documents related carlsbad rupture cooperated fully responding subpoena since expired december 2003 january 2004 eight current former employees served testimonial subpoenas issued grand jury six individuals testified march 2004 april 2004 epng received new federal grand jury subpoena requesting additional documents responded fully subpoena two additional employees testified grand jury june 2004 number civil actions filed epng connection rupture settled fully covered insurance addition matters subsidiaries affiliates named defendants numerous lawsuits governmental proceedings arise ordinary course business also regulatory rules orders various stages adoption review andor implementation none believe material impact us rates regulatory matters pipeline integrity costs november 2004 ferc issued proposed accounting release may impact certain costs interstate pipelines incur related pipeline integrity programs release enacted written would required expense certain future pipeline integrity costs instead capitalizing part property plant equipment although continue evaluate impact potential accounting release currently estimate release enacted written would required expense additional amount pipeline integrity expenditures range approximately 25 million 41 million annually next eight years inquiry regarding income tax allowances december 2004 ferc issued notice inquiry noi response recent dc circuit decision held ferc adequately justified policy providing certain oil pipeline limited partnership income tax allowance equal proportion limited partnership interests owned corporate partners ferc sought comments whether court’s reasoning applied partnerships ownership structures interests nontaxable entities could affected ruling cannot predict impact inquiry interstate pipelines including pipelines jointly owned unaffiliated parties selective discounting notice inquiry november 2004 ferc issued noi seeking comments policy regarding selective discounting natural gas pipelines ferc seeks comments regarding whether practice permitting pipelines adjust ratemaking throughput downward rate cases reflect discounts given pipelines competitive reasons appropriate discount given meet competition another natural gas pipeline pipelines filed comments noi neither final outcome inquiry impact pipelines predicted certainty contingencies enron bankruptcy december 2001 enron corp number subsidiaries including enron north america corp ena enron power marketing inc epmi filed chapter 11 bankruptcy protection new york various contracts enron marketing trading entities tradingrelated contracts terminated due bankruptcy october 2002 filed proofs claims enron trading entities totaling approximately 317 million enron trading claims largely sold settled original claims trading entities enron particular june 24 2004 bankruptcy court approved settlement agreement enron resolved trading merchant issues parties final payments made third quarter 2004 remaining trading claims involve european trading businesses claims enron capital trade resources limited subject separate proceedings united kingdom addition corresponding claim enron corp based corporate guarantee considering valuation setoff arguments reserves established believe overall remaining trading exposure enron 3 million enron pipeline claims addition various enron subsidiaries transportation contracts several pipeline systems transportation contracts rejected pipeline subsidiaries filed proofs claim totaling approximately 137 million epng filed largest proof claim amount approximately 128 million included 18 million amounts due services provided date contracts rejected 110 million damage claims arising rejection transportation contracts epng expects enron vigorously contest claims remaining pipeline claimants anr tgp wic various stages attempting resolve claims enron given uncertainty bankruptcy process results uncertain fully reserved amounts due date contracts rejected recognized amounts contracts since time brazilian matters number interests various production properties power pipeline assets brazil total investment brazil approximately 16 billion december 31 2004 although economic conditions generally improved last year brazil experienced high interest rates local debt experienced restrictions availability foreign funds investment addition number assets investments petrobras either serves joint owner customer shipper asset project although material current disputes petrobras regard ownership operation production pipeline assets current disputes macae power plant us petrobras may negatively impact investments impact could material also investment power plant brazil called porto velho porto velho project process negotiating certain provisions ppas eletronorte including amount installed capacity energy prices take pay levels term first ppa issues addition october 2004 project experienced outage steam turbine resulted partial reduction plant’s capacity project expects replace repair steam turbine first quarter 2006 uncertain impact outage ppas although current terms ppas proposed amendments indicate impairment investment may required write value investment negotiations resolved unfavorably investment porto velho 292 million december 31 2004 outstanding legal contingent matters evaluate merits item exposure matter possible legal settlement strategies likelihood unfavorable outcome determine unfavorable outcome probable estimated establish necessary accruals outcome matters cannot predicted certainty still uncertainties related costs may incur based upon evaluation experience date believe established appropriate reserves matters however possible new information future developments could require us reassess potential exposure related matters adjust accruals accordingly december 31 2004 approximately 592 million net related insurance receivables accrued outstanding legal contingencies including amounts accrued western energy settlement environmental matters subject federal state local laws regulations governing environmental quality pollution control laws regulations require us remove remedy effect environment disposal release specified substances current former operating sites december 31 2004 accrued approximately 380 million including approximately 373 million expected remediation costs associated onsite offsite groundwater technical studies approximately 7 million related environmental legal costs anticipate incurring 2027 380 million accrual 100 million reserved facilities currently operate 280 million reserved nonoperating sites facilities shut sold superfund sites reserve estimates range approximately 380 million approximately 547 million accrual represents combination two estimation methodologies first likely outcome reasonably estimated cost accrued 82 million second likely outcome cannot estimated range costs established 298 million 465 million one amount range likely lower end expected range accrued type site reserves based following estimates reasonably possible outcomes reconciliation accrued liability january 1 2004 december 31 2004 millions 2005 estimate total remediation expenditures approximately 64 million addition expect make capital expenditures environmental matters approximately 62 million aggregate years 2005 2009 expenditures primarily relate compliance clean air regulations internal pcb remediation project since 1988 tgp subsidiary engaged internal project identify address presence polychlorinated biphenyls pcbs substances including epa list hazardous substances hsl compressor stations facilities operates conducting project tgp frequent contact federal state regulatory agencies informal negotiation formal entry consent orders tgp executed consent order 1994 epa governing remediation relevant compressor stations working epa relevant states regarding remediation activities tgp also working pennsylvania new york environmental agencies regarding remediation postremediation activities pennsylvania new york stations pcb cost recoveries may 1995 following negotiations customers tgp filed agreement ferc established mechanism recovering substantial portion environmental costs identified internal remediation project agreement approved ferc november 1995 provided pcb surcharge firm interruptible customers’ rates pay eligible remediation costs surcharges collected defined collection period tgp received approval ferc extend collection period currently set expire june 2006 agreement also provided biannual audits eligible costs december 31 2004 tgp precollected pcb costs approximately 125 million precollected amount reduced future eligible costs incurred remainder remediation project extent actual eligible expenditures less amounts precollected tgp refund customers difference plus carrying charges incurred date refunds december 31 2004 tgp recorded regulatory liability included noncurrent liabilities balance sheet 97 million estimated future refund obligations cercla matters received notice could designated asked information determine whether could designated potentially responsible party prp respect 61 active sites comprehensive environmental response compensation liability act cercla state equivalents sought resolve liability prp sites indemnification thirdparties settlements provide payment allocable share remediation costs december 31 2004 estimated share remediation costs sites 31 million 52 million since cleanup costs estimates subject revision information becomes available extent remediation required cases asserted defense liability estimates could change moreover liability federal cercla statute joint several meaning could required pay excess pro rata share remediation costs understanding financial strength prps considered appropriate estimating liabilities accruals issues included previously indicated estimates superfund sites possible new information future developments could require us reassess potential exposure related environmental matters may incur significant costs liabilities order comply existing environmental laws regulations also possible developments increasingly strict environmental laws regulations claims damages property employees persons environment resulting current past operations could result substantial costs liabilities future information becomes available relevant developments occur adjust accrual amounts accordingly still uncertainties relating ultimate costs may incur based upon evaluation experience date believe current environmental reserves adequate commitments purchase obligations operating leases maintain operating leases ordinary course business activities leases include office space operating facilities office operating equipment terms agreements vary 2005 2053 december 31 2004 total commitments operating leases approximately 442 million minimum annual rental commitments operating leases december 31 2004 follows aggregate minimum commitments reduced minimum sublease rentals approximately 28 million due future noncancelable subleases rental expense operating leases years ended december 31 2004 2003 2002 101 million 113 million 116 million may 2004 announced would consolidate houstonbased operations one location consolidation substantially completed end 2004 result december 31 2004 established accrual totaling 80 million record liability net sublease rentals obligations existing lease terms currently lease approximately 888000 square feet office space buildings vacating various leases lease terms expiring 2014 see note 4 additional information regarding lease terminations guarantees involved various joint ventures ownership arrangements sometimes require additional financial support results issuance financial performance guarantees financial guarantee obligated make payments guaranteed party fails make payments violates terms financial arrangement performance guarantee provide assurance guaranteed party execute terms contract required perform behalf also periodically provide indemnification arrangements related assets businesses sold arrangements include indemnification income taxes resolution existing disputes environmental matters necessary expenditures ensure safety integrity assets sold evaluate time guarantee indemnity arrangement entered period thereafter whether liability exists estimated record accruals criteria met december 31 2004 accrued 70 million related arrangements december 31 2004 approximately 40 million financial performance guarantees indemnification arrangements otherwise reflected financial statements commercial commitments various commercial commitments purchase obligations recorded balance sheet december 31 2004 firm commitments tolling transportation storage capacity contracts 15 billion commodity purchase commitments 149 million purchase capital commitments including maintenance engineering procurement construction contracts 224 million 18 retirement benefits pension benefits primary pension plan defined benefit plan covers substantially us employees provides benefits cash balance formula certain employees participated prior pension plans el paso sonat coastal receive greater cash balance benefits transition benefits prior plan formulas transition benefits reflect prior plan accruals employees december 31 2001 december 31 2004 march 31 2006 anticipate making contributions pension plan 2005 addition primary pension plan maintain supplemental executive retirement plan serp provides additional benefits selected officers key management serp provides benefits excess certain irs limits essentially mirror primary pension plan also maintain two pension plans closed new participants provide benefits former employees previously discontinued coal convenience store operations serp frozen plans together referred pension plans also participate one multiemployer pension plan benefit former employees union members contributions plan 2004 2003 2002 material expect contribute 5 million serp 2005 anticipate making contributions pension plans 2005 2004 recognized 4 million curtailment benefit pension plans primarily related reduction number employees participate pension plan resulted various asset sales employee severance efforts 2003 recognized 11 million charges pension plans resulted employee terminations internal reorganization retirement savings plan maintain defined contribution plan covering us employees prior may 1 2002 matched 75 percent participant basic contributions 6 percent matching contributions made plan’s stock fund participants could diversify time may 1 2002 plan amended allow company matching contributions invested manner participant contributions effective march 1 2003 suspended matching contributions reinstituted rate 50 percent participant basic contributions 6 percent july 1 2003 effective july 1 2004 increased matching contributions 75 percent participant basic contributions 6 percent amounts expensed plan approximately 16 million 14 million 28 million years ended december 31 2004 2003 2002 postretirement benefits provide postretirement medical benefits closed groups retired employees limited postretirement life insurance benefits current retired employees postretirement employee benefits opeb regulated pipeline companies prefunded extent costs recoverable rates extent actual opeb costs regulated pipeline companies differ amounts recovered rates regulatory asset liability recorded expect contribute 63 million postretirement plans 2005 medical benefits closed groups retirees may subject deductibles copayment provisions limitations dollar caps amount employer costs reserve right change benefits projected benefit obligation accumulated benefit obligation fair value plan assets september 30 plan measurement date related balance sheet accounts pension plans december 31 information pension plans accumulated benefit obligations excess plan assets year ended december 31 required recognize additional minimum liability pension plans accumulated benefit obligation excess plan assets recorded comprehensive income loss 33 million 2004 18 million 2003 related change additional minimum liability change projected benefit obligation change plan assets reconciliation funded status pension postretirement benefit plans benefits presented computed twelve months ended september 30 1 decrease unrecognized net actuarial loss pension benefits primarily due historical changes assumptions discount rates expected return plan assets rate compensation increase recognize difference actual return expected return three year period permitted sfas 87 decrease unrecognized net actuarial loss postretirement benefits primarily due adoption fsp 1062 portion postretirement benefit obligation included current liabilities 38 million 45 million december 31 2004 2003 future benefits expected paid pension plans postretirement plans december 31 2004 follows 1 includes reduction 3 million year excluding 2005 expected subsidy related medicare prescription drug improvement modernization act 2003 years ended december 31 components net benefit cost income follows 1 permitted amortization prior service cost determined using straightline amortization cost average remaining service period employees expected receive benefits plan projected benefit obligations net benefit cost based actuarial estimates assumptions following table details weightedaverage actuarial assumptions used determining projected benefit obligation net benefit costs pension postretirement plans 2004 2003 2002 1 expected return plan assets pretax rate tax rate ranging 26 percent 27 percent postretirement benefits primarily based expected riskfree investment return adjusted historical risk premiums specific risk adjustments associated debt equity securities expected returns weighted based target asset allocations investment portfolio 2005 assumed expected return assets pension benefits reduced 8 percent actuarial estimates postretirement benefit plans assumed weightedaverage annual rate increase per capita costs covered health care benefits 100 percent 2004 gradually decreasing 55 percent year 2009 assumed health care cost trends significant effect amounts reported postretirement benefit plans onepercentage point change assumed health care cost trends would following effects september 30 plan assets following table provides target actual asset allocations pension postretirement benefit plans september 30 1 actuals pension plans include 42 million 18 percent total assets 33 million 15 percent total assets common stock september 30 2004 september 30 2003 primary investment objective plans ensure longterm life plans adequate pool sufficiently liquid assets support benefit obligations participants retirees beneficiaries exists meeting objective plans seek achieve high level investment return consistent prudent level portfolio risk investment objectives longterm nature covering typical market cycles three five years shortfall investment performance compared investment objectives result general economic capital market conditions 2003 modified target asset allocations postretirement benefit plans increase equity allocation 65 percent total plan assets result actual assets september 30 2004 close targets 2004 modified target actual asset allocations pension plans reduce equity allocation 60 percent total plan assets correspondingly 2005 assumption related expected return plan assets reduced 85 percent 80 percent reflect change 19 capital stock common stock 2003 2004 issued 264 million shares satisfy obligations western energy settlement see note 17 2003 also issued 15 million shares part offer exchange equity security units common stock see note 15 dividend year ended december 31 2004 paid dividends 101 million common stockholders february 18 2005 declared quarterly dividends 004 per share common stock payable april 4 2005 shareholders record march 4 2005 dividends common stock treated reduction paidincapital since currently accumulated deficit el paso tennessee pipeline co subsidiary pays dividends approximately 6 million quarter series cumulative preferred stock 825 percent per annum 20625 percent per quarter 20 stockbased compensation grant stock awards various stock option plans account stock option plans using accounting principles board opinion 25 related interpretations employee plans may issue incentive stock options common stock intended qualify section 422 internal revenue code nonqualified stock options restricted stock appreciation rights phantom stock options performance units nonemployee director plan may issue deferred shares common stock reserved approximately 68 million shares common stock existing future stock awards including deferred shares december 31 2004 approximately 28 million shares remained unissued nonqualified stock options granted nonqualified stock options employees 2004 2003 2002 stock options contractual terms 10 years generally vest completion one five years continuous employment grant date prior 2004 also granted options nonemployee members board directors fair market value grant date exercisable immediately summary stock option transactions stock options outstanding stock options exercisable december 31 presented 1 includes conversion stock options common stock cash cost employees based upon achievement certain performance targets lapse time options original stated exercise price approximately 43 per share 42 per share 2004 2003 following table summarizes range exercise prices weightedaverage remaining contractual life options outstanding range exercise prices options exercisable december 31 2004 fair value stock option granted used complete pro forma net income disclosures see note 1 estimated date grant using blackscholes optionpricing model following weightedaverage assumptions restricted stock stockbased compensation plans limited number shares restricted common stock may granted officers employees shares carry voting dividend rights however sale transfer shares restricted stock awards vest specific period time andor achieve established performance targets restricted stock awards representing 31 million 04 million 14 million shares granted 2004 2003 2002 weightedaverage grant date fair value 863 746 3845 per share december 31 2004 39 million shares restricted stock outstanding value restricted shares subject performance vesting determined based fair market value date performance targets achieved value charged compensation expense ratably required service restriction period value time vested restricted shares determined issuance date cost amortized compensation expense vesting period 2004 2003 2002 charges totaled 23 million 60 million 73 million 20 million balance sheet december 31 2004 related unamortized compensation charged expense vesting period restricted stock performance units past awarded eligible officers performance units payable cash stock end vesting period final value performance units varied according plan granted usually based common stock price end vesting period total shareholder return vesting period relative peer group value performance units charged ratably compensation expense vesting period periodic adjustments account fluctuation market price stock changes expected total shareholder return recorded credit compensation expense 2002 11 million upon reduction performance unit liability 21 million due reduction expected total shareholder return july 2003 outstanding performance units vested “below threshold” level compensation committee board directors determined would payout performance units accordingly reversed remaining liability units recorded income 16 million employee stock purchase program october 1999 implemented employee stock purchase plan section 423 internal revenue code plan allowed participating employees right purchase common stock quarterly basis 85 percent lower market price beginning end calendar quarter five million shares common stock authorized issuance plan year ended december 31 2002 sold 14 million shares common stock employees effective january 1 2003 suspended employee stock purchase program 21 business segment information 2004 reorganized business structure two primary business lines regulated nonregulated modified operating segments historically operating segments included pipelines production merchant energy field services result reorganization eliminated merchant energy segment established individual power marketing trading segments periods presented reflect change segments regulated business consists pipelines segment nonregulated businesses consist production marketing trading power field services segments strategic business units provide variety energy products services managed separately segment requires different technology marketing strategies corporate operations include general administrative functions well telecommunications business various contracts assets immaterial assets contracts include financial services lng related items first quarter 2004 reclassified petroleum ship charter operations discontinued operations continuing corporate operations second quarter 2004 reclassified canadian certain international natural gas oil production operations production segment discontinued operations operating results periods presented reflect changes pipelines segment provides natural gas transmission storage related services primarily us conduct activities primarily eight wholly owned four partially owned interstate transmission systems along five underground natural gas storage entities lng terminalling facility production segment engaged exploration acquisition development production natural gas oil natural gas liquids primarily united states brazil us production onshore operations properties 20 states offshore operations properties federal state waters gulf mexico marketing trading segment’s operations focus marketing natural gas oil production management remaining trading portfolio power segment owns interests domestic international power assets december 31 2004 power segment primarily consisted international power business historically segment also domestic power plant operations domestic power contract restructuring business sold announced sale substantially domestic businesses ongoing focus within power segment maximize value assets brazil field services segment conducts midstream activities related remaining gathering processing assets customers whose revenues exceeded 10 percent total revenues 2004 2003 2002 use earnings interest expense income taxes ebit assess operating results effectiveness business segments define ebit net income loss adjusted items impact income loss continuing operations extraordinary items discontinued operations impact accounting changes ii income taxes iii interest debt expense iv distributions preferred interests consolidated subsidiaries business operations consist consolidated businesses well substantial investments unconsolidated affiliates believe ebit useful investors allows effectively evaluate performance businesses investments also exclude interest debt expense distributions preferred interests consolidated subsidiaries investors may evaluate operating results without regard financing methods capital structure ebit may comparable measures used companies additionally ebit considered conjunction net income performance measures operating income operating cash flow reconciliation ebit income loss continuing operations three years ended december 31 ’ following tables reflect segment results three years ended december 31 1 includes eliminations intercompany transactions 308 million intersegment revenues along intersegment operating expenses incurred normal course business operating segments record intersegment revenue operation maintenance expense elimination 25 million included “corporate” column remove intersegment transactions 2 revenues external customers include gains losses related hedging price risk associated natural gas oil production intersegment revenues represent sales marketing trading segment responsible marketing production 3 excludes assets discontinued operations 106 million see note 3 4 total foreign assets approximately 13 billion relates property plant equipment approximately 15 billion relates investments advances unconsolidated affiliates 5 amounts net third party reimbursements capital expenditures returns invested capital 1 includes eliminations intercompany transactions 316 million intersegment revenues along intersegment operating expenses incurred normal course business operating segments record intersegment revenue operation maintenance expense elimination 59 million included “corporate” column remove intersegment transactions 2 revenues external customers include gains losses related hedging price risk associated natural gas oil production intersegment revenues represent sales marketing trading segment responsible marketing production 3 relates intercompany activities continuing operations discontinued operations 4 excludes assets discontinued operations 18 billion see note 3 5 amounts net third party reimbursements capital expenditures returns invested capital power segment includes 1 billion acquire remaining interest chaparral gemstone see note 2 1 includes eliminations intercompany transactions 213 million intersegment revenues along intersegment operating expenses incurred normal course business operating segments record intersegment revenue operation maintenance expense elimination 41 million included “corporate” column remove intersegment transactions 2 revenues external customers include gains losses related hedging price risk associated natural gas oil production intersegment revenues represent sales marketing trading segment responsible marketing production 3 relates intercompany activities continuing operations discontinued operations 4 excludes assets discontinued operations 45 billion see note 3 5 amounts net third party reimbursements capital expenditures returns invested capital 22 investments earnings transactions unconsolidated affiliates hold investments various unconsolidated affiliates accounted using equity method accounting principal equity method investees international pipelines interstate pipelines power generation plants gathering systems investment balance less equity net assets investments 265 million 136 million december 31 2004 2003 differences primarily relate unamortized purchase price adjustments net asset impairment charges net ownership interest investments earnings losses unconsolidated affiliates follows year ended december 31 1 december 31 2003 owned effective 50 percent interest one percent general partner gulfterra approximately 178 percent partnership’s common units outstanding series c units 2004 sold remaining interest gulfterra enterprise cash equity interests enterprise recognized 507 million gain december 31 2004 ownership consisted 99 percent interest two percent general partner enterprise approximately 37 percent enterprise’s common units january 2005 sold remaining interests enterprise discussion interests gulfterra enterprise see page 165 2 ownership interest consists 381 percent general partner interest 54 percent limited partner interest 3 includes 47 percent general partner interest great lakes gas transmission limited partnership 3 percent limited partner interest ownership great lakes gas transmission company 4 2003 completed sale transfer interest investment 5 2004 completed sale interest investment 6 consolidated 2004 7 investment consolidated 2003 8 investment araucaria power included diamond power gemstone prior 2003 9 signed agreement sell interest project expect close transaction first half 2005 10 december 31 2004 2003 also outstanding advances 64 million 90 million related investment habibullah power also outstanding advances 318 million 327 million related foreign investments december 31 2004 2003 307 million 290 million related investment porto velho 11 consists investments power facility pipeline 2002 sold investment power facility 12 impaired 2002 due inability recover investment earnings generated 2003 2004 improve recoverability investment sold interest march 2005 impairment charges gains losses sales equity investments included earnings losses unconsolidated affiliates 2004 2003 2002 consisted following 1 september 2004 connection closing merger gulfterra enterprise sold affiliates enterprise substantially interests gulfterra see discussion gulfterra beginning page 165 2 includes impairments investments korea independent energy corporation meizhou wan generating habibullah power saba power company several foreign power investments 3 includes loss sale bastrop company gains sale several domestic investments 4 2003 sold 50 percent equity consolidated subsidiary holds 1 percent general partner interest recorded minority interest balance sheet 5 december 2003 transferred ownership interest milford lenders order terminate obligations associated milford summarized financial information proportionate share unconsolidated affiliates information includes affiliates hold less 50 percent interest well hold greater 50 percent interest received distributions dividends 358 million 398 million 2004 2003 includes 23 million 53 million returns capital investments proportional shares unconsolidated affiliates hold greater 50 percent interest net income 15 million 119 million 26 million 2004 2003 2002 total assets 734 million 11 billion december 31 2004 2003 summarized financial information gulfterra millions following table shows revenues charges resulting transactions unconsolidated affiliates chaparral gemstone december 31 2002 held equity investments chaparral gemstone 2003 acquired remaining third party equity interests voting rights entities discussed note 2 consolidated chaparral effective january 1 2003 gemstone effective april 1 2003 gulfterra prior sale interests gulfterra september 30 2004 field services segment managed gulfterra’s daily operations performed gulfterra’s administrative operational activities general administrative services agreement cases separate operational agreements gulfterra contributed income general partner interest ownership common preference units loans gulfterra december 2003 gulfterra wholly owned subsidiary enterprise executed definitive agreements merge form second largest publicly traded energy partnership us july 29 2004 gulfterra’s unitholders approved adoption merger agreement enterprise completed september 2004 january 2005 sold remaining 99 percent interest two percent general partner enterprise approximately 135 million common units enterprise 425 million also sold membership interest two subsidiaries operate natural gas gathering systems indian springs processing facility enterprise 75 million december 2003 sales transactions specific evaluation procedures instituted ensure best interests us partnership based fair values procedures required board directors evaluate approve appropriate transaction gulfterra addition special committee comprised gulfterra general partner’s independent directors evaluated transactions gulfterra’s behalf boards engaged independent financial advisors assist evaluation opine fairness detail gains losses recognized earnings unconsolidated affiliates transactions related gulfterraenterprise significant transactions 2002 2003 2004 1 received 955 million cash series c units gulfterra value 356 million interest production field value 190 million recorded additional 74 million liability related loss 2003 future pipeline integrity costs related transmission assets agreed reimburse gulfterra 2006 2 paid 92 million cash transferred gulfterra common units book value 19 million goldman sachs december 2003 also paid 5 million miscellaneous expenses related repurchase 3 satisfied obligation gulfterra transfer communications assets book value 10 million 4 cash flows reflected 2003 cash flow statement investing activity 84 million proceeds reflected minority interest balance sheet also agreed pay 45 million enterprise 2006 5 received 870 million cash 99 percent interest general partner combined organization enterprise products gp fair value 82 million also exchanged remaining gulfterra common units 135 million enterprise common units 6 result enterprise transaction also recorded 480 million impairment goodwill loss longlived assets income statement associated field services segment addition sold south texas assets enterprise total proceeds 156 million loss 11 million included loss longlived assets prior sale interests gulfterra enterprise september 2004 subsidiary field services segment served general partner gulfterra publicly traded master limited partnership following interests gulfterra enterprise effective september 30 2004 december 31 1 181 million indefinitelived intangible assets related general partner interest december 31 2003 also 96 million recorded minority interest related effective general partnership interest acquired enterprise december 2003 reduced effective ownership interest general partner 50 percent disposed enterprise sales described three years ended december 31 2004 conducted following transactions gulfterra contingent matters could impact investments economic conditions dominican republic investments power projects dominican republic aggregate exposure approximately 103 million approximate 25 percent ownership interest 416 mw power generating complex known itabo also approximate 48 percent interest 67 mw heavy fuel oil fired power project known cepp project 2003 economic crisis developed dominican republic resulting significant devaluation dominican peso consequence economic conditions described combined high prices imported fuels due inability pass high fuel costs consumers local distribution companies purchase electrical output facilities delinquent payments cepp itabo generating facilities dominican republic since april 2003 failure pay generators resulted inability generators purchase fuel required produce electricity resulting significant energy shortfalls country addition recent local court decision resulted potential inability cepp continue receive payments power sales may affect cepp’s ability operate contesting local court decision continue monitor economic regulatory situation dominican republic new information becomes available future material developments arise possible impairments investments may occur berkshire power project 56 percent direct equity interest 261 mw power plant berkshire power located massachusetts supply natural gas berkshire fuel management agreement berkshire ability delay payment 33 percent amounts due us fuel supply agreement maximum 49 million berkshire available cash meet debt service requirements berkshire delayed total 46 million fuel payments including 8 million interest agreement december 31 2004 2002 berkshire’s lenders asserted berkshire default loan agreement issues remain unresolved based uncertainty surrounding negotiations berkshire’s inability generate adequate future cash flow recorded losses 10 million 28 million 2004 2003 associated amounts due us fuel supply agreement contingent matters could impact investments brazil see note 17 discussion nonrecourse project financing see note 15 duke litigation citrus trading corporation ctc direct subsidiary citrus corp citrus filed suit duke energy lng sales inc duke panenergy corp holding company duke seeking damages 185 million breach gas supply contract wrongful termination contract duke sent ctc notice termination gas supply contract alleging failure ctc increase amount outstanding letter credit collateral purchase obligations duke filed federal court amended counter claim joining citrus cross motion partial summary judgment requesting court find duke right terminate gas sales contract ctc due failure ctc adjust amount letter credit supporting purchase obligations ctc filed answer duke’s motion currently pending court unfavorable outcome matter could impact value investment citrus report independent registered public accounting firm board directors stockholders el paso corporation completed integrated audit el paso corporation’s 2004 consolidated financial statements internal control financial reporting december 31 2004 audits 2003 2002 consolidated financial statements accordance standards public company accounting oversight board united states opinions based audits presented consolidated financial statements financial statement schedule opinion consolidated financial statements listed accompanying index present fairly material respects financial position el paso corporation subsidiaries december 31 2004 2003 results operations cash flows three years period ended december 31 2004 conformity accounting principles generally accepted united states america addition opinion financial statement schedule listed accompanying index presents fairly material respects information set forth therein read conjunction related consolidated financial statements financial statements financial statement schedule responsibility company’s management responsibility express opinion financial statements financial statement schedule based audits conducted audits statements accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit financial statements includes examining test basis evidence supporting amounts disclosures financial statements assessing accounting principles used significant estimates made management evaluating overall financial statement presentation believe audits provide reasonable basis opinion discussed note 1 2002 consolidated financial statements restated discussed notes consolidated financial statements company adopted fasb financial interpretation 46 consolidation variable interest entities january 1 2004 fasb staff position 1062 accounting disclosure requirements related medicare prescription drug improvement modernization act 2003 july 1 2004 statement financial accounting standards sfas 150 accounting certain financial instruments characteristics liabilities equity july 1 2003 sfas 143 accounting asset retirement obligations sfas 146 accounting costs associated exit disposal activities january 1 2003 sfas 141 business combinations sfas 142 goodwill intangible assets sfas 144 accounting impairment disposal longlived assets january 1 2002 dig issue c16 scope exceptions applying normal purchases sales exception contracts combine forward contract purchased option contract july 1 2002 eitf issue 0203 accounting contracts involved energy trading risk management activities consensus 2 october 1 2002 internal control financial reporting also audited management’s assessment included management’s report internal control financial reporting appearing item 9a el paso corporation maintain effective internal control financial reporting december 31 2004 company maintain effective controls 1 access financial application programs data certain information technology environments 2 account reconciliations 3 identification capture communication financial data used accounting nonroutine transactions activities management’s assessment based criteria established internal control integrated framework issued committee sponsoring organizations treadway commission coso company’s management responsible maintaining effective internal control financial reporting assessment effectiveness internal control financial reporting responsibility express opinions management’s assessment effectiveness company’s internal control financial reporting based audit conducted audit internal control financial reporting accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether effective internal control financial reporting maintained material respects audit internal control financial reporting includes obtaining understanding internal control financial reporting evaluating management’s assessment testing evaluating design operating effectiveness internal control performing procedures consider necessary circumstances believe audit provides reasonable basis opinions company’s internal control financial reporting process designed provide reasonable assurance regarding reliability financial reporting preparation financial statements external purposes accordance generally accepted accounting principles company’s internal control financial reporting includes policies procedures pertain maintenance records reasonable detail accurately fairly reflect transactions dispositions assets company ii provide reasonable assurance transactions recorded necessary permit preparation financial statements accordance generally accepted accounting principles receipts expenditures company made accordance authorizations management directors company iii provide reasonable assurance regarding prevention timely detection unauthorized acquisition use disposition company’s assets could material effect financial statements inherent limitations internal control financial reporting may prevent detect misstatements also projections evaluation effectiveness future periods subject risk controls may become inadequate changes conditions degree compliance policies procedures may deteriorate material weakness control deficiency combination control deficiencies results remote likelihood material misstatement annual interim financial statements prevented detected following material weaknesses identified included management’s assessment december 31 2004 company maintain effective control 1 access financial applications programs data 2 account reconciliations 3 identification capture communication financial data used accounting nonroutine transactions activities specific description control deficiencies management concluded material weaknesses existed december 31 2004 discussed access financial application programs data december 31 2004 company maintain effective controls access financial application programs data operating segments internal control deficiencies identified respect inadequate design compliance security access procedures related identifying monitoring conflicting roles ie segregation duties lack independent monitoring access various systems information technology staff well certain users accounting reporting responsibilities also security administrator access financial reporting systems perform responsibilities control deficiencies result adjustment 2004 interim annual consolidated financial statements however control deficiencies could result misstatement number company’s financial statement accounts including accounts receivable property plant equipment accounts payable revenue price risk management assets liabilities potentially others would result material misstatement annual interim consolidated financial statements would prevented detected accordingly control deficiencies constitute material weakness account reconciliations december 31 2004 company maintain effective controls preparation review account reconciliations related accounts prepaid insurance accounts receivable assets taxes income taxes specifically instances identified power marketing trading businesses 1 account balances properly reconciled 2 consistent communication reconciling differences within organization allow adequate accumulation resolution reconciling items instances also noted accounts reconciled reviewed individuals adequate accounting experience training control deficiencies resulted adjustments impacting fourth quarter 2004 financial statements furthermore control deficiencies could result misstatement aforementioned accounts would result material misstatement annual interim consolidated financial statements would prevented detected accordingly control deficiencies constitute material weakness identification capture communication financial data used accounting nonroutine transactions activities december 31 2004 company maintain effective controls related identification capture communication financial data used accounting nonroutine transactions activities control deficiencies identified related identification capture validation pertinent information necessary ensure timely accurate recording nonroutine transactions activities primarily related accounting investments unconsolidated affiliates determining impairment longlived assets accounting divestiture assets control deficiencies resulted restatement 2002 financial statements reflected annual report well adjustments aforementioned accounts impacting financial statements fourth quarter 2004 furthermore control deficiencies could result material misstatement aforementioned accounts would result misstatement annual interim consolidated financial statements would prevented detected accordingly control deficiencies constitute material weakness material weaknesses considered determining nature timing extent audit tests applied audit 2004 consolidated financial statements opinion regarding effectiveness company’s internal control financial reporting affect opinion consolidated financial statements opinion management’s assessment el paso corporation maintain effective internal control financial reporting december 31 2004 fairly stated material respects based criteria established internal control integrated framework issued coso also opinion effects material weaknesses described achievement objectives control criteria company maintained effective internal control financial reporting december 31 2004 based criteria established internal control integrated framework issued coso pricewaterhousecoopers llp houston texas march 25 2004 supplemental selected quarterly financial information unaudited financial information quarter summarized 1 petroleum markets operations canadian certain international natural gas oil production operations coal mining operations classified discontinued operations see note 3 discussion supplemental natural gas oil operations unaudited production segment engaged exploration acquisition development production natural gas oil natural gas liquids primarily united states brazil united states onshore operations properties 20 states offshore operations properties federal state waters gulf mexico proved reserves united states brazil excluded information relating natural gas oil operations canada indonesia hungary following disclosures classified operations discontinued operations beginning second quarter 2004 based decision exit operations capitalized costs relating natural gas oil producing activities related accumulated depreciation depletion amortization follows december 31 millions 1 january 1 2003 adopted sfas 143 discussed note 1 included costs subject amortization december 31 2004 2003 sfas 143 asset values 154 million 124 million united states 3 million 02 million brazil costs incurred natural gas oil producing activities whether capitalized expensed follows december 31 millions 1 excludes approximately 110 million 130 million paid 2004 2003 net profits agreements described beginning page 178 2 january 2003 adopted sfas 143 discussed note 1 cumulative effect adopting sfas 143 3 million table includes capitalized internal costs incurred connection acquisition development exploration natural gas oil reserves 44 million 58 million 76 million capitalized interest 22 million 19 million 10 million years ended december 31 2004 2003 2002 january 1 2005 reserve report amounts estimated spent 2005 2006 2007 develop worldwide booked proved undeveloped reserves 182 million 251 million 218 million presented analysis capitalized costs natural gas oil properties year expenditures amortized december 31 2004 pending determination proved reserves millions 1 includes operations united states brazil 2 includes capitalized interest 20 million 6 million less 1 million years ended december 31 2004 2003 2002 projects presently excluded amortization various stages evaluation majority costs expected included amortization calculation years 2005 2008 total amortization expense per mcfe united states 184 140 105 2004 2003 2002 202 brazil 2004 production brazil 2003 2002 included worldwide depreciation depletion amortization expense accretion expense 008mcfe 006mcfe 2004 2003 attributable sfas 143 adopted january 2003 net quantities proved developed undeveloped reserves natural gas ngl oil condensate changes reserves december 31 2004 presented information tables based internal reserve report ryder scott company independent petroleum engineering firm prepared estimate natural gas oil reserves 88 percent properties total estimate proved reserves prepared ryder scott within four percent internally prepared estimates presented tables information consistent estimates reserves filed federal agencies except differences less five percent resulting actual production acquisitions property sales necessary reserve revisions additions reflect actual experience ryder scott retained reports audit committee board directors properties reviewed ryder scott represented 88 percent proved properties based value tables exclude power segment’s equity interest sengkang indonesia aguaytia peru combined proved reserves balances interests 132336 mmcf natural gas 2195 mbbls oil condensate ngl total natural gas equivalents 145507 mmcfe net ownership interests 1 net proved reserves exclude royalties interests owned others reflects contractual arrangements royalty obligations effect time estimate 2 sales reserves place include 20729 mmcf 28779 mmcf natural gas conveyed third parties net profits agreements 2004 2003 described beginning page 178 1 net proved reserves exclude royalties interests owned others reflects contractual agreements royalty obligations effect time estimate 2 sales reserves place include 1276 mbbl 1098 mbbl liquids conveyed third parties net profits agreements 2004 2003 described beginning page 178 1 net proved reserves exclude royalties interests owned others reflects contractual agreements royalty obligations effect time estimate 2 sales reserves place include 47 mbbl 194 mbbl ngl conveyed third parties net profits agreements 2004 2003 described 2004 approximately 174 bcfe negative reserve revisions united states largely performancedriven reserve revisions primarily concentrated onshore coal bed methane operations offshore gulf mexico onshore region recorded 71 bcfe negative reserve revisions negative reserve revisions related performance results producing wells recent drilling program coupled related impact booked proven undeveloped locations certain areas arkoma black warrior basins wells drilled late 2003 positive initial results however subsequent drilling additional production history resulted 70 bcfe negative revisions holly field north louisiana 14 bcfe reserves revised downward result production performance negative revisions offset betterthananticipated performance rockies arklatex fields resulting positive reserve revisions 13 bcfe texas gulf coast texas gulf coast region recorded 26 bcfe negative reserve revisions negative revisions comprised approximately 7 bcfe performance revisions proved producing wells approximately 6 bcfe due mechanical failures five wells approximately 13 bcfe due lowerthanexpected results 2004 development drilling program offshore region recorded 77 bcfe negative reserve revisions gulf mexico approximately 10 bcfe revisions result mechanical failures approximately 25 bcfe due producing well performance remaining 42 bcfe resulted drilling development wells adjustments proved undeveloped reserves result production performance offsetting locations numerous uncertainties inherent estimating quantities proved reserves projecting future rates production projecting timing development expenditures including many factors beyond control reserve data represents estimates reservoir engineering subjective process estimating underground accumulations natural gas oil cannot measured exact manner accuracy reserve estimate function quality available data engineering geological interpretations judgment estimates proved reserves determined according rules prescribed sec rules indicate standard “reasonable certainty” applied proved reserve estimates concept reasonable certainty implies technical data becomes available positive upward revision likely negative downward revision estimates subject revision based upon number factors including reservoir performance prices economic conditions government restrictions addition results drilling testing production subsequent date estimate may justify revision estimate reserve estimates often different quantities natural gas oil ultimately recovered meaningfulness reserve estimates highly dependent accuracy assumptions based general volume production natural gas oil properties declines reserves depleted except extent conduct successful exploration development activities acquire additional properties containing proved reserves proved reserves decline reserves produced major discoveries events favorable adverse may considered caused significant change estimated proved reserves since december 31 2004 however january 2005 announced two acquisitions east texas south texas 211 million march 2005 acquired interest one parties net profits interest drilling program 62 million acquisitions added properties approximately 139 bcfe existing proved reserves 52 mmcfed current production 2003 entered agreements sell interests maximum 124 wells lehman brothers subsidiary nabors industries wells developed lehman nabors pay 70 percent drilling development costs exchange 70 percent net profits wells sold well commenced lehman nabors receive overriding royalty interest form net profits interest well entitled receive 70 percent aggregate net profits wells recovered 1175 percent aggregate investment upon recovery net profits interest convert 2 percent overriding royalty interest wells remainder well’s productive life guarantee return recovery lehman nabor’s costs parties agreement right cease participation agreement time lehman nabors continue receive net profits interest wells previously started relinquish right participate future wells 2004 sold interests 54 wells total proved reserves 20729 mmcf natural gas 1323 mbbl oil natural gas liquids paid 110 million drilling development costs paid 152 million revenues net 11 million expenses associated wells year ended december 31 2004 march 2005 acquired interests held lehman subsidiary 62 million results operations producing activities fiscal year follows december 31 millions 1 production cost includes lease operating costs production related taxes including ad valorem severance taxes 2 january 2003 adopted sfas 143 discussed note 1 depreciation depletion amortization includes accretion expense sfas 143 abandonment liabilities 23 million primarily united states 2004 2003 standardized measure discounted future net cash flows relating proved natural gas oil reserves december 31 follows millions 1 united states excludes 1 million 104 million 85 million future net cash outflows attributable hedging activities years 2004 2003 2002 brazil excludes 5 million future net cash outflows attributable hedging activities 2004 calculations preceding table estimated future cash inflows estimated future production proved reserves computed using yearend prices 622 per mmbtu natural gas 4345 per barrel oil december 31 2004 adjustments transportation charges resulted net price 599 per mcf gas 4211 per barrel oil 3213 per barrel ngl december 31 2004 may receive amounts different standardized measure discounted cash flow number reasons including price changes effects hedging activities rely upon standardized measure making investment operating decisions based various factors including probable proved reserves different price cost assumptions actual economic conditions capital availability corporate investment criteria following principal sources change worldwide standardized measure discounted future net cash flows millions 1 disclosure reflects changes standardized measure calculation excluding effects hedging activities 2 includes operations united states brazil schedule ii el paso corporation valuation qualifying accounts years ended december 31 2004 2003 2002 millions 1 relates primarily accounts written 2 relates primarily receivables trading counterparties reclassified due bankruptcy declining credit accounted within price risk management activities 3 relates primarily valuation allowances deferred tax assets related western energy settlement foreign ceiling test charges foreign asset impairments net operating loss carryovers 4 relates western energy settlement 104 million 2003 899 million 2002 june 2004 released approximately 602 million settling parties including approximately 568 million escrow correspondingly reduced liability amount 5 relates primarily payments various litigation reserves including western energy settlement environmental remediation reserves revenue crediting rate settlement reserves 6 relates primarily liabilities previously classified petroleum discontinued operations reclassified continuing operations due retention obligations item 9nanitem 8 financial statements supplementary data index items contained part ii item 8 financial statements supplementary data management’s annual report internal control financial reporting management responsible establishing maintaining adequate internal control financial reporting defined sec rules adopted securities exchange act 1934 amended internal control financial reporting designed provide reasonable assurance regarding reliability financial reporting preparation financial statements external purposes accordance generally accepted accounting principles consists policies procedures • pertain maintenance records reasonable detail accurately fairly reflect transactions dispositions assets • provide reasonable assurance transactions recorded necessary permit preparation financial statements accordance generally accepted accounting principles receipts expenditures made accordance authorizations management directors • provide reasonable assurance regarding prevention timely detection unauthorized acquisition use disposition assets could material effect financial statements supervision participation management including chief executive officer ceo chief financial officer cfo made assessment effectiveness internal control financial reporting december 31 2006 making assessment used criteria established internal control integrated framework issued committee sponsoring organizations treadway commission coso based evaluation concluded internal control financial reporting effective december 31 2006 assessment effectiveness internal control financial reporting december 31 2006 audited ernst young llp independent registered public accounting firm stated report included herein report independent registered public accounting firm board directors stockholders el paso corporation audited accompanying consolidated balance sheet el paso corporation december 31 2006 related consolidated statements income comprehensive income stockholders’ equity cash flows year ended audit also included financial statement schedule listed index item 15a year ended december 31 2006 financial statements schedule responsibility company’s management responsibility express opinion financial statements schedule based audit financial statements citrus corp subsidiaries four star oil gas company corporations company 50 431 interest respectively audited auditors whose reports furnished us opinion consolidated financial statements insofar relates amounts included citrus corp subsidiaries four star oil gas company based solely reports auditors consolidated financial statements company’s combined investments companies represent approximately 3 total assets december 31 2006 earnings investments represent approximately 24 income taxes continuing operations year ended conducted audit accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements audit also includes assessing accounting principles used significant estimates made management well evaluating overall financial statement presentation believe audit reports auditors provide reasonable basis opinion based audit reports auditors financial statements referred present fairly material respects consolidated financial position el paso corporation december 31 2006 consolidated results operations cash flows year ended conformity us generally accepted accounting principles also opinion related financial statement schedule considered relation basic financial statements taken whole present fairly material respects information set forth therein discussed note 1 consolidated financial statements effective january 1 2006 company adopted provisions statement financial accounting standards 123revised 2004 sharebased payment federal energy regulatory commission’s accounting release related pipeline assessment costs effective december 31 2006 company adopted recognition provisions statement financial accounting standards 158 employers’ accounting defined benefit pension postretirement plans amendment fasb statements 87 88 106 132r also audited accordance standards public company accounting oversight board united states effectiveness el paso corporation’s internal control financial reporting december 31 2006 based criteria established internal controlintegrated framework issued committee sponsoring organizations treadway commission report dated february 26 2007 expressed unqualified opinion thereon ernst young llp houston texas february 26 2007 report independent registered public accounting firm internal control financial reporting board directors stockholders el paso corporation audited management’s assessment included accompanying management’s annual report internal control financial reporting el paso corporation maintained effective internal control financial reporting december 31 2006 based criteria established internal control integrated framework issued committee sponsoring organizations treadway commission coso criteria el paso corporation’s management responsible maintaining effective internal control financial reporting assessment effectiveness internal control financial reporting responsibility express opinion management’s assessment opinion effectiveness company’s internal control financial reporting based audit conducted audit accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether effective internal control financial reporting maintained material respects audit included obtaining understanding internal control financial reporting evaluating management’s assessment testing evaluating design operating effectiveness internal control performing procedures considered necessary circumstances believe audit provides reasonable basis opinion company’s internal control financial reporting process designed provide reasonable assurance regarding reliability financial reporting preparation financial statements external purposes accordance generally accepted accounting principles company’s internal control financial reporting includes policies procedures 1 pertain maintenance records reasonable detail accurately fairly reflect transactions dispositions assets company 2 provide reasonable assurance transactions recorded necessary permit preparation financial statements accordance generally accepted accounting principles receipts expenditures company made accordance authorizations management directors company 3 provide reasonable assurance regarding prevention timely detection unauthorized acquisition use disposition company’s assets could material effect financial statements inherent limitations internal control financial reporting may prevent detect misstatements also projections evaluation effectiveness future periods subject risk controls may become inadequate changes conditions degree compliance policies procedures may deteriorate opinion management’s assessment el paso corporation maintained effective internal control financial reporting december 31 2006 fairly stated material respects based coso criteria also opinion el paso corporation maintained material respects effective internal control financial reporting december 31 2006 based coso criteria also audited accordance standards public company accounting oversight board united states 2006 consolidated financial statements el paso corporation report dated february 26 2007 expressed unqualified opinion thereon ernst young llp houston texas february 26 2007 report independent registered public accounting firm board directors stockholders el paso corporation opinion consolidated balance sheet december 31 2005 related consolidated statements income comprehensive income stockholders’ equity cash flows two years period ended december 31 2005 present fairly material respects financial position el paso corporation subsidiaries “company” december 31 2005 results operations cash flows two years period ended december 31 2005 conformity accounting principles generally accepted united states america addition opinion financial statement schedule two years period ended december 31 2005 presents fairly material respects information set forth therein read conjunction related consolidated financial statements financial statements financial statement schedule responsibility company’s management responsibility express opinion financial statements financial statement schedule based audits conducted audits statements accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit financial statements includes examining test basis evidence supporting amounts disclosures financial statements assessing accounting principles used significant estimates made management evaluating overall financial statement presentation believe audits provide reasonable basis opinion discussed notes consolidated financial statements company adopted fasb interpretation 47 accounting conditional asset retirement obligations december 31 2005 pricewaterhousecoopers llp houston texas march 2 2006 except eleventh paragraph note 2 date may 10 2006 tenth paragraph note 2 date february 26 2007 report independent registered public accounting firm stockholders four star oil gas company opinion accompanying consolidated balance sheets related consolidated statements income stockholders’ equity cash flows present fairly material respects financial position four star oil gas company “company” subsidiary december 31 2006 2005 results operations cash flows three years period ended december 31 2006 conformity accounting principles generally accepted united states america financial statements responsibility company’s management responsibility express opinion financial statements based audits conducted audits statements accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements assessing accounting principles used significant estimates made management evaluating overall financial statement presentation believe audits provide reasonable basis opinion described note 3 financial statements company significant transactions affiliated companies relationships possible terms transactions would result transactions among wholly unrelated parties pricewaterhousecoopers llp february 23 2007 houston texas report independent registered public accounting firm board directors stockholders citrus corp subsidiaries opinion accompanying consolidated balance sheets related consolidated statements income stockholders’ equity comprehensive income cash flows present fairly material respects financial position citrus corp subsidiaries “company” december 31 2006 2005 results operations cash flows three years period ended december 31 2006 conformity accounting principles generally accepted united states america consolidated financial statements responsibility company’s management responsibility express opinion financial statements based audits conducted audits statements accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements assessing accounting principles used significant estimates made management evaluating overall financial statement presentation believe audits provide reasonable basis opinion discussed notes 2 6 consolidated financial statements company adopted recognition disclosure provisions fasb statement 158 “employers’ accounting defined benefit pension postretirement plans amendment fasb statements 87 88 106 132r” december 31 2006 pricewaterhousecoopers llp houston texas february 26 2007 el paso corporation consolidated statements income millions except per common share amounts see accompanying notes el paso corporation consolidated balance sheets millions except share amounts see accompanying notes el paso corporation consolidated balance sheets millions except share amounts see accompanying notes el paso corporation consolidated statements cash flows millions see accompanying notes el paso corporation consolidated statements stockholders’ equity millions except per share amounts see accompanying notes el paso corporation consolidated statements comprehensive income millions see accompanying notes el paso corporation notes consolidated financial statements 1 basis presentation significant accounting policies basis presentation principles consolidation consolidated financial statements prepared accordance us generally accepted accounting principles gaap include accounts majority owned controlled subsidiaries elimination significant intercompany accounts transactions financial statements adjusted periods reflect reclassification anr michigan storage assets 50 percent interest great lakes gas transmission well macae power facility discontinued operations additionally financial statements prior periods include reclassifications made conform current year presentation reclassifications impact reported net income loss stockholders’ equity consolidate entities either ability control operating financial decisions policies entity ii allocated majority entity’s losses andor returns variable interests see note 18 entity determination ability control exert significant influence entity whether allocated majority entity’s losses andor returns involves use judgment apply equity method accounting exert significant influence control policies decisions entity allocated majority entity’s losses andor returns use cost method accounting unable exert significant influence entity use estimates preparation financial statements requires use estimates assumptions affect amounts report assets liabilities revenues expenses disclosures financial statements actual results often differ estimates regulated operations interstate natural gas pipelines storage operations subject jurisdiction ferc natural gas act 1938 natural gas policy act 1978 energy policy act 2005 pipelines follow regulatory accounting principles prescribed statement financial accounting standards sfas 71 accounting effects certain types regulation sfas 71 record regulatory assets liabilities would recorded gaap nonregulated entities regulatory assets liabilities represent probable future revenues expenses associated certain charges credits recovered refunded customers rate making process items apply regulatory accounting requirements include certain postretirement employee benefit plan costs equity return component regulated capital projects certain costs included expected included future rates cash equivalents consider shortterm investments original maturity less three months cash equivalents maintain cash deposit banks insurance companies pledged particular use restricted support potential liability classify balances restricted cash current noncurrent assets balance sheet based expect restrictions cash removed december 31 2006 8 million restricted cash current assets 123 million noncurrent assets december 31 2005 92 million restricted cash current assets 168 million noncurrent assets allowance doubtful accounts establish provisions losses accounts notes receivable natural gas imbalances due shippers operators determine collect part outstanding balance regularly review collectibility establish adjust allowance necessary using specific identification method property plant equipment pipelines excluding natural gas oil properties property plant equipment recorded original cost construction upon acquisition fair value assets acquired assets construct capitalize direct costs labor materials indirect costs overhead interest equity return component regulated businesses capitalize major units property replacements improvements expense minor items prior january 1 2006 capitalized certain costs interstate pipelines incurred related pipeline integrity programs part property plant equipment beginning january 1 2006 began expensing costs based ferc guidance year ended december 31 2006 expensed approximately 19 million result adoption accounting release approximately 002 per basic fully diluted share included pipeline property balances additional acquisition costs represent excess purchase costs associated purchase business combinations allocated regulated interstate systems’ property plant equipment costs amortized straightline basis recover excess costs rates retire property plant equipment regulated operations charge accumulated depreciation amortization original cost assets addition cost remove sell dispose assets less salvage value recognize gain loss unless sell entire operating unit include gains losses dispositions operating units operating income natural gas oil properties use full cost method account natural gas oil properties full cost method substantially costs incurred connection acquisition development exploration natural gas oil reserves capitalized countrybycountry basis capitalized amounts include costs unproved properties internal costs directly related acquisition development exploration activities asset retirement costs capitalized interest full cost method dry hole costs geological geophysical costs capitalized full cost pool subject amortization periodically assessed impairment ceiling test calculation discussed capitalized costs associated proved reserves amortized life reserves using unit production method conversely capitalized costs associated unproved properties excluded amortizable base properties evaluated occurs quarterly transfer unproved property costs amortizable base properties determined proved reserves addition areas natural gas oil reserve base exists transfer unproved property costs amortizable base unproved properties evaluated impaired exploratory dry holes determined unsuccessful additionally amortizable base includes future development costs dismantlement restoration abandonment costs net estimated salvage values geological geophysical costs incurred cannot associated specific unevaluated properties prospects direct interest capitalized costs net related income tax effects limited ceiling based present value future net revenues discounted 10 percent plus lower cost fair market value unproved properties net related income tax effects utilize endofperiod spot prices calculating future net revenues unless prices result ceiling test charge case evaluate price recoveries subsequent end period total capitalized costs exceed ceiling required writedown capitalized costs ceiling perform ceiling test calculation quarter required writedown included income statement ceiling test charge ceiling test calculations include effects derivative instruments designated qualify cash flow hedges anticipated future natural gas oil production ceiling test calculations exclude estimated future cash outflows associated asset retirement liabilities related proved developed reserves sell convey interests natural gas oil properties reduce natural gas oil reserves amount attributable sold conveyed interest recognize gain loss sales natural gas oil properties unless sales would significantly alter relationship capitalized costs proved reserves treat sales proceeds nonsignificant sales adjustment cost properties asset investment divestitures impairments evaluate assets investments impairment events circumstances indicate carrying values may recovered events include market declines believed temporary changes manner intend use longlived asset decisions sell asset investment adverse changes legal business environment adverse actions regulators event occurs evaluate recoverability carrying value based either longlived assets’ ability generate future cash flows undiscounted basis ii fair value investments unconsolidated affiliates impairment indicated decide sell longlived asset group assets adjust carrying values assets downward necessary estimated fair value fair value estimates generally based market data obtained sales process analysis expected discounted cash flows magnitude impairment impacted number factors including nature assets sold established time frame completing sales among factors reclassify asset assets sold either heldforsale discontinued operations depending among criteria whether significant longterm continuing involvement assets sold cease depreciating assets period reclassified either held sale discontinued operations pension postretirement benefits maintain several pension postretirement benefit plans require us make contributions fund benefits paid plans contributions invested benefits paid plan participants record benefit expense related plans income statement benefit expense function many factors including benefits earned year plan participants function employee’s salary level benefits provided plan actuarial assumptions passage time expected returns plan assets amortization certain deferred gains losses discussion policies respect pension postretirement plans see note 14 effective december 31 2006 adopted recognition provisions sfas 158 employers’ accounting defined benefit pension postretirement plans amendment fasb statements 87 88 106 132r sfas 158 record asset liability pension postretirement benefit plans based overfunded underfunded status deferred amounts related unrealized gains losses changes actuarial assumptions recorded accumulated comprehensive income loss component stockholders’ equity gains losses recognized income statement prior december 31 2006 deferred amounts included pension postretirement assets liabilities balance sheets reclassification stockholders’ equity impact pension postretirement benefit expense included income statements discussion impact adoption sfas 158 see note 14 revenue recognition business segments provide number services sell variety products record revenues products services include estimates amounts earned unbilled estimate unbilled revenues related services provided products delivered based contract data regulatory information commodity prices preliminary throughput allocation measurements among items revenue recognition policies significant operating segments follows pipelines revenues pipelines segment derives revenues primarily transportation storage services transportation storage services recognize reservation revenues firm contracted capacity ratably contract period regardless amount natural gas transported stored interruptible volumetric based services record revenues physical deliveries natural gas made agreed upon delivery point gas injected withdrawn storage facility gas needed operations based volumes allowed retain relative amounts gas use operating purposes recognize revenue gas used operations retain volumes tariffs revenues services generally based thermal quantity gas delivered subscribed price specified contract subject ferc regulations result revenues collect rate proceedings may subject refund establish reserves potential refunds exploration production revenues exploration production segment derives revenues primarily physical sale natural gas oil condensate ngl revenues sales products recorded upon delivery passage title using sales method net royalty interests profit interests produced product actual natural gas sales volumes exceed entitled share sales volumes overproduced imbalance occurs extent overproduced imbalance exceeds share remaining estimated proved natural gas reserves given property record liability costs associated transportation delivery production included cost sales marketing revenues marketing segment derives revenues physical natural gas power transactions management derivative contracts derivative transactions recorded fair value changes fair value reflected net operating revenues discussion income recognition policies derivatives see price risk management activities impact nonderivative transactions including transportation contacts recognized net operating revenues based contractual market price related volumes time commodity delivered contracts terminated environmental costs contingencies environmental costs record liabilities undiscounted amounts balance sheet current longterm liabilities environmental assessments indicate remediation efforts probable costs reasonably estimated estimates liabilities based currently available facts existing technology presently enacted laws regulations taking consideration likely effects societal economic factors include estimates associated legal costs amounts also consider prior experience remediating contaminated sites companies’ cleanup experience data released epa organizations estimates subject revision future periods based actual costs new circumstances capitalize costs benefit future periods recognize current period charge operation maintenance expense cleanup efforts benefit future periods evaluate amounts paid directly reimbursed government sponsored programs potential recoveries reimbursements remediation costs third parties including insurance coverage separately liability recovery evaluated based creditworthiness solvency third party among factors recovery assured record report asset separately associated liability balance sheet contingencies recognize liabilities contingencies exposure fully analyzed indicates probable liability incurred amount loss reasonably estimated likely outcome contingency reasonably estimated accrue liability amount likely outcome cannot estimated range potential losses established one amount range likely low end range accrued price risk management activities price risk management activities consist following activities • derivatives entered hedge otherwise reduce commodity exposure natural gas oil production interest rate foreign currency exposure longterm debt • derivatives intended hedge exposures including related historical trading activities entered objective generating profits exposure shifts changes market prices derivatives reflected balance sheet fair value assets liabilities price risk management activities classify derivatives either current noncurrent assets liabilities based anticipated settlement date net derivative assets liabilities counterparties legal right offset see note 8 discussion price risk management activities derivatives designated accounting hedges impact revenues expenses based nature timing transactions hedge derivatives designated hedges markedtomarket period changes fair value reflected revenues cash flow statement cash inflows outflows associated settlement derivative instruments recognized operating cash flows derivatives intended hedge principal amounts foreign currency denominated debt balance sheet receivables payables resulting settlement derivative instruments reported trade receivables payables income taxes record current income taxes based current taxable income provide deferred income taxes reflect estimated future tax payments receipts deferred taxes represent tax impacts differences financial statement tax bases assets liabilities carryovers year end account tax credits flowthrough method reduces provision income taxes year tax credits first become available reduce deferred tax assets valuation allowance based estimates likely portion assets realized future period estimates utilized recognition deferred tax assets subject revision either future periods based new facts circumstances foreign currency translation foreign operations whose functional currency local currency assets liabilities translated yearend exchange rates revenues expenses translated average exchange rates prevailing year cumulative effects translating local currency us dollar included separate component accumulated comprehensive income loss stockholders’ equity balance sheet accounting asset retirement obligations account asset retirement obligations accordance sfas 143 accounting asset retirement obligations financial accounting standards board fasb interpretation fin 47 accounting conditional asset retirement obligations record liability legal obligations associated replacement removal retirement longlived assets asset retirement liabilities recorded estimated fair value corresponding increase property plant equipment increase property plant equipment depreciated useful life longlived asset liability relates ongoing expense also recognized changes value liability result passage time record depreciation depletion amortization expense income statement regulated pipelines ability recover certain costs customers recorded asset rather expense associated depreciation property plant equipment accretion liabilities described accounting stockbased compensation january 1 2006 adopted sfas 123r sharebased payment prospectively awards stockbased compensation granted date unvested portion outstanding awards date standard related interpretations require companies measure employee stockbased compensation awards fair value date granted employees recognize compensation cost financial statements requisite service period prior january 1 2006 accounted plans using intrinsic value method provisions accounting principles board apb opinion 25 accounting stock issued employees related interpretations record compensation expense stock options granted market value stock date grant additional information stockbased compensation awards see note 16 record stockbased compensation expense excluding amounts capitalized operation maintenance expense separately vesting portion award net estimates forfeitures actual forfeitures differ estimates additional adjustments compensation expense required future periods adoption sfas 123r result significant cumulative effect financial statements however 2006 recognized incremental 11 million additional pretax compensation expense capitalized approximately 2 million expense part fixed assets recorded 4 million income tax benefits earnings per share decreased 001 per basic diluted share resulting implementation standard additionally sfas 123r beginning january 1 2006 excess tax benefits exercise stockbased compensation awards recognized cash flows financing activities prior date amounts recorded cash flows operating activities excess tax benefits recorded 2006 2005 2004 material following table shows impact net loss available common stockholders loss per share applied provisions sfas 123 historical periods millions except per share amounts evaluation prior period misstatements current financial statements december 2006 adopted provisions securities exchange commission’s staff accounting bulletin sab 108 considering effects prior year misstatements quantifying misstatements current year financial statements sab 108 provides guidance evaluate impact financial statement misstatements prior periods identified current year adoption provisions impact financial statements new accounting pronouncements issued yet adopted december 31 2006 following accounting standards interpretations yet adopted us accounting uncertainty income taxes july 2006 fasb issued fin 48 accounting uncertainty income taxes fin 48 clarifies sfas 109 accounting income taxes requires us evaluate tax positions jurisdictions years statute limitations expired fin 48 requires companies meet “morelikelythannot” threshold ie greater 50 percent likelihood tax position sustained examination prior recording benefit tax positions additionally tax positions meeting “morelikelythannot” threshold amount benefit limited largest benefit greater 50 percent probability realized upon ultimate settlement cumulative effect applying interpretation recorded adjustment beginning balance retained earnings components stockholders’ equity appropriate period adoption interpretation effective fiscal years beginning december 15 2006 anticipate material impact financial statements fair value measurements september 2006 fasb issued sfas 157 fair value measurements provides guidance measuring fair value assets liabilities financial statements required adopt provisions standard later 2008 currently evaluating impact financial statements measurement date pension postretirement benefits december 2006 adopted recognition provisions sfas 158 beginning 2008 standard also require us change measurement date pension postretirement benefit plans september 30 date currently use december 31 currently evaluating impact measurement date provisions standard financial statements february 2007 fasb issued statement financial accounting standards 159 fair value option financial assets financial liabilities including amendment fasb statement 115 accounting certain investments debt equity securities permits entities choose measure many financial instruments certain items fair value required adopt provisions standard later 2008 currently evaluating impact financial statements 2 acquisitions divestitures acquisitions south texas properties january 2007 acquired operated natural gas oil producing properties undeveloped acreage south texas approximately 249 million using funds borrowed epep 500 million credit facility medicine bow august 2005 completed acquisition medicine bow privately held energy company total cash consideration approximately 09 billion medicine bow owns 431 percent interest four star unconsolidated affiliate proportionate share operating results associated four star reflected earnings unconsolidated affiliates financial statements see note 18 reflected medicine bow’s results operations income statement beginning september 1 2005 following summary unaudited pro forma consolidated results operations years ended december 31 2005 2004 reflect combination historical income statements medicine bow’s adjusted certain effects acquisition related funding pro forma results prepared acquisition occurred beginning periods presented necessarily indicative operating results would occurred acquisition consummated date necessarily indicative future operating results 1 excludes 13 million pretax charge change control payments triggered medicine bow result acquisition divestitures 2006 2005 2004 sold number assets investments business segments corporate operations table discussions summarize assets sold proceeds sales 1 proceeds exclude returns invested capital cash transferred assets sold include costs incurred preparing assets disposal items increased sales proceeds 15 million year ended december 31 2006 decreased sales proceeds 35 million 85 million years ended december 31 2005 2004 power assets sold consisted primarily interests mcv power plants brazil asia central america 2006 interests power contract restructuring entities power plants india korea 2005 interests utility contract funding 31 domestic power plants 2004 field services assets sold consisted primarily investment enterprise javelina natural gas processing pipeline assets 2005 investment gulfterra 2004 exploration production pipelines corporate assets sold consisted primarily natural gas oil properties south texas various corporate assets 2006 pipeline facilities gathering systems located southeastern western us lakeside technology center 2005 brazilian exploration production acreage various corporate assets 2004 february 2007 sold anr michigan storage assets 50 percent interest great lakes gas transmission pipeline lateral located northeastern united states cash proceeds sales approximately 37 billion expect record gain sales 2007 discontinued operations assets held sale sfas 144 accounting impairment disposal longlived assets classify assets disposed held sale appropriate discontinued operations received appropriate approvals disposed management board directors meet criteria cash flows discontinued businesses reflected discontinued operating investing financing activities statement cash flows extent operations maintain separate cash balances reflect net cash flows generated businesses contribution continuing operations cash continuing financing activities following description discontinued operations summarized results operations periods ended december 31 2006 2005 2004 also assets held sale approximately 28 million december 31 2006 sold february 2007 anr related operations february 2007 sold anr michigan storage assets 50 percent interest great lakes gas transmission transcanada corporation tc pipeline lp net cash proceeds approximately 37 billion described international power operations 2006 board directors approved sale interest macae wholly owned power plant facility brazil 2005 board directors approved sale asian central american power asset portfolio 2005 recognized approximately 499 million impairments net minority interest based upon indications value would receive upon sale assets 2006 completed sale discontinued international power operations net proceeds approximately 368 million south louisiana gathering processing operations 2005 board directors approved sale south louisiana gathering processing assets part field services segment completed sale assets 2005 net proceeds approximately 486 million recorded pretax gain approximately 394 million 2004 canadian certain international natural gas oil production operations approved sale completed sale substantially properties 2004 2005 approximately 395 million 2003 sales petroleum markets businesses operations approved completed sale operations end 2005 income taxes discontinued operations years ended december 31 2006 2005 2004 incurred income tax expense associated discontinued operations 274 million 179 million 142 million resulting effective tax rate approximately 126 216 63 years effective tax rates significantly higher statutory rate 35 primarily due following items • 2006 recorded approximately 188 million deferred taxes upon agreeing sell stock anr michigan storage assets 50 percent interest great lakes gas transmission prior decision sell required record deferred taxes individual assetsliabilities portion investment stock one companies • 2005 impairments operating losses certain foreign investments tax benefit available dividends foreign subsidiaries taxable us state income taxes • 2004 impairments operating losses certain foreign investments tax benefit available state income taxes summarized operating results financial position data discontinued operations follows 3 gain loss longlived assets gain loss longlived assets continuing operations consists realized gains losses sales longlived assets impairments longlived assets including goodwill intangibles asset impairments primarily result asset sales unfavorable contract negotiations related assets discontinuance pipeline development projects based changing economic conditions additional information asset impairments discontinued operations investments unconsolidated affiliates see notes 2 18 three years ended december 31 gain loss longlived assets follows 4 income expenses following components income expenses continuing operations three years ended december 31 5 income taxes pretax income loss income tax expense benefit tables show pretax income loss continuing operations components income tax expense benefit years ended december 31 effective tax rate reconciliation income taxes included income loss continuing operations differs amount computed applying statutory federal income tax rate 35 percent following reasons three years ended december 31 2006 2005 overall effective tax rate continuing operations significantly different statutory rate due primarily conclusion irs audits 2006 audits coastal corporation’s 19982000 tax years el paso’s 2001 2002 tax years concluded resulted reduction tax contingencies reinstatement certain tax credits 2005 finalized coastal corporation’s irs tax audits years prior 1998 2004 overall effective tax rate continuing operations significantly different statutory rate due primarily sales gulfterra investment impairments certain foreign investments sale gulfterra resulted significant net taxable gain compared lower book gain thus significant tax expense due nondeductibility goodwill written result transaction impact nondeductible goodwill increased tax expense 2004 approximately 139 million additionally received us federal income tax benefit impairment certain foreign investments deferred tax assets liabilities following components net deferred tax liability related continuing operations december 31 prior 2004 recorded us deferred tax assets liabilities book versus tax basis differences substantial portion international investments based intent indefinitely reinvest earnings investments outside us based sales negotiations certain power assets asia central america india however received expect receive sales proceeds within us result years ended december 31 2006 2005 2004 recorded us deferred tax assets liabilities book versus tax basis differences investments also recorded us deferred tax benefits sale power asset india december 31 2006 2005 us deferred tax assets 45 million 103 million us deferred tax liabilities 2 million 23 million related investments cumulative undistributed earnings remainder foreign subsidiaries foreign corporate joint ventures excluding power assets discussed intended indefinitely reinvested foreign operations therefore provision made us taxes foreign withholding taxes may applicable upon actual deemed repatriation estimate taxes earnings repatriated practical december 31 2006 portion cumulative undistributed earnings investments recorded us income taxes approximately 112 million reasons recorded provision us income taxes foreign currency translation adjustments recorded accumulated comprehensive income tax credit nol carryovers december 31 2006 us federal alternative minimum tax credits 326 million carryover indefinitely 1 million general business credit carryovers carryover periods end various years 2010 2022 capital loss carryovers 11 million carryover period ends 2008 table presents details federal state net operating loss carryover periods december 31 2006 also 182 million foreign net operating loss carryovers 56 million foreign capital loss carryovers carryover indefinitely usage us federal carryovers subject limitations provided sections 382 383 internal revenue code well separate return limitation year rules irs regulations valuation allowances deferred tax assets recorded net operating losses temporary differences book tax basis assets liabilities expected produce tax deductions future periods realization assets depends recognition sufficient future taxable income specific tax jurisdictions periods temporary differences net operating losses deductible assessing need valuation allowance deferred tax assets consider whether likely portion realized part assessment consider future reversals existing taxable temporary differences primarily related depreciation 2006 also considered gain expected sale anr related assets assessment believe likely realize benefit deferred tax assets net existing valuation allowances tax matters irs currently auditing el paso’s 2003 2004 tax years recorded liabilities tax contingencies associated audits well proceedings examinations taxing authorities believe adequate matters finalized may required adjust liability could significantly increase decrease income tax expense effective income tax rates future periods 6 earnings per share calculated basic diluted earnings per common share follows three years ended december 31 exclude potentially dilutive securities determination diluted earnings per share well related income statement impacts impact income continuing operations per common share antidilutive potentially dilutive securities consist employee stock options restricted stock convertible preferred stock issued 2005 trust preferred securities zero coupon convertible debentures paid april 2006 year ended december 31 2006 certain employee stock options zero coupon convertible debentures trust preferred securities antidilutive year ended december 31 2005 2004 incurred losses continuing operations accordingly excluded potentially dilutive securities determination diluted earnings per share impact loss per common share antidilutive discussion capital stock activity stockbased compensation arrangements instruments noted see notes 15 16 7 fair value financial instruments december 31 2006 2005 carrying amounts cash equivalents shortterm borrowings trade receivables payables represented fair value shortterm nature instruments fair value longterm debt variable interest rates approximates carrying value marketbased nature interest rate estimated fair value debt fixed interest rates based quoted market prices similar issues see note 8 discussion methodology determining fair value derivative instruments used price risk management activities investments primarily relate available sale securities cost basis investments 8 price risk management activities following table summarizes carrying value derivatives used price risk management activities december 31 2006 2005 table derivatives designated hedges consist instruments used hedge natural gas oil production commoditybased derivative contracts relate derivative contracts designated hedges options swaps natural gas power purchase supply contracts derivatives historical energy trading activities finally interest rate foreign currency derivatives consist swaps primarily designated hedges interest rate foreign currency risk longterm debt 1 decrease due primarily sale assignment number derivative contracts significant changes natural gas oil prices 2006 2 included current noncurrent assets liabilities balance sheet derivative contracts recorded financial statements fair value best indication fair value quoted market prices however quoted market prices available estimate fair value derivatives use commodity pricing data either obtained derived independent pricing source assumptions certain power natural gas markets develop price curves used estimate value settlements future periods based contractual settlement quantities dates finally discount estimated settlement values using libor curve record valuation adjustments reflect uncertainties associated estimates use determining fair value common valuation adjustments include market liquidity creditworthiness contractual counterparties 2006 2005 changed independent pricing source provided pricing data used valuing certain commoditybased derivative contracts changes material impact fair value positions december 31 2006 2005 derivatives designated hedges engage two types hedging activities hedges cash flow exposure hedges fair value exposure enter derivative contract may designate derivative either cash flow hedge fair value hedge time prepare documentation required sfas 133 hedges cash flow exposure primarily relate natural gas oil production hedges interest rate risks longterm debt designed hedge forecasted sales transactions limit variability cash flows received paid related recognized asset liability hedges fair value exposure entered protect fair value recognized asset liability firm commitment hedges interest rate foreign currency exposure designated either cash flow hedges fair value hedges based whether interest underlying debt converted either fixed floating interest rate changes derivative fair values designated cash flow hedges deferred accumulated comprehensive income loss extent effective recognized earnings hedged transactions occur changes fair value derivatives designated fair value hedges recognized earnings offsets changes fair values related hedged assets liabilities firm commitments ineffective portion hedge’s change fair value recognized immediately earnings component operating revenues interest debt expense income statement discussion hedging activities follows cash flow hedges majority commodity sales purchases spot market forward market prices use fixed price swaps floor ceiling contracts limit exposure fluctuations commodity markets well fluctuations foreign currency interest rates objective realizing fixed cash flow stream activities summary impacts cash flow hedges included accumulated comprehensive income loss net income taxes december 31 2006 2005 follows 1 reclassifications occur upon physical delivery hedged commodity forecasted transaction longer probable 2 2006 removed hedging designation certain derivatives hedged approximately 75 tbtu 154 mbbls natural gas oil production 2007 years ended december 31 2006 2005 2004 recognized net gain 10 million losses 5 million 1 million net income taxes income loss continuing operations related ineffective portion cash flow hedges fair value hedges fixed rate us dollar foreign currency denominated debt exposes us paying higher market rates interest rates decline use interest rate swaps protect value debt instruments converting fixed amounts interest due debt agreements variable interest payments recorded fair value derivatives component longterm debt related accrued interest december 31 2006 2005 derivatives follows amounts millions 1 record ineffectiveness related fair value hedges 2004 2005 2006 2 december 31 2006 2005 derivatives combined euro denominated debt converted 350 million euro debt 402 million commoditybased derivatives commoditybased derivatives primarily relate derivative contracts designated hedges contracts associated historical trading activities credit risk subject credit risk related financial instrument assets credit risk relates risk loss would incur result nonperformance counterparties pursuant terms contractual obligations measure credit risk estimated replacement costs commodities would purchase sell future plus amounts owed counterparties delivered unpaid commodities exposures netted legally enforceable right setoff maintain credit policies regard counterparties price risk management activities minimize overall credit risk policies require evaluation potential counterparties’ financial condition including credit rating ii collateral certain circumstances including cash advance letters credit guarantees iii use margining provisions standard contracts iv use master netting agreements allow netting positive negative exposures various contracts associated single counterparty use daily margining provisions financial contracts physical power agreements master netting agreements require counterparty post cash letters credit fair value contract exceeds daily contractual threshold amount typically tied published credit rating counterparty margining collateral provisions also allow us terminate contract liquidate positions counterparty unable provide required collateral margining provisions required return collateral amount posted collateral exceeds amount collateral required collateral received returned vary significantly day based changes market values counterparty’s credit ratings furthermore amount collateral hold may less fair value derivative contracts counterparty given period following table presents summary fair value derivative contracts net collateral liabilities right offset exists presented type derivative counterparty net asset exposure december 31 2006 2005 1 “investment grade” “below investment grade” determined using publicly available credit ratings “investment grade” includes counterparties minimum standard poor’s rating bbb moody’s rating baa3 “below investment grade” includes counterparties public credit rating meet criteria “investment grade” “not rated” includes counterparties rated public rating service approximately 54 counterparties december 31 2006 energy marketers although counterparties currently rated investment grade one counterparties fails perform may recognize immediate loss earnings well additional financial impacts future delivery periods extent replacement contract prices quantities cannot established december 31 2006 three counterparties deutsche bank ag j aron company constellation energy commodities group inc comprised 39 percent 18 percent 16 percent net financial instrument asset exposure december 31 2005 two counterparties constellation energy commodities group inc duke energy trading marketing llc comprised 28 percent 18 percent net financial instrument asset exposure concentration counterparties may impact overall exposure credit risk either positively negatively counterparties may similarly affected changes economic regulatory conditions 9 regulatory assets liabilities regulatory assets liabilities relate interstate pipeline subsidiaries included current noncurrent assets liabilities balance sheets balances presented balance sheets gross basis recoverable various periods details regulatory assets liabilities december 31 10 assets liabilities detail current noncurrent assets liabilities balance sheets december 31 11 property plant equipment depreciable lives table presents depreciation method depreciable lives property plant equipment 1 composite group method assets similar useful lives characteristics grouped depreciated one asset apply depreciation rate approved rate settlements total cost group net book value equals salvage value reevaluate depreciation rates time redevelop transportation rates file ferc increase decrease rates 2 capitalized costs associated proved reserves amortized life reserves using unit production method conversely capitalized costs associated unproved properties excluded amortizable base properties evaluated see note 1 additional information excess purchase cost december 31 2006 2005 tgp epng excess purchase costs associated acquisition total excess costs pipelines approximately 25 billion accumulated depreciation approximately 04 billion 03 billion december 31 2006 2005 excess costs depreciated life pipeline assets costs assigned related depreciation expense year ended december 31 2006 2005 2004 approximately 42 million currently earn return excess purchase costs rate payers capitalized costs construction capitalize carrying cost funds related construction longlived assets reflect increases cost asset balance sheet carrying cost consists interest cost debt could attributed assets constructed ii regulated transmission business return equity could attributed assets constructed debt portion calculated based average cost debt interest cost debt amounts capitalized included reduction interest expense income statements 41 million 41 million 35 million years ended december 31 2006 2005 2004 equity portion calculated using recent ferc approved equity rate return equity amounts capitalized included nonoperating income statement 28 million 31 million 22 million years ended december 2006 2005 2004 construction workin progress december 31 2006 2005 approximately 1 billion construction workinprogress included property plant equipment asset retirement obligations legal obligations associated retirement natural gas oil wells related infrastructure natural gas pipelines related transmission facilities storage wells well corporate headquarters building obligations plug wells production wells exhausted longer plan use abandon legal obligations associated natural gas transmission facilities relate primarily purging sealing pipelines abandoned also obligations remove hazardous materials associated natural gas transmission facilities corporate headquarters facilities replaced renovated accrue liability legal obligations based estimate timing amount settlement required operate maintain natural gas pipeline storage systems intend long supply demand natural gas exists expect foreseeable future therefore believe substantial majority natural gas pipeline storage system assets indeterminate lives continue evaluate asset retirement obligations future developments could impact amounts record estimating liability associated asset retirement obligations utilize several assumptions including creditadjusted discount rates ranging six eight percent projected inflation rate 25 percent changes estimate represent changes expected amount timing payments settle asset retirement obligations typically changes primarily result obtaining new information exploration production segment timing obligations plug natural gas oil wells costs 2006 also revised estimates due primarily impacts hurricanes katrina rita net asset retirement liability december 31 reported balance sheet current noncurrent liabilities changes net liability years ended december 31 follows 1 decrease due primarily sale certain domestic natural gas oil properties exploration production segment 2005 see note 2 recorded charge 2005 4 million net income taxes 2 million cumulative effect accounting change upon adoption fin 47 primarily related pipelines segment corporate activities adopted provisions fin 47 january 1 2004 net income years ended december 31 2004 2005 would materially affected 12 debt financing obligations credit facilities following provides additional detail longterm financing obligations 1 excludes 741 967 million debt related discontinued operations 2006 2005 changes longterm financing obligations 2006 following changes longterm financing obligations 1 included liabilities related discontinued operations balance sheet december 31 2005 prior redemption 2006 recorded accretion expense zero coupon debentures increased principal balance longterm debt period 2006 2005 accretion recorded interest expense 4 million 25 million 2006 2005 redeemed 615 million 236 million zero coupon convertible debentures 110 million 34 million represented increased principal due accretion interest debentures account redemptions financing activities statement cash flows debt maturities aggregate maturities principal amounts longterm financing obligations next 5 years total thereafter follows millions approximately 600 million debt obligations redeemable option holders first half 2007 prior stated maturity date result amounts classified current liabilities balance sheet december 31 2006 subsequent date holders 300 million obligations exercise redemption right debt mature 2027 addition approximately 9 billion debt obligations increasing approximately 10 billion end 2008 provide us ability call debt prior stated maturity date redeemed prior stated maturities required pay makewhole fixed premium addition repaying principal accrued interest february 2007 launched tender offer certain outstanding debt obligations conjunction closing sale anr related assets credit facilities available capacity credit agreements december 31 2006 available capacity credit agreements approximately 1 billion amount 04 billion related 500 million revolving credit agreement subsidiary epep 06 billion available 175 billion credit agreement 500 million unsecured revolving credit facility january 2007 borrowed approximately 250 million epep revolving credit facility fund acquisition additional natural gas oil properties credit agreement restructuring july 2006 restructured 3 billion credit agreement part restructuring entered new 175 billion credit agreement consisting 125 billion threeyear revolving credit facility 500 million fiveyear deposit letter credit facility conjunction restructuring recorded 2006 charge approximately 17 million associated unamortized financing costs previous credit agreement el paso certain subsidiaries guaranteed 175 billion credit agreement collateralized stock ownership cig epng tgp also eligible borrowers 175 billion credit agreement 125 billion revolving credit facility matures july 2009 borrow funds libor plus 175 issue letters credit 175 plus fee 015 amount issued pay annual commitment fee 0375 unused capacity revolving credit facility terms 500 million deposit letter credit facility provide ability issue letters credit borrow amounts revolving loans mature july 2011 pay libor plus 200 amounts borrowed deposit facility 215 letters credit 210 unused capacity unsecured revolving credit facility 500 million unsecured revolving credit facility matures july 2011 third party third party trust provides borrowings issuing letters credit required pay fixed facility fees rate 23 total committed amount facility addition pay interest borrowings rate comprised either libor base rate epep revolving credit facility 500 million revolving credit agreement epep borrow revolving loans issue letters credit maturity date august 2010 amounts borrowed classified longterm balance sheet carry interest rate libor plus fixed percentage 125 1875 depending utilization facility collateralized certain natural gas oil properties contingent letter credit facility january 2007 el paso entered 250 million unsecured contingent letter credit facility matures march 2008 letters credit available us facility average nymex gas price strip remaining calendar months march 2008 equal exceeds 1175 per mmbtu facility fee triggered 166 per annum restrictive covenants 175 billion revolving credit facility covenants 175 billion revolving credit facility include restrictions debt levels restrictions liens securing debt guarantees restrictions mergers sales assets dividend restrictions cross default crossacceleration breach covenants could result acceleration debt financial obligations subsidiaries credit agreement restrictive debt covenants cross default provisions ratio debt consolidated ebitda defined credit agreement shall exceed 575 1 anytime prior june 30 2007 thereafter shall exceed 55 1 june 29 2008 525 1 june 30 2008 maturity b ratio consolidated ebitda defined credit agreement interest expense plus dividends paid shall less 175 1 anytime prior december 31 2006 thereafter shall less 180 1 june 29 2008 200 1 june 30 2008 maturity c epng tgp cig cannot incur incremental debt incurrence incremental debt would cause debt consolidated ebitda ratio defined credit agreement particular company exceed 50 1 occurrence event default expiration applicable grace period respect debt aggregate principal amount 200 million epep revolving credit facility epep’s borrowings facility subject various conditions financial coverage ratio facility requires epep’s ebitda defined facility interest expense less 20 1 epep’s debt ebitda defined credit agreement must exceed 40 1 epep’s collateral coverage ratio defined credit agreement must exceed 15 1 restrictions provisions addition restrictions provisions andor subsidiaries subject number additional restrictions covenants restrictions covenants include limitations additional debt subsidiaries limitations use proceeds borrowing subsidiaries limitations cases transactions affiliates limitations occurrence liens potential limitations abilities subsidiaries declare pay dividends potential limitations subsidiaries participate cash management program limitations subsidiaries’ ability prepay debt restrictive acceleration provision 5 million associated indenture one subsidiaries indenture states event default occur resulting acceleration debt obligations excess 5 million longterm debt obligation containing provision could accelerated acceleration debt would adversely affect liquidity position turn financial condition also issued various guarantees securing financial obligations subsidiaries affiliates similar covenants facilities financing arrangements capital trusts el paso energy capital trust wholly owned business trust formed march 1998 issued 65 million 475 percent trust convertible preferred securities 325 million trust exists sole purpose issuing preferred securities investing proceeds 475 percent convertible subordinated debentures issued due 2028 trust i’s sole source income interest earned debentures interest income used pay distributions preferred securities also two wholly owned business trusts el paso energy capital trust ii iii trust ii iii issued securities provide full unconditional guarantee trust i’s preferred securities would provide guarantee securities issued trust ii iii trust i’s preferred securities nonvoting except limited circumstances pay quarterly distributions annual rate 475 percent carry liquidation value 50 per security plus accrued unpaid distributions convertible common shares time prior close business march 31 2028 option holder rate 12022 common shares trust preferred security equivalent conversion price 4159 per common share classified securities longterm debt right redeem securities time nonrecourse project financings many subsidiaries investments debt obligations related costs project construction acquisition several projects experienced events either constituted could constitute event default loan agreements project financing debt recourse project company assets ie without recourse el paso believe defaults events led could lead events default projects material effect us subsidiaries’ financial statements based amounts recorded balance sheet projects andor current status negotiations relating projects letters credit enter letters credit ordinary course operating activities well periodically conjunction sales assets businesses december 31 2006 outstanding letters credit approximately 14 billion included amount 11 billion letters credit securing recorded obligations related price risk management activities 13 commitments contingencies legal proceedings shareholder litigation twentyeight purported shareholder class action lawsuits pending since 2002 consolidated federal court houston texas consolidated lawsuit alleges violations federal securities laws us several current former officers directors november 2006 parties executed definitive settlement agreement parties agreed settle class action lawsuits subject final court approval terms settlement el paso insurers pay total 273 million plaintiffs el paso contributed approximately 48 million insurers contributed approximately 225 million escrow account pending final court approval settlement additional 12 million separately contributed third party terms settlement erisa class action suits december 2002 purported class action lawsuit entitled william h lewis iii v el paso corporation et al filed us district court southern district texas alleging communication participants retirement savings plan included misrepresentations omissions similar pled consolidated shareholder litigation caused members class hold maintain investments el paso stock violation employee retirement income security act erisa formal discovery lawsuit currently stayed various insurance coverages lawsuit subject certain deductibles copay obligations established accruals matters believe adequate cash balance plan lawsuit december 2004 purported class action lawsuit entitled tomlinson et al v el paso corporation el paso corporation pension plan filed us district court denver colorado lawsuit alleges various violations erisa age discrimination employment act result change final average earnings formula pension plan cash balance pension plan costs legal exposure related lawsuit currently determinable retiree medical benefits matters currently serve plan administrator medical benefits plan covers closed group retirees case corporation retired july 1 1994 case formerly subsidiary tenneco inc spun prior acquisition tenneco 1996 tenneco retained obligation provide certain medical prescription drug benefits eligible retirees spouses assumed obligation result merger tenneco pursuant agreement applicable union case employees liability benefits subject cap costs excess cap assumed plan participants 2002 case sued individual retirees federal court detroit michigan action entitled yolton et al v el paso tennessee pipeline co case corporation suit alleges among things el paso case violated erisa required pay amounts cap case filed claims el paso asserting el paso obligated indemnify defend hold case harmless amounts would required pay separate rulings 2004 court ruled pending trial merits case must pay amounts incurred cap el paso must reimburse case payments january 2006 rulings upheld appeal us court appeals 6th circuit proceed trial merits regard issues whether cap enforceable degree benefits actually vested resolved el paso indemnify case payments case makes cap currently 18 million per month continue defend action filed approval trial court various amendments medical benefit plans would allow us deliver benefits plan participants cost effective manner although uncertain plan amendments ultimately approved approval plan amendments could reduce overall costs result could reduce recorded obligation established accrual matter believe adequate natural gas commodities litigation beginning august 2003 several lawsuits filed el paso marketing lp epm allege el paso epm energy companies conspired manipulate price natural gas providing false price information industry trade publications published gas indices first cases consolidated federal court new york pretrial purposes styled gas commodity litigation september 2005 court certified class include persons purchased sold nymex natural gas futures january 1 2000 december 31 2002 executed settlement agreement plaintiffs subject court approval second set cases involving similar allegations behalf commercial residential customers transferred multidistrict litigation proceeding mdl us district court nevada western states wholesale natural gas antitrust litigation dismissed appealed third set cases also involve similar allegations behalf certain purchasers natural gas include purported class action lawsuits styled leggett et al v duke energy corporation et al filed chancery court tennessee january 2005 everbloom inc v aep energy services inc et al filed federal court eastern district california june 2005 farmland industries inc v oneok inc filed state court wyandotte county kansas july 2005 learjet inc v oneok inc filed state court wyandotte county kansas september 2005 breckenridge et al v oneok inc et al filed state court denver county colorado may 2006 missouri public service commission v el paso corporation et al filed circuit court jackson county missouri kansas city october 2006 arandell et al v xcel energy et alfiled circuit court dane county wisconsin december 2006 leggett farmland cases dismissed arandell missouri public service cases removed federal court remaining cases transferred mdl proceeding similar motions dismiss either filed anticipated filed cases well costs legal exposure related lawsuits claims currently determinable gas measurement cases number subsidiaries named defendants actions generally allege mismeasurement natural gas volumes andor heating content resulting underpayment royalties first set cases filed 1997 individual false claims act consolidated pretrial purposes natural gas royalties qui tam litigation us district court district wyoming complaints allege industrywide conspiracy underreport heating value well volumes natural gas produced federal native american lands may 2005 representative appointed court issued recommendation dismiss actions october 2006 us district judge issued order dismissing mismeasurement claims defendants appeal filed similar allegations filed set actions initiated 1999 price et al v gas pipelines predecessors et al district court stevens county kansas plaintiffs currently seek certification class royalty owners wells nonfederal nonnative american lands kansas wyoming colorado motions class certification briefed argued proceedings parties awaiting court’s ruling plaintiff seeks unspecified amount monetary damages form additional royalty payments along interest expenses punitive damages injunctive relief regard future gas measurement practices costs legal exposure related lawsuits claim currently determinable mtbe certain subsidiaries used gasoline additive methyl tertiarybutyl ether mtbe gasoline certain subsidiaries also produced bought sold distributed mtbe number lawsuits filed throughout us regarding mtbe’s potential impact water supplies subsidiaries among defendants 70 lawsuits suits consolidated pretrial purposes multi district litigation us district court southern district new york plaintiffs certain state attorneys general various water districts limited number individual water customers generally seek remediation groundwater prevention future contamination damages punitive damages attorney’s fees court costs among allegations plaintiffs assert gasoline containing mtbe defective product defendant refiners liable proportion market share costs legal exposure related lawsuits currently determinable government investigations inquiries reserve revisions march 2004 received subpoena sec requesting documents relating december 31 2003 natural gas oil reserve revisions continue cooperate sec investigation related reserve revisions iraq oil sales several government agencies investigating coastal corporation’s el paso’s purchases crude oil iraq united nations’ oil food program agencies include us attorney southern district new york sdny sec office foreign assets control ofac february 2007 entered agreements sdny sec ofac resolve pending investigations participation oil food program agreements obligate us pay approximately 8 million approximately 6 million intended ultimately transferred humanitarian fund benefit iraqi people government investigations also continue provide information cooperate inquiry investigation us attorney sec response requests information regarding price reporting transactional data energy trade press hedges natural gas production contingencies epng rate case june 2005 epng filed rate case ferc proposing increase revenues 106 percent 56 million annually current tariff rates new services revisions certain terms conditions existing services january 1 2006 rates became effective subject refund march 2006 ferc issued order generally approved proposed new services implemented june 1 2006 december 2006 epng filed settlement rate case ferc settlement provides benefits epng customers threeyear period ending december 31 2008 one party rate case contested settlement administrative law judge certified settlement ferc finding settlement could approved parties alternative contesting party could severed settlement reserved sufficient amounts meet epng’s refund obligations settlement refunds payable within 120 days approval ferc iraq imports december 2005 ministry oil state oil marketing organization iraq somo sent invoice one subsidiaries regard shipments crude oil somo alleged purchased paid coastal 1990 invoices request additional 144 million payments shipments along allegation undefined amount interest invoice appears associated cargoes coastal purchased 1990 invasion kuwait iraq requested additional information somo assist evaluation invoice underlying facts addition evaluating legal defenses including applicable statute limitation periods navajo nation approximately 900 looped pipeline miles north mainline epng pipeline system located lands held trust united states benefit navajo nation rightsofway lands crossing navajo nation subject pending renewal application filed 2005 department interior’s bureau indian affairs interim agreement navajo nation expired end december 2006 negotiations terms longterm agreement continuing addition continue preserve legal regulatory legislative alternatives includes continuing pursue application department interior renewal rightsofway navajo nation lands uncertain whether negotiation alternatives successful ultimate cost obtaining rightsofway whether able recover costs rates addition matters subsidiaries affiliates named defendants numerous lawsuits governmental proceedings arise ordinary course business also regulatory rules orders various stages adoption review andor implementation outstanding legal contingent matters evaluate merits case exposure matter possible legal settlement strategies likelihood unfavorable outcome determine unfavorable outcome probable estimated establish necessary accruals outcome matters including discussed cannot predicted certainty still uncertainties related costs may incur based upon evaluation experience date believe established appropriate reserves matters however possible new information future developments could require us reassess potential exposure related matters adjust accruals accordingly adjustments could material december 31 2006 approximately 548 million accrued net related insurance receivables outstanding legal contingent matters deposited 60 million escrow account shareholder litigation environmental matters subject federal state local laws regulations governing environmental quality pollution control laws regulations require us remove remedy effect environment disposal release specified substances current former operating sites december 31 2006 accrued approximately 314 million reduced 31 million amounts paid directly government sponsored programs accrual includes approximately 305 million expected remediation costs associated onsite offsite groundwater technical studies approximately 9 million related environmental legal costs 314 million accrual 28 million reserved facilities currently operate 286 million reserved nonoperating sites facilities shut sold superfund sites reserve estimates range approximately 314 million approximately 532 million accrual represents combination two estimation methodologies first likely outcome reasonably estimated cost accrued 27 million second likely outcome cannot estimated range costs established 287 million 505 million one amount range likely lower end expected range accrued environmental remediation projects various stages completion recorded liabilities reflect current estimates amounts expend remediate sites however depending stage completion assessment ultimate extent contamination remediation required may known additional assessments occur remediation efforts continue may incur additional liabilities type site reserves based following estimates reasonably possible outcomes reconciliation accrued liability january 1 2006 december 31 2006 millions 2007 estimate total remediation expenditures approximately 84 million expended government directed cleanup plans addition expect make capital expenditures environmental matters approximately 21 million aggregate years 2007 2011 expenditures primarily relate compliance clean air regulations cercla matters received notice could designated asked information determine whether could designated potentially responsible party prp respect 53 active sites cercla state equivalents sought resolve liability prp sites indemnification thirdparties settlements provide payment allocable share remediation costs december 31 2006 estimated share remediation costs sites 34 million 58 million cleanup costs estimates subject revision information becomes available extent remediation required cases asserted defense liability estimates could change moreover liability federal cercla statute joint several meaning could required pay excess pro rata share remediation costs understanding financial strength prps considered appropriate estimating liabilities accruals issues included previously indicated estimates superfund sites possible new information future developments could require us reassess potential exposure related environmental matters may incur significant costs liabilities order comply existing environmental laws regulations also possible developments increasingly strict environmental laws regulations orders regulatory agencies well claims damages property environment injuries employees persons resulting current past operations could result substantial costs liabilities future information becomes available relevant developments occur adjust accrual amounts accordingly still uncertainties related ultimate costs may incur based upon evaluation experience date believe reserves adequate commitments purchase obligations matters operating leases maintain operating leases ordinary course business activities leases include office space operating facilities office operating equipment terms agreements vary 2007 2053 december 31 2006 total commitments noncancellable operating leases approximately 98 million reduced minimum sublease rentals approximately 4 million due future noncancelable subleases minimum annual rental commitments operating leases december 31 2006 follows lease obligations table significantly decrease 2007 based upon expiration certain lease payments made accordance termination agreement signed 2005 related consolidating houstonbased operations one location rental expense lease obligations years ended december 31 2006 2005 2004 43 million 53 million 90 million includes 27 million 80 million 2005 2004 related consolidating houstonbased operations guarantees involved various joint ventures ownership arrangements sometimes require additional financial support results issuance financial performance guarantees financial guarantee obligated make payments guaranteed party fails make payments violates terms financial arrangement performance guarantee provide assurance guaranteed party execute terms contract required perform behalf also periodically provide indemnification arrangements related assets businesses sold arrangements include limited indemnification income taxes resolution existing disputes environmental matters necessary expenditures ensure safety integrity assets sold december 31 2006 recorded obligations 71 million related guarantees indemnification arrangements total stated value approximately 376 million indemnified third parties 18 million amounts exclude guarantees issued related letters credit discussed note 12 included stated value 376 million approximately 120 million associated tax matters related interest indemnifications arising sale macae power facility addition exposures described trial court ruled upheld appeal required indemnify third party benefits paid closed group retirees one former subsidiaries liability approximately 379 million associated estimated exposure matter december 31 2006 discussion matter see retiree medical benefits matters commercial commitments various commercial commitments purchase obligations recorded balance sheet december 31 2006 firm commitments transportation storage capacity contracts 400 million purchase capital commitments including maintenance engineering procurement construction contracts 540 million also hold cancelable easements rightofway arrangements landowners permitting use land construction operation pipeline systems currently obligation easements material results operations however currently negotiating longterm rightofway agreement navajo nation could result significant commitment us see navajo nation 14 retirement benefits overview retirement benefits pension benefits primary pension plan defined benefit plan covers substantially us employees provides benefits cash balance formula certain employees participated prior pension plans el paso sonat coastal receive greater cash balance benefits transition benefits prior plan formulas anticipate making contributions pension plan 2007 addition primary pension plan maintain supplemental executive retirement plan serp provides additional benefits selected officers key management serp provides benefits excess certain irs limits essentially mirror primary pension plan also maintain two pension plans closed new participants provide benefits former employees previously discontinued coal convenience store operations serp frozen plans together referred pension plans also participate several multiemployer pension plans benefit former employees union members contributions plans 2006 2005 2004 material expect contribute 5 million serp 3 million frozen plans 2007 2004 recognized 4 million curtailment benefit pension plans due reduction number employees participate pension plan reduction resulted asset sales severance employees retirement savings plan maintain defined contribution plan covering us employees match 75 percent participant basic contributions 6 percent eligible compensation make additional discretionary matching contributions amounts expensed plan approximately 35 million 30 million 16 million years ended december 31 2006 2005 2004 postretirement benefits provide postretirement medical benefits closed groups retired employees limited postretirement life insurance benefits current retired employees postretirement employee benefits opeb regulated pipeline companies prefunded extent costs recoverable rates extent actual opeb costs regulated pipeline companies differ amounts recovered rates regulatory asset liability recorded expect contribute 42 million postretirement plans 2007 medical benefits closed groups retirees may subject deductibles copayment provisions limitations dollar caps amount employer costs reserve right change benefits retain postretirement benefit plans associated retirees anr sale operations 2007 pension postretirement benefits december 31 2006 adopted recognition provisions sfas 158 upon adoption reflected assets liabilities related pension postretirement benefit plans based funded unfunded status actuarial deferrals reclassified component accumulated comprehensive income adoption standard decreased noncurrent assets 601 million noncurrent deferred tax liabilities 210 million accumulated comprehensive income 391 million table provides additional information related pension postretirement plans september 30 measurement date obligations plan assets december 31 balance sheet amounts accumulated benefit obligation defined benefit pension plans 2148 million 2216 million december 31 2006 2005 pension plans whose accumulated benefit obligations exceeded fair value plan assets projected benefit obligation accumulated benefit obligation 167 million december 31 2006 176 million december 31 2005 fair value plan assets 110 million 99 million december 31 2006 2005 accumulated postretirement benefit obligation fair value plan assets associated postretirement benefit plans whose accumulated postretirement benefit obligations exceeded fair value plan assets 320 million 67 million december 31 2006 374 million 84 million december 31 2005 accumulated comprehensive income includes approximately 10 million unamortized prior service costs net tax anticipate approximately 25 million accumulated comprehensive loss net tax recognized part net periodic benefit cost 2007 change benefit obligation plan assets funded status benefits presented computed twelve months ended september 30 1 benefit obligation table refers projected benefit obligation pension plans accumulated postretirement benefit obligation postretirement plans 2 increase due primarily changes discount rate mortality assumptions 2005 3 defer difference actual return plan assets expected return three year period considered inclusion net benefit expense income deferred actuarial gains losses recognized extent remaining unrecognized actual gains loses exceed greater 10 percent projected benefit obligations market related value plan assets 4 amounts reclassified accumulated comprehensive income upon adoption sfas 158 2006 expected payment future benefits december 31 2006 expect following payments plans 1 includes reduction years presented expected subsidy related medicare prescription drug improvement modernization act 2003 components net benefit cost years ended december 31 components net benefit cost follows 1 permitted amortization prior service cost determined using straightline amortization cost average remaining service period employees expected receive benefits plan actuarial assumptions sensitivity analysis projected benefit obligations net benefit cost based actuarial estimates assumptions following table details weightedaverage actuarial assumptions used determining projected benefit obligation net benefit costs pension postretirement plans 2006 2005 2004 1 expected return plan assets pretax rate tax rate ranging 26 percent 27 percent postretirement benefits primarily based expected riskfree investment return adjusted historical risk premiums specific risk adjustments associated debt equity securities expected returns weighted based target asset allocations investment portfolio actuarial estimates postretirement benefit plans assumed weightedaverage annual rate increase per capita costs covered health care benefits 103 percent gradually decreasing 50 percent year 2015 assumed health care cost trends significant effect amounts reported postretirement benefit plans onepercentage point change assumed health care cost trends would following effects september 30 plan assets following table provides target actual asset allocations pension postretirement benefit plans september 30 1 2005 liquidated el paso common stock included plan assets primary investment objective plans ensure longterm life plans adequate pool sufficiently liquid assets support benefit obligations participants retirees beneficiaries exists meeting objective plans seek achieve high level investment return consistent prudent level portfolio risk investment objectives longterm nature covering typical market cycles three five years shortfall investment performance compared investment objectives result general economic capital market conditions matters fourth quarter 2005 recorded increase legal reserves approximately 350 million associated closed group retirees case corporation increasing total liability approximately 379 million december 31 2006 trial court ruled upheld appeal required indemnify case benefits paid retirees estimated liability ruling utilizing actuarial methods similar used estimating obligations associated postretirement benefit plans however legal reserves included disclosures related pension postretirement benefits discussion matter see note 13 15 stockholders’ equity common stock may 2006 issued 357 million shares common stock net proceeds approximately 500 million 2005 issued approximately 136 million shares common stock remaining holders 272 million notes originally formed portion equity security units settlement commitment purchase shares 2004 issued 264 million shares satisfy obligations western energy settlement convertible perpetual preferred stock april 2005 issued 750 million convertible perpetual preferred stock dividends preferred stock declared quarterly rate 499 per annum approved board directors dividends accumulate paid share preferred stock convertible holder’s option time subject adjustment 767754 shares common stock certain conditions conversion rate represents equivalent conversion price approximately 1303 per share conversion rate subject adjustment based certain events include limited fundamental changes business mergers business combinations well distributions common stock adjustments current rate dividends common stock able cause preferred stock converted common stock five years common stock trading premium 130 percent conversion price net proceeds 723 million issuance preferred stock together cash hand used prepay western energy settlement approximately 442 million redeem 6 million outstanding shares 825 series cumulative preferred stock subsidiary eptp approximately 300 million dividends table shows amount dividends paid declared millions except per share amounts dividends common stock treated reduction additional paidincapital since currently accumulated deficit expect dividends paid common preferred stock 2006 taxable stockholders anticipate dividends paid current accumulated earnings profits tax purposes terms 750000 outstanding shares 499 convertible preferred stock prohibit payment dividends common stock unless paid set aside payment accumulated unpaid dividends preferred stock preceding dividend periods addition although credit facilities contain direct restriction payment dividends included fixed charge calculation fixed charge coverage ratio credit facilities fixed charge ratio exceed permitted maximum level ability pay additional dividends would restricted accumulated comprehensive income following table provides components accumulated comprehensive income loss december 31 16 stockbased compensation stockbased compensation plans may issue employees incentive stock options common stock intended qualify section 422 internal revenue code nonqualified stock options restricted stock restricted stock units stock appreciation rights performance shares performance units stockbased awards authorized grant awards approximately 425 million shares common stock current plans includes 35 million shares employee plan 25 million shares nonemployee director plan 5 million shares employee stock purchase plan december 31 2006 approximately 35 million shares remain available grant current plans addition approximately 22 million shares stock option awards outstanding granted terminated plans obligate us issue additional shares common stock exercised stock option exercises restricted stock funded primarily issuance new common shares nonqualified stock options grant nonqualified stock options employees exercise price equal market value stock grant date stock option awards contractual terms 10 years generally vest equal amounts three years grant date pay dividends unexercised options summary stock option transactions year ended december 31 2006 presented total compensation cost related nonvested option awards yet recognized december 31 2006 approximately 10 million expected recognized weighted average period 11 months options exercised year ended december 31 2006 total intrinsic value approximately 5 million generated 6 million cash proceeds generate significant associated income tax benefit total intrinsic value cash received income tax benefit generated option exercises material years ended december 31 2005 2004 fair value assumptions fair value stock option granted estimated date grant using blackscholes optionpricing model based several assumptions based management’s best estimate time grant years ended december 31 2006 2005 2004 weighted average grant date fair value per share options granted 489 388 269 listed weighted average assumption based grants fiscal year estimate expected volatility based analysis implied volatilities traded options common stock historical stock price volatility expected term adjusted certain time periods believe representative future stock performance prior january 1 2006 estimated expected volatility based primarily adjusted historical stock price volatility effective january 1 2006 adopted provisions sec staff accounting bulletin 107 estimate expected term option awards based vesting period average remaining contractual term restricted stock may grant shares restricted common stock carry voting dividend rights officers employees sale transfer shares restricted vest currently outstanding grant timebased restricted stock performancebased restricted share awards fair value timebased restricted shares determined grant date shares generally vest equal amounts three years date grant summary changes nonvested restricted shares fiscal years presented weighted average grant date fair value per share restricted stock granted 2006 2005 2004 1309 1078 863 total fair value shares vested 2006 2005 2004 236 million 143 million 67 million 2006 2005 2004 recognized approximately 17 million 18 million 23 million pretax compensation expense capitalized approximately 2 million year part fixed assets recorded 6 million 6 million 8 million income tax benefits related restricted stock arrangements total unrecognized compensation cost related arrangements december 31 2006 approximately 22 million expected recognized weighted average period 11 months upon adoption sfas 123r recorded cumulative effect change accounting principle less 1 million result estimating forfeitures restricted stock date grant compared recognizing forfeitures occur also reclassified unearned compensation additional paidin capital balance sheet required sfas 123r employee stock purchase plan july 2005 reinstated employee stock purchase plan section 423 internal revenue code amended restated plan allows participating employees right purchase common stock 95 percent market price last trading day month plan noncompensatory provisions sfas 123r shares issued plan insignificant 2006 2005 2004 17 business segment information december 31 2006 business consists pipelines exploration production marketing power segments prior 2006 also field services segment reclassified certain operations discontinued operations periods presented see notes 1 2 segments strategic business units provide variety energy products services managed separately segment requires different technology marketing strategies corporate operations include general administrative functions well miscellaneous businesses various contracts assets immaterial discussion segment follows pipelines provides natural gas transmission storage related services primarily united states december 31 2006 conducted activities primarily eight wholly owned five partially owned interstate transmission systems along five underground natural gas storage entities lng terminalling facility february 2007 sold anr michigan storage facilities 50 percent interest great lakes gas transmission exploration production engaged exploration acquisition development production natural gas oil ngl primarily united states brazil egypt marketing focuses marketing managing price risks associated natural gas oil production well management remaining historical trading portfolio power primarily consists remaining international power assets historically segment also domestic power activities completed sale domestic power facilities sold announced sale substantially international operations except brazil primary focus within power segment manage risks associated remaining assets brazil prior january 1 2006 field services segment conducted midstream activities disposed substantially assets segment customers whose revenues exceeded 10 percent total revenues 2006 2005 2004 management uses earnings interest expense income taxes ebit assess operating results effectiveness business segments consist consolidated businesses well substantial investments unconsolidated affiliates believe ebit useful investors allows effectively evaluate operating performance using performance measure analyzed internally management define ebit net income loss adjusted items impact income loss continuing operations extraordinary items discontinued operations impact accounting changes ii income taxes iii interest debt expense iv distributions preferred interests consolidated subsidiaries v preferred dividends also exclude interest debt expense distributions preferred interests consolidated subsidiaries investors may evaluate operating results without regard financing methods capital structure ebit may comparable measures used companies additionally ebit considered conjunction net income performance measures operating income operating cash flow reconciliation ebit income loss continuing operations three years ended december 31 following tables reflect segment results three years ended december 31 1 includes eliminations intercompany transactions intersegment revenues along intersegment operating expenses incurred normal course business operating segments recorded intersegment revenue elimination 37 million operation maintenance expense elimination 13 million included “corporate” column remove intersegment transactions 2 revenues external customers include gains losses related hedging price risk associated natural gas oil production intersegment revenues represent sales marketing segment responsible marketing production 3 excludes assets discontinued operations 4133 million see note 2 4 total foreign assets approximately 362 million relates property plant equipment approximately 07 billion relates investments advances unconsolidated affiliates 5 amounts net third party reimbursements capital expenditures returns invested capital 1 includes eliminations intercompany transactions intersegment revenues along intersegment operating expenses incurred normal course business operating segments recorded intersegment revenue elimination 91 million operation maintenance expense elimination 2 million included “corporate” column remove intersegment transactions 2 revenues external customers include gains losses related hedging price risk associated natural gas oil production intersegment revenues represent sales marketing segment responsible marketing production 3 relates intercompany activities continuing operations discontinued operations 4 excludes assets discontinued operations 4649 million 5 total foreign assets approximately 324 million relates property plant equipment approximately 10 billion relates investments advances unconsolidated affiliates 6 amounts net third party reimbursements capital expenditures returns invested capital 1 includes eliminations intercompany transactions intersegment revenues along intersegment operating expenses incurred normal course business operating segments recorded intersegment revenue elimination 236 million operation maintenance expense elimination 25 million included “corporate” column remove intersegment transactions 2 revenues external customers include gains losses related hedging price risk associated natural gas oil production intersegment revenues represent sales marketing segment responsible marketing production 3 relates intercompany activities continuing operations discontinued operations 4 excludes assets discontinued operations 5398 million 5 total foreign assets approximately 435 million relates property plant equipment approximately 15 billion relates investments advances unconsolidated affiliates 6 amounts net third party reimbursements capital expenditures returns invested capital 18 investments earnings transactions unconsolidated affiliates hold investments unconsolidated affiliates accounted using equity method accounting income statement typically reflects share net earnings directly attributable unconsolidated affiliates ii impairments adjustments recorded us investment balance differs underlying net equity investments due primarily purchase price adjustments impairment charges recorded us december 31 2006 2005 investment balance exceeded net equity underlying net assets investments 409 million 378 million due items largest purchase price adjustments related investment four star acquired 2005 generally amortize assess recoverability amount based development production underlying proved natural gas oil reserves four star net ownership interest investments earnings losses unconsolidated affiliates follows years ended december 31 1 amortization purchase cost excess underlying net assets four star 54 million 20 million 2006 2005 2 sold interests investments 3 received approval board directors sell interest investments substantially targeted close first half 2007 4 december 31 2006 2005 outstanding advances receivables 413 million 385 million related foreign investments 25 million 37 million related investment habibullah power 350 million 331 million relate investment porto velho remainder foreign investments recognized interest income outstanding advances receivables approximately 46 million 47 million 44 million 2006 2005 2004 5 deconsolidated 100 owned investments january 2005 upon entering agreement transfer ownership plants power purchaser january 2008 impairment charges gains losses sales equity investments included earnings unconsolidated affiliates 2006 2005 2004 impairments gains losses primarily result decision sell number investments based declines fair value investments due changes economics investments’ underlying contracts markets serve realized gains losses consisted following 1 amounts represent impairment investment 2004 recording proportionate share losses investment mcv 2005 primarily based mcv’s impairment plant assets gain sale 2006 summarized financial information proportionate share operating results financial position unconsolidated affiliates including hold greater 50 percent interest 1 includes net income 20 million 15 million 7 million 2006 2005 2004 related proportionate share affiliates hold greater 50 percent interest 2 includes total assets 417 million 485 million december 31 2006 2005 related proportionate share affiliates hold greater 50 percent interest received distributions dividends 177 million 203 million 2006 2005 includes 38 million less 1 million returns capital investments following table shows revenues charges resulting transactions unconsolidated affiliates 1 decrease primarily due sale investments power segment 2 decrease activity 2005 due primarily sale gulfterra 2004 accounts receivable sales program third quarter 2006 entered agreements sell certain accounts receivable qualifying special purpose entities qspes sfas 140 accounting transfers servicing financial assets extinguishments liabilities december 31 2006 sold approximately 202 million receivables received cash approximately 108 million received subordinated beneficial interests approximately 91 million recognized loss approximately 3 million conjunction sale qspes also issued senior beneficial interests receivables sold third party financial institution totaled 111 million closing date reflect subordinated beneficial interest receivables sold accounts receivable affiliates balance sheet reflect accounts receivable sold program changes subordinated beneficial interests operating cash flows statement cash flows agreements earn fee servicing accounts receivable performing administrative duties qspes reflected reduction operation maintenance expense income statement fair value servicing administrative agreements well fees earned material financial statements year ended december 31 2006 matters could impact investments international power december 31 2006 equity investments seven power generation transmission facilities asia central america brazil considered variable interests fin 46r operate facilities supply significant portion fuel consumed purchase significant portion power generated facilities additionally longterm debt issued entities recourse project investments advances entities well guarantees agreements follows december 31 2006 porto velho 315 million stateowned facility purchases power generated facility brazil approached us opportunity potentially sell interest power plant although currently indications impairment investment evaluate potential opportunity could required record loss based potential value may receive december 2006 brazilian tax authorities assessed 30 million fine porto velho power project allegedly filing proper tax forms related consumption fuel power facility power purchase agreement believe tax authority’s claims without merit manaus rio negro 97 million agreement transfer ownership facility brazil power purchaser january 2008 asian central american power investments 105 million process selling assets changes political economic conditions could negatively impact amount net proceeds expect receive upon sale may result additional impairments domestic power 2006 completed sales remaining investments domestic power facilities continue supply gas mcv natural gas supply contracts recorded loss third quarter approximately 133 million contracts longer affiliate prior sale recognized cumulative marktomarket losses contracts extent ownership interest due affiliated nature secure remaining obligations contracts also issued letters credit mcv approximately 208 million december 31 2006 investment bolivia 8 percent interest bolivia brazil pipeline december 31 2006 total investment guarantees related pipeline project approximately 117 million bolivian portion 3 million 2006 bolivian government announced decree significantly increasing interest control bolivia’s oil gas assets continue monitor evaluate together partners potential commercial impact recent political events bolivia could bolivia brazil pipeline new information becomes available future material developments arise may required record impairment investment argentina approximate 22 percent interest argentina chile pipeline december 31 2006 total investment pipeline project approximately 23 million july 2006 ministry economy production argentina issued decree significantly increases export taxes natural gas continue evaluate together partners potential commercial impact decree could argentina chile pipeline new information becomes available future material developments arise may required record impairment investment citrus trading corporation ctc direct subsidiary citrus 50 percent equity interest settled lawsuit january 2007 million spectra lng sales formerly duke energy lng sales inc wrongful termination gas supply contract entered parties 1988 pursuant settlement spectra lng sales paid ctc 100 million supplemental selected quarterly financial information unaudited financial information quarter adjusted reflect discontinued operations summarized unusual infrequently occurring items respective quarters 2006 2005 december 31 2006 188 million charge associated release capacity alliance contract ii approximately 188 million deferred taxes related anr discontinued operations note 2 september 30 2006 marktomarket losses 133 million mcv supply agreement recorded conjunction sale interest related power facility ii 105 million income tax benefit associated reduction tax contingencies reinstatement certain tax credits result irs audit settlements net tax amounts recognized certain foreign investments note 5 june 30 2006 income tax benefit 34 million associated irs audit settlements note 5 december 31 2005 350 million charge associated retiree medical benefits legal matters note 13 ii net gain approximately 400 million sale south louisiana processing facilities discontinued operations september 30 2005 proportionate share mcv investment’s losses approximately 160 million ii 109 million gain sale korean power facility june 30 2005 impairment macae power facility discontinued operations approximately 300 million ii 160 million impairments international power facilities iii approximately 70 million income recorded upon receipt payment bankruptcy claim march 31 2005 gain sale remaining investment enterprise 183 million ii net losses associated international power facilities approximately 75 million iii 59 million charge associated finalizing western energy settlement iv approximately 30 million income tax benefits primarily result irs audit settlements see note 5 supplemental natural gas oil operations unaudited exploration production segment engaged exploration acquisition development production natural gas oil ngl united states brazil egypt capitalized costs capitalized costs relating natural gas oil producing activities related accumulated depreciation depletion amortization follows december 31 millions 1 capitalized costs egypt 4 million december 31 2006 total costs incurred costs incurred natural gas oil producing activities whether capitalized expensed follows year ended december 31 millions 1 amount includes 179 million deferred income tax adjustments related acquisition fullcost pool properties 217 million related acquisition unconsolidated investment four star pursuant full cost method accounting capitalize certain general administrative expenses related property acquisition exploration development activities interest costs incurred attributable unproved oil gas properties major development projects oil gas properties table includes capitalized internal general administrative costs incurred connection acquisition development exploration natural gas oil reserves 50 million 47 million 44 million years ended december 31 2006 2005 2004 also capitalized interest 30 million 30 million 22 million years ended december 31 2006 2005 2004 january 1 2007 reserve report amounts estimated spent 2007 2008 2009 develop consolidated worldwide proved undeveloped reserves 424 million 473 million 243 million unevaluated capitalized costs exclude capitalized costs natural gas oil properties amortization various stages evaluation expect majority costs included amortization calculation 2007 2008 presented analysis capitalized costs natural gas oil properties year expenditures amortized december 31 2006 pending determination proved reserves millions 1 includes capitalized interest 24 million 9 million 1 million years ended december 31 2006 2005 2004 depreciation depletion amortization rates total amortization expense per mcfe united states 243 225 184 2006 2005 2004 230 233 202 brazil 2006 2005 2004 included worldwide depreciation depletion amortization expense accretion expense 007mcfe 010mcfe 008mcfe 2006 2005 2004 united states 003mcfe 2006 001mcfe 2005 2004 brazil attributable sfas 143 natural gas oil reserves net quantities proved developed undeveloped reserves natural gas ngl oil condensate changes reserves december 31 2006 presented tables based internal reserve report net proved reserves exclude royalties interests owned others reflect contractual arrangements royalty obligations effect time estimate consolidated reserves consistent estimates reserves filed federal agencies except differences less five percent resulting actual production acquisitions property sales necessary reserve revisions additions reflect actual experience ryder scott independent reservoir engineering firm reports audit committee board directors prepared estimate 84 percent consolidated natural gas oil reserves additionally ryder scott prepared estimate 80 percent proved reserves four star unconsolidated affiliate estimates four star’s proved natural gas oil reserves prepared internal reservoir engineers reflect prepared engineers four star based amount proved reserves determined ryder scott believe reported reserve amounts reasonable ryder scott’s reports included exhibits annual report form 10k 1 includes downward reserve revisions approximately 54 bcfe related price positive reserve revisions 39 bcfe related performance numerous uncertainties inherent estimating quantities proved reserves projecting future rates production projecting timing development expenditures including many factors beyond control reserve data represents estimates reservoir engineering subjective process estimating underground accumulations natural gas oil cannot measured exact manner accuracy reserve estimate function quality available data engineering geological interpretations judgment estimates proved reserves determined according rules prescribed sec rules indicate standard “reasonable certainty” applied proved reserve estimates concept reasonable certainty implies technical data becomes available positive upward revision likely negative downward revision estimates subject revision based upon number factors including reservoir performance prices economic conditions government restrictions addition results drilling testing production subsequent date estimate may justify revision estimate reserve estimates often different quantities natural gas oil ultimately recovered meaningfulness reserve estimates highly dependent accuracy assumptions based general volume production natural gas oil properties declines reserves depleted except extent conduct successful exploration development activities acquire additional properties containing proved reserves proved reserves decline reserves produced major discoveries events favorable adverse may considered caused significant change estimated proved reserves since december 31 2006 results operations results operations producing activities fiscal year follows december 31 millions 1 cost products services consists primarily transportation costs 2 production cost includes lease operating costs production related taxes including ad valorem severance taxes 3 acquired august 2005 standardized measure discounted future net cash flows standardized measure discounted future net cash flows relating consolidated proved natural gas oil reserves december 31 follows millions 1 united states excludes 219 million 502 million 1 million future net cash inflows outflows attributable hedging activities years 2006 2005 2004 brazil excludes 4 million 5 million future net cash outflows attributable hedging activities 2005 2004 2 four star acquired august 2005 calculations preceding table estimated future cash inflows estimated future production proved reserves computed using yearend prices 564 1008 622 per mmbtu natural gas 6105 6104 4335 per barrel oil december 31 2006 2005 2004 united states adjustments transportation charges net prices 533 per mcf gas 5108 per barrel oil 3436 per barrel ngl december 31 2006 may receive amounts different standardized measure discounted cash flow number reasons including price changes effects hedging activities changes standardized measure discounted future net cash flows following principal sources change consolidated worldwide standardized measure discounted future net cash flows millions 1 disclosure reflects changes standardized measure calculation excluding effects hedging activities schedule ii el paso corporation valuation qualifying accounts years ended december 31 2006 2005 2004 millions 1 amounts reflect reclassification discontinued operations 2 2006 relates primarily sale accounts receivable accounts receivable sales program 2005 2004 relates primarily accounts written 3 relates primarily valuation allowances deferred tax assets related western energy settlement foreign ceiling test charges foreign asset impairments state foreign net operating loss carryovers 4 relates primarily payments various litigation reserves including 442 million 602 million related western energy settlement environmental remediation reserves revenue crediting rate settlement reserves item 9item 8 financial statements supplementary data index items contained part ii item 8 financial statements supplementary data management’s annual report internal control financial reporting management responsible establishing maintaining adequate internal control financial reporting defined sec rules adopted securities exchange act 1934 amended internal control financial reporting designed provide reasonable assurance regarding reliability financial reporting preparation financial statements external purposes accordance generally accepted accounting principles consists policies procedures • pertain maintenance records reasonable detail accurately fairly reflect transactions dispositions assets • provide reasonable assurance transactions recorded necessary permit preparation financial statements accordance generally accepted accounting principles receipts expenditures made accordance authorizations management directors • provide reasonable assurance regarding prevention timely detection unauthorized acquisition use disposition assets could material effect financial statements supervision participation management including chief executive officer ceo chief financial officer cfo made assessment effectiveness internal control financial reporting december 31 2007 making assessment used criteria established internal control integrated framework issued committee sponsoring organizations treadway commission coso based evaluation concluded internal control financial reporting effective december 31 2007 effectiveness internal control financial reporting december 31 2007 audited ernst young llp independent registered public accounting firm stated report included herein report independent registered public accounting firm board directors stockholders el paso corporation audited accompanying consolidated balance sheets el paso corporation december 31 2007 2006 related consolidated statements income comprehensive income stockholders’ equity cash flows years ended audits also included financial statement schedule listed index item 15a years ended december 31 2007 2006 financial statements schedule responsibility company’s management responsibility express opinion financial statements schedule based audits financial statements citrus corp subsidiaries corporation company 50 interest december 31 2007 2006 four star oil gas company corporation company approximately 49 43 interest december 31 2007 2006 respectively audited auditors whose reports furnished us opinion consolidated financial statements insofar relates amounts included citrus corp subsidiaries four star oil gas company based solely reports auditors consolidated financial statements company’s combined investments companies represent approximately 3 total assets december 31 2007 2006 earnings investments represent approximately 23 24 income taxes continuing operations years ended based amounts audited auditors conducted audits accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements audit also includes assessing accounting principles used significant estimates made management well evaluating overall financial statement presentation believe audits reports auditors provide reasonable basis opinion based audits reports auditors financial statements referred present fairly material respects consolidated financial position el paso corporation december 31 2007 2006 consolidated results operations cash flows years ended conformity us generally accepted accounting principles also opinion related financial statement schedule considered relation basic financial statements taken whole presents fairly material respects information set forth therein discussed note 1 consolidated financial statements effective january 1 2007 company adopted provisions financial accounting standards board interpretation 48 accounting uncertainty income taxes interpretation fasb statement 109 effective december 31 2006 company adopted recognition provisions statement financial accounting standards 158 employers’ accounting defined benefit pension postretirement plans amendment fasb statements 87 88 106 132r effective january 1 2006 company adopted provisions statement financial accounting standards 123revised 2004 sharebased payment federal energy regulatory commission’s accounting release related pipeline assessment costs also audited accordance standards public company accounting oversight board united states el paso corporation’s internal control financial reporting december 31 2007 based criteria established internal controlintegrated framework issued committee sponsoring organizations treadway commission report dated february 25 2008 expressed unqualified opinion thereon houston texas february 25 2008 report independent registered public accounting firm internal control financial reporting board directors stockholders el paso corporation audited el paso corporation’s internal control financial reporting december 31 2007 based criteria established internal control integrated framework issued committee sponsoring organizations treadway commission coso criteria el paso corporation’s management responsible maintaining effective internal control financial reporting assessment effectiveness internal control financial reporting included accompanying management’s annual report internal control financial reporting responsibility express opinion company’s internal control financial reporting based audit conducted audit accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether effective internal control financial reporting maintained material respects audit included obtaining understanding internal control financial reporting assessing risk material weakness exists testing evaluating design operating effectiveness internal control based assessed risk performing procedures considered necessary circumstances believe audit provides reasonable basis opinion company’s internal control financial reporting process designed provide reasonable assurance regarding reliability financial reporting preparation financial statements external purposes accordance generally accepted accounting principles company’s internal control financial reporting includes policies procedures 1 pertain maintenance records reasonable detail accurately fairly reflect transactions dispositions assets company 2 provide reasonable assurance transactions recorded necessary permit preparation financial statements accordance generally accepted accounting principles receipts expenditures company made accordance authorizations management directors company 3 provide reasonable assurance regarding prevention timely detection unauthorized acquisition use disposition company’s assets could material effect financial statements inherent limitations internal control financial reporting may prevent detect misstatements also projections evaluation effectiveness future periods subject risk controls may become inadequate changes conditions degree compliance policies procedures may deteriorate opinion el paso corporation maintained material respects effective internal control financial reporting december 31 2007 based coso criteria also audited accordance standards public company accounting oversight board united states 2007 consolidated financial statements el paso corporation report dated february 25 2008 expressed unqualified opinion thereon houston texas february 25 2008 report independent registered public accounting firm board directors stockholders el paso corporation opinion consolidated statements income comprehensive income stockholders’ equity cash flows year ended december 31 2005 present fairly material respects results operations cash flows el paso corporation subsidiaries “company” year ended conformity accounting principles generally accepted united states america addition opinion financial statement schedule year ended december 31 2005 presents fairly material respects information set forth therein read conjunction related consolidated financial statements financial statements financial statement schedule responsibility company’s management responsibility express opinion financial statements financial statement schedule based audit conducted audit statements accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit financial statements includes examining test basis evidence supporting amounts disclosures financial statements assessing accounting principles used significant estimates made management evaluating overall financial statement presentation believe audit provides reasonable basis opinion discussed notes consolidated financial statements company adopted fasb interpretation 47 accounting conditional asset retirement obligations december 31 2005 pricewaterhousecoopers llp houston texas march 2 2006 except eleventh paragraph note 2 date may 10 2006 tenth paragraph note 2 date february 26 2007 report independent registered public accounting firm stockholders four star oil gas company opinion consolidated balance sheets related consolidated statements income stockholders’ equity cash flows presented separately herein present fairly material respects financial position four star oil gas company “company” subsidiary december 31 2007 2006 results operations cash flows three years period ended december 31 2007 conformity accounting principles generally accepted united states america financial statements responsibility company’s management responsibility express opinion financial statements based audits conducted audits statements accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements assessing accounting principles used significant estimates made management evaluating overall financial statement presentation believe audits provide reasonable basis opinion described notes 3 4 financial statements company significant transactions affiliated companies relationships possible terms transactions would result transactions among wholly unrelated parties pricewaterhousecoopers llp houston texas february 25 2008 report independent registered public accounting firm board directors stockholders citrus corp opinion consolidated balance sheets related consolidated statements income stockholders’ equity comprehensive income cash flows presented separately herein present fairly material respects financial position citrus corp subsidiaries “company” december 31 2007 2006 results operations cash flows three years period ended december 31 2007 conformity accounting principles generally accepted united states america consolidated financial statements responsibility company’s management responsibility express opinion financial statements based audits conducted audits statements accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements assessing accounting principles used significant estimates made management evaluating overall financial statement presentation believe audits provide reasonable basis opinion discussed notes 2 6 consolidated financial statements company adopted recognition disclosure provisions fasb statement 158 “employers’ accounting defined pension postretirement plans amendment fasb statements 87 88 106 132r” december 31 2006 pricewaterhousecoopers llp houston texas february 25 2008 el paso corporation consolidated statements income millions except per common share amounts see accompanying notes el paso corporation consolidated balance sheets millions except share amounts see accompanying notes el paso corporation consolidated balance sheets millions except share amounts see accompanying notes el paso corporation consolidated statements cash flows millions see accompanying notes el paso corporation consolidated statements stockholders’ equity millions except per share amounts see accompanying notes el paso corporation consolidated statements comprehensive income millions see accompanying notes el paso corporation notes consolidated financial statements 1 basis presentation significant accounting policies basis presentation principles consolidation consolidated financial statements prepared accordance us generally accepted accounting principles gaap include accounts majority owned controlled subsidiaries elimination significant intercompany accounts transactions financial statements prior periods include reclassifications made conform current year presentation reclassifications impact reported net income loss stockholders’ equity consolidate entities either ability control operating financial decisions policies entity ii allocated majority entity’s losses andor returns variable interests see note 17 entity determination ability control exert significant influence entity whether allocated majority entity’s losses andor returns involves use judgment apply equity method accounting exert significant influence control policies decisions entity allocated majority entity’s losses andor returns use cost method accounting unable exert significant influence entity use estimates preparation financial statements requires use estimates assumptions affect amounts report assets liabilities revenues expenses disclosures financial statements actual results often differ estimates regulated operations interstate natural gas pipelines storage operations subject jurisdiction ferc natural gas act 1938 natural gas policy act 1978 energy policy act 2005 pipelines follow regulatory accounting principles prescribed statement financial accounting standards sfas 71 accounting effects certain types regulation sfas 71 record regulatory assets liabilities would recorded gaap nonregulated entities regulatory assets liabilities represent probable future revenues expenses associated certain charges credits recovered refunded customers rate making process items apply regulatory accounting requirements include certain postretirement employee benefit plan costs equity return component regulated capital projects certain costs included expected included future rates cash equivalents consider shortterm investments original maturity less three months cash equivalents maintain cash deposit banks insurance companies pledged particular use restricted support potential liability classify balances restricted cash current noncurrent assets balance sheet based expect restrictions cash removed december 31 2007 7 million restricted cash current assets 91 million noncurrent assets december 31 2006 8 million restricted cash current assets 123 million noncurrent assets allowance doubtful accounts establish provisions losses accounts notes receivable natural gas imbalances due shippers operators determine collect part outstanding balance regularly review collectibility establish adjust allowance necessary using specific identification method inventory consists primarily supplies materials classified current balance sheet use average cost method account inventories value inventory lower cost market value property plant equipment pipelines excluding natural gas oil properties property plant equipment recorded original cost construction upon acquisition fair value assets acquired assets construct capitalize direct costs labor materials indirect costs overhead interest equity return component regulated businesses capitalize major units property replacements improvements expense minor items prior january 1 2006 capitalized certain costs interstate pipelines incurred related pipeline integrity programs part property plant equipment beginning january 1 2006 began expensing costs based ferc guidance years ended december 31 2007 2006 expensed approximately 18 million 19 million result adoption accounting release approximately 003 per basic fully diluted share 2007 002 per basic fully diluted share 2006 included pipeline property balances additional acquisition costs represent excess purchase costs associated purchase business combinations allocated regulated interstate systems’ property plant equipment costs amortized straightline basis recover excess costs rates retire property plant equipment regulated operations charge accumulated depreciation amortization original cost assets addition cost remove sell dispose assets less salvage value recognize gain loss unless sell entire operating unit include gains losses dispositions operating units operating income natural gas oil properties use full cost method account natural gas oil properties full cost method substantially costs incurred connection acquisition development exploration natural gas oil reserves capitalized countrybycountry basis capitalized amounts include costs unproved properties internal costs directly related acquisition development exploration activities asset retirement costs capitalized interest full cost method dry hole costs geological geophysical costs capitalized full cost pool subject amortization periodically assessed impairment ceiling test calculation discussed capitalized costs associated proved reserves amortized life reserves using unit production method conversely capitalized costs associated unproved properties excluded amortizable base properties evaluated occurs quarterly transfer unproved property costs amortizable base properties determined proved reserves addition areas natural gas oil reserve base exists transfer unproved property costs amortizable base unproved properties evaluated impaired exploratory dry holes determined unsuccessful additionally amortizable base includes future development costs dismantlement restoration abandonment costs net estimated salvage values geological geophysical costs incurred cannot associated specific unevaluated properties prospects direct interest capitalized costs net related income tax effects limited ceiling based present value future net revenues discounted 10 percent plus lower cost fair market value unproved properties net related income tax effects utilize endofperiod spot prices calculating future net revenues unless prices result ceiling test charge case evaluate price recoveries subsequent end period total capitalized costs exceed ceiling required writedown capitalized costs ceiling perform ceiling test calculation quarter required writedown included income statement ceiling test charge ceiling test calculations include effects derivative instruments designated qualify cash flow hedges anticipated future natural gas oil production ceiling test calculations exclude estimated future cash outflows associated asset retirement liabilities related proved developed reserves sell convey interests natural gas oil properties reduce natural gas oil reserves amount attributable sold conveyed interest recognize gain loss sales natural gas oil properties unless sales would significantly alter relationship capitalized costs proved reserves treat sales proceeds nonsignificant sales adjustment cost properties asset investment divestituresimpairments evaluate assets investments impairment events circumstances indicate carrying values may recovered events include market declines believed temporary changes manner intend use longlived asset decisions sell asset investment adverse changes legal business environment adverse actions regulators event occurs evaluate recoverability carrying value based either longlived asset’s ability generate future cash flows undiscounted basis ii fair value investment unconsolidated affiliate impairment indicated decide sell longlived asset group assets adjust carrying values asset downward necessary estimated fair value fair value estimates generally based market data obtained sales process analysis expected discounted cash flows magnitude impairment impacted number factors including nature assets sold established time frame completing sale among factors reclassify asset assets sold either heldforsale discontinued operations depending among criteria whether significant longterm continuing involvement assets sold cease depreciating assets period reclassified either held sale discontinued operations pension postretirement benefits maintain several pension postretirement benefit plans require us make contributions fund benefits paid plans contributions invested benefits paid plan participants record benefit expense related plans income statement benefit expense function many factors including benefits earned year plan participants function employee’s salary level benefits provided plan actuarial assumptions passage time expected returns plan assets amortization certain deferred gains losses discussion policies respect pension postretirement plans see note 13 pension postretirement benefit plans use recognition provisions sfas 158 employers’ accounting defined benefit pension postretirement plans amendment fasb statements 87 88 106 132r sfas 158 record asset liability pension postretirement benefit plans based overfunded underfunded status deferred amounts related unrealized gains losses changes actuarial assumptions recorded either regulatory asset liability regulated operations accumulated comprehensive income loss component stockholders’ equity nonregulated operations gains losses recognized income statement discussion application sfas 158 see note 13 revenue recognition business segments provide number services sell variety products record revenues products services include estimates amounts earned unbilled estimate unbilled revenues related services provided products delivered based contract data regulatory information commodity prices preliminary throughput allocation measurements among items revenue recognition policies significant operating segments follows pipelines revenues pipelines segment derives revenues primarily transportation storage services revenues services generally based thermal quantity gas delivered subscribed price specified contract transportation storage services recognize reservation revenues firm contracted capacity ratably contract period regardless amount natural gas transported stored interruptible volumetric based services record revenues physical deliveries natural gas made agreed upon delivery point gas injected withdrawn storage facility gas needed operations based volumes allowed retain relative amounts gas use operating purposes recognize revenue gas used operations retain volumes tariffs subject ferc regulations result revenues collect rate proceedings may subject refund establish reserves potential refunds exploration production revenues exploration production segment derives revenues primarily physical sale natural gas oil condensate ngl revenues sales products recorded upon delivery passage title using sales method net royalty interests profit interests produced product actual natural gas sales volumes exceed entitled share sales volumes overproduced imbalance occurs extent overproduced imbalance exceeds share remaining estimated proved natural gas reserves given property record liability costs associated transportation delivery production included cost products services marketing revenues marketing segment derives revenues physical natural gas power transactions management derivative contracts derivative transactions recorded fair value changes fair value reflected net operating revenues discussion income recognition policies derivatives see price risk management activities impact nonderivative transactions including transportation contracts recognized net operating revenues based contractual market price related volumes time commodity delivered contracts terminated environmental costs contingencies environmental costs record liabilities undiscounted amounts balance sheet current longterm liabilities environmental assessments indicate remediation efforts probable costs reasonably estimated estimates liabilities based currently available facts existing technology presently enacted laws regulations taking consideration likely effects societal economic factors include estimates associated legal costs amounts also consider prior experience remediating contaminated sites companies’ cleanup experience data released epa organizations estimates subject revision future periods based actual costs new circumstances capitalize costs benefit future periods recognize current period charge operation maintenance expense cleanup efforts benefit future periods evaluate amounts paid directly reimbursed government sponsored programs potential recoveries reimbursements remediation costs third parties including insurance coverage separately liability recovery evaluated based creditworthiness solvency third party among factors recovery assured record report asset separately associated liability balance sheet contingencies recognize liabilities contingencies exposure fully analyzed indicates probable liability incurred amount loss reasonably estimated likely outcome contingency reasonably estimated accrue liability amount likely outcome cannot estimated range potential losses established one amount range likely low end range accrued price risk management activities price risk management activities consist following activities • derivatives entered hedge otherwise reduce commodity exposure natural gas oil production interest rate foreign currency exposure longterm debt • derivatives intended hedge exposures including related legacy trading activities entered objective generating profits exposure shifts changes market prices derivatives reflected balance sheet fair value assets liabilities price risk management activities classify derivatives either current noncurrent assets liabilities based anticipated settlement date net derivative assets liabilities counterparties legal right offset see note 7 discussion price risk management activities 2007 adopted provisions fasb staff position fsp fin 391 offsetting amounts related certain contracts allowed companies option offset amounts recorded derivative contracts cash collateral posted held contracts executed counterparty master netting arrangement elected continue report separately amounts recorded derivative contracts cash collateral posted held balance sheet result adoption standard impact financial statements derivatives designated accounting hedges impact revenues expenses based nature timing transactions hedge derivatives designated hedges markedtomarket period changes fair value reflected revenues cash flow statement cash inflows outflows associated settlement derivative instruments recognized operating cash flows derivatives intended hedge principal amounts foreign currency denominated debt balance sheet receivables payables resulting settlement derivative instruments reported trade receivables payables income taxes record current income taxes based current taxable income provide deferred income taxes reflect estimated future tax payments receipts deferred taxes represent tax impacts differences financial statement tax bases assets liabilities carryovers year end account tax credits flowthrough method reduces provision income taxes year tax credits first become available reduce deferred tax assets valuation allowance based estimates likely portion assets realized future period estimates utilized recognition deferred tax assets subject revision either future periods based new facts circumstances effective january 1 2007 adopted provisions fin 48 accounting uncertainty income taxes fin 48 clarifies sfas 109 accounting income taxes requires us evaluate tax positions jurisdictions years statute limitations expired fin 48 requires companies meet “morelikelythannot” threshold ie greater 50 percent likelihood tax position sustained examination prior recording benefit tax positions additionally tax positions meeting “morelikelythannot” threshold amount benefit limited largest benefit greater 50 percent probability realized upon effective settlement recognize interest penalties related unrecognized tax benefits income tax expenses income statement discussion impact adoption fin 48 see note 4 foreign currency translation foreign operations whose functional currency local currency assets liabilities translated yearend exchange rates revenues expenses translated average exchange rates prevailing year cumulative effects translating local currency us dollar included separate component accumulated comprehensive income loss stockholders’ equity balance sheet accounting asset retirement obligations account asset retirement obligations accordance sfas 143 accounting asset retirement obligations financial accounting standards board fasb interpretation fin 47 accounting conditional asset retirement obligations record liability legal obligations associated replacement removal retirement longlived assets asset retirement liabilities recorded estimated fair value corresponding increase property plant equipment increase property plant equipment depreciated useful life longlived asset liability relates ongoing expense also recognized changes value liability result passage time record depreciation depletion amortization expense income statement regulated pipelines ability recover certain costs customers recorded asset rather expense associated depreciation property plant equipment accretion liabilities described accounting stockbased compensation january 1 2006 adopted sfas 123r sharebased payment prospectively awards stockbased compensation granted date unvested portion outstanding awards date measure employee stockbased compensation awards fair value date granted employees recognize compensation cost financial statements requisite service period prior january 1 2006 accounted stockbased compensation awards using intrinsic value method provisions accounting principles board apb opinion 25 accounting stock issued employees related interpretations record compensation expense stock options granted market value stock date grant additional information stockbased compensation awards see note 15 following table shows impact net loss available common stockholders loss per share applied provisions sfas 123 2005 millions except per share amounts new accounting pronouncements issued yet adopted december 31 2007 following accounting standards interpretations yet adopted us fair value measurements september 2006 fasb issued sfas 157 fair value measurements provides guidance measuring fair value assets liabilities financial statements adopt provisions standard financial assets liabilities effective january 1 2008 time required consider credit standing determination fair value liabilities adoption standard expected material impact financial statements fasb provided one year deferral adoption sfas 157 certain nonfinancial assets liabilities elected defer adoption certain nonfinancial assets liabilities currently evaluating impact deferred provisions standard financial statements measurement date pension postretirement benefits december 2006 adopted recognition provisions sfas 158 beginning 2008 standard also require us change measurement date pension postretirement benefit plans september 30 date currently use december 31 adoption measurement date provisions standard expected material impact financial statements fair value option february 2007 fasb issued sfas 159 fair value option financial assets financial liabilities including amendment fasb statement 115 accounting certain investments debt equity securities permits entities choose measure many financial instruments certain items fair value adopt provisions standard effective january 1 2008 anticipate material impact financial statements business combinations december 2007 fasb issued sfas 141r business combinations provides revised guidance accounting acquisitions businesses standard changes current guidance require acquired assets liabilities minority interest certain contingencies measured fair value certain acquisitionrelated costs expensed rather capitalized sfas 141r apply acquisitions effective december 31 2008 application standard acquisitions prior date permitted noncontrolling interests december 2007 fasb issued sfas 160 noncontrolling interests consolidated financial statements provides guidance presentation minority interest financial statements standard requires minority interest presented separate component equity rather “mezzanine” item liabilities equity also requires minority interest presented separate caption income statement standard also requires transactions minority interest holders including issuance repurchase minority interests accounted equity transactions unless change control subsidiary occurs sfas 160 effective fiscal years beginning december 15 2008 currently evaluating impact standard financial statements 2 acquisitions divestitures acquisitions peoples energy production company peoples september 2007 acquired peoples 887 million using cash hand borrowings revolving credit facilities peoples exploration production company natural gas oil properties located primarily arklatex texas gulf coast mississippi areas san juan arkoma basins accounted acquisition purchase method accounting allocated purchase price primarily natural gas oil properties balance sheet subject change based finalization allocation record goodwill associated transaction south texas properties january 2007 acquired operated natural gas oil producing properties undeveloped acreage south texas approximately 254 million medicine bow august 2005 completed acquisition medicine bow privately held energy company total cash consideration approximately 853 million part transaction also acquired four star unconsolidated affiliate medicine bow reflect proportionate share operating results earnings unconsolidated affiliates financial statements see note 17 2007 increased ownership four star 43 percent 49 percent gulf lng february 2008 closed previously announced acquisition 50 percent interest gulf lng clean energy project liquefied natural gas lng terminal currently construction pascagoula mississippi paid 294 million divestitures 2007 2006 2005 sold number assets investments business segments corporate activities table discussions summarize assets sold proceeds sales power assets sold 2006 consisted primarily interests mcv power plants brazil asia central america assets sold 2005 consisted primarily interests power contract restructuring entities power plants india korea field services assets sold 2005 consisted primarily investment enterprise javelina natural gas processing pipeline assets exploration production marketing pipelines corporate assets sold consisted primarily investment nymex stagecoach pipeline lateral 2007 natural gas oil properties south texas 2006 pipeline facilities gathering systems located southeastern western us lakeside technology center 2005 discontinued operations assets held sale sfas 144 accounting impairment disposal longlived assets classify assets disposed held sale appropriate discontinued operations received appropriate approvals disposed management board directors meet criteria cash flows discontinued businesses reflected discontinued operating investing financing activities statement cash flows extent operations maintain separate cash balances reflect net cash flows generated businesses contribution continuing operations cash continuing financing activities following description discontinued operations summarized results operations periods ended december 31 2007 2006 2005 also 28 million assets held sale december 31 2006 december 31 2007 assets liabilities related discontinued operations assets held sale sold anr related operations february 2007 sold anr michigan storage assets 50 percent interest great lakes gas transmission approximately 37 billion recorded gain sale 648 million net taxes 354 million included net assets discontinued operations date sale net deferred tax liabilities assumed purchaser also recorded approximately 188 million deferred taxes 2006 conjunction sale international power operations 2006 completed sale discontinued international power operations including macae wholly owned power plant facility brazil asian central american power assets total net proceeds approximately 368 million previously 2005 recognized approximately 499 million impairments net minority interest based upon indications value would receive upon sale assets south louisiana gathering processing operations 2005 completed sale south louisiana gathering processing assets net proceeds approximately 486 million recorded pretax gain approximately 394 million assets part historical field services segment prior 2005 canadian certain international natural gas oil production operations petroleum markets businesses operations approved sale completed sale substantially properties 2004 2005 income taxes discontinued operations years ended december 31 2007 2006 2005 incurred income tax expense associated discontinued operations 369 million 274 million 179 million resulting effective tax rate approximately 35 126 216 years effective tax rates 2006 2005 significantly higher statutory rate 35 primarily due following items • 2006 recorded approximately 188 million deferred taxes upon agreeing sell stock anr michigan storage assets 50 percent interest great lakes gas transmission prior decision sell recorded deferred taxes individual assetsliabilities portion investment stock one companies • 2005 impairments operating losses certain foreign investments tax benefit available ii receipt dividends foreign subsidiaries taxable us iii state income taxes summarized operating results financial position data discontinued operations follows 1 includes loss approximately 19 million associated extinguishment certain debt obligations 3 income expenses following components income expenses continuing operations three years ended december 31 4 income taxes pretax income loss income tax expense benefit tables show pretax income loss continuing operations components income tax expense benefit years ended december 31 effective tax rate reconciliation income taxes included income loss continuing operations differs amount computed applying statutory federal income tax rate 35 percent following reasons three years ended december 31 2006 2005 overall effective tax rate continuing operations significantly different statutory rate due primarily conclusion irs audits 2006 audit settlements primarily relate conclusion audits coastal corporation’s 19982000 tax years el paso’s 2001 2002 tax years resulted reduction tax contingencies reinstatement certain tax credits 2005 audit settlements primarily relate conclusion coastal corporation’s irs tax audits years prior 1998 deferred tax assets liabilities following components net deferred tax liability related continuing operations december 31 expect receive sales proceeds within us asia central america power assets recorded us deferred tax assets liabilities book versus tax basis differences assets december 31 2007 2006 us deferred tax assets 12 million 45 million us deferred tax liabilities 1 million 2 million related investments cumulative undistributed earnings substantially remainder foreign subsidiaries foreign corporate joint ventures excluding power assets discussed intended indefinitely reinvested foreign operations therefore provision made us taxes foreign withholding taxes may applicable upon actual deemed repatriation estimate taxes earnings repatriated practical december 31 2007 portion cumulative undistributed earnings investments recorded us income taxes approximately 117 million reasons recorded provision us income taxes foreign currency translation adjustments recorded accumulated comprehensive income unrecognized tax benefits liabilities uncertain tax matters fin 48 file income tax returns us federal jurisdiction various states foreign jurisdictions exceptions longer subject us federal state local nonus income tax examinations tax authorities years 1999 additionally internal revenue service completed examination el paso’s u income tax returns 2003 2004 tentative settlement appellate level issues settlement matters expected change unrecognized tax benefits next twelve months anticipate impact significant results operations financial condition liquidity remaining open tax years unrecognized tax benefits liabilities uncertain tax matters could increase decrease income tax expense effective income tax rates matters finalized although currently unable estimate range potential impacts matters could financial statements upon adoption fin 48 recorded additional liabilities unrecognized tax benefits 2 million including interest penalties accounted increase 4 million january 1 2007 accumulated deficit increase 2 million additional paidin capital following table shows change unrecognized tax benefits january 1 2007 december 31 2007 december 31 2007 approximately 132 million net federal tax benefits unrecognized tax benefits would affect income tax expense effective income tax rate recognized future periods amount unrecognized tax benefits could change next twelve months expect change significant impact results operations financial position year ended december 31 2007 recognized 6 million interest penalties 45 million accrued payment interest penalties december 31 2007 tax credit nol carryovers december 31 2007 us federal alternative minimum tax credits 344 million carryover indefinitely table presents details federal state net operating loss carryover periods december 31 2007 also 240 million foreign net operating loss carryovers 68 million foreign capital loss carryovers carryover indefinitely usage us federal carryovers subject limitations provided sections 382 383 internal revenue code well separate return limitation year rules irs regulations valuation allowances deferred tax assets recorded net operating losses temporary differences book tax basis assets liabilities expected produce tax deductions future periods realization assets depends recognition sufficient future taxable income specific tax jurisdictions periods temporary differences net operating losses deductible assessing need valuation allowance deferred tax assets consider whether likely portion realized part assessment consider future reversals existing taxable temporary differences primarily related depreciation believe likely realize benefit deferred tax assets net existing valuation allowances 5 earnings per share calculated basic diluted earnings per common share follows three years ended december 31 exclude potentially dilutive securities determination diluted earnings per share well related income statement impacts impact income continuing operations per common share antidilutive potentially dilutive securities consist employee stock options restricted stock convertible preferred stock trust preferred securities zero coupon convertible debentures paid april 2006 year ended december 31 2007 2006 certain employee stock options trust preferred securities antidilutive additionally 2006 zero coupon convertible debentures redeemed april 2006 antidilutive 2007 convertible preferred stock antidilutive year ended december 31 2005 incurred losses continuing operations accordingly excluded potentially dilutive securities determination diluted earnings per share impact loss per common share antidilutive discussion capital stock activity stockbased compensation arrangements instruments noted see notes 14 15 6 fair value financial instruments december 31 2007 2006 carrying amounts cash equivalents shortterm borrowings trade receivables payables represented fair value shortterm nature instruments fair value longterm debt variable interest rates approximates carrying value marketbased nature interest rate estimated fair value debt fixed interest rates based quoted market prices similar issues see note 7 discussion methodology determining fair value derivative instruments used price risk management activities investments primarily relate available sale securities cost basis investments 7 price risk management activities following table summarizes carrying value derivatives used price risk management activities december 31 2007 2006 table derivatives designated hedges consist instruments used hedge natural gas oil production commoditybased derivative contracts relate derivative contracts designated hedges options swaps natural gas power purchase supply contracts derivatives historical energy trading activities finally interest rate foreign currency derivatives consist swaps primarily designated hedges interest rate foreign currency risk longterm debt 1 included current noncurrent assets liabilities balance sheet derivative contracts recorded financial statements fair value best indication fair value quoted market prices however quoted market prices available estimate fair value derivatives use commodity pricing data either obtained derived independent pricing source assumptions certain power natural gas markets develop price curves used estimate value settlements future periods based contractual settlement quantities dates finally discount estimated settlement values using libor curve record valuation adjustments reflect uncertainties associated estimates use determining fair value common valuation adjustments include market liquidity creditworthiness contractual counterparties believe methodology results fair value representative proceeds would receive disposed derivative instruments estimates utilized determining fair value derivatives subject revisions either future periods based changes market conditions 2006 changed independent pricing source provided pricing data used valuing certain commoditybased derivative contracts changes material impact fair value positions derivatives designated hedges engage two types hedging activities hedges cash flow exposure hedges fair value exposure enter derivative contract may designate derivative either cash flow hedge fair value hedge time prepare documentation required sfas 133 hedges cash flow exposure primarily relate natural gas oil production hedges interest rate risks longterm debt designed hedge forecasted sales transactions limit variability cash flows received paid related recognized asset liability hedges fair value exposure entered protect fair value recognized asset liability firm commitment hedges interest rate foreign currency exposure designated either cash flow hedges fair value hedges based whether interest underlying debt converted either fixed floating interest rate changes derivative fair values designated cash flow hedges deferred accumulated comprehensive income loss extent effective recognized earnings hedged transactions occur changes fair value derivatives designated fair value hedges recognized earnings offsets changes fair values related hedged assets liabilities firm commitments ineffective portion hedge’s change fair value recognized immediately earnings component operating revenues interest debt expense income statement discussion hedging activities follows cash flow hedges majority commodity sales purchases spot market forward market prices use fixed price swaps floor ceiling option contracts limit exposure decreases commodity prices well fluctuations foreign currency interest rates objective limiting variability cash flows activities summary impacts cash flow hedges included accumulated comprehensive income loss net income taxes december 31 2007 2006 follows 1 reclassifications occur upon physical delivery hedged commodity forecasted transaction longer probable years ended december 31 2007 2006 2005 recognized net loss 3 million net gain 10 million net loss 5 million net income taxes respectively income loss continuing operations related ineffective portion cash flow hedges fair value hedges fixed rate us dollar foreign currency denominated debt exposes us paying higher market rates interest rates decline use interest rate swaps protect value debt instruments converting fixed amounts interest due debt agreements variable interest payments recorded fair value derivatives component longterm debt related accrued interest december 31 2007 2006 derivatives follows amounts millions commoditybased derivatives commoditybased derivatives primarily relate derivative contracts designated hedges contracts associated legacy trading activities credit risk subject credit risk related financial instrument assets credit risk relates risk loss would incur result nonperformance counterparties pursuant terms contractual obligations measure credit risk estimated replacement costs commodities would purchase sell future plus amounts owed counterparties delivered unpaid commodities exposures netted legally enforceable right setoff maintain credit policies regard counterparties price risk management activities minimize overall credit risk policies require evaluation potential counterparties’ financial condition including credit rating ii collateral certain circumstances including cash advance letters credit guarantees iii use margining provisions standard contracts iv use master netting agreements allow netting positive negative exposures various contracts associated single counterparty use daily margining provisions financial contracts physical power agreements master netting agreements require counterparty post cash letters credit fair value contract exceeds daily contractual threshold amount typically tied published credit rating counterparty margining collateral provisions also allow us terminate contract liquidate positions counterparty unable provide required collateral margining provisions required return collateral amount posted collateral exceeds amount collateral required collateral received returned vary significantly day based changes market values counterparty’s credit ratings furthermore amount collateral hold may less fair value derivative contracts counterparty given period following table presents summary fair value derivative contracts net collateral liabilities right offset exists presented type derivative counterparty net asset exposure december 31 2007 2006 1 “investment grade” “below investment grade” determined using publicly available credit ratings “investment grade” includes counterparties minimum standard poor’s rating bbb moody’s rating baa3 “below investment grade” includes counterparties public credit rating meet criteria “investment grade” “not rated” includes counterparties rated public rating service approximately 48 counterparties december 31 2007 one counterparties fails perform may recognize immediate loss earnings well additional financial impacts future delivery periods extent replacement contract prices quantities cannot established december 31 2007 four counterparties merrill lynch commodities morgan stanley group central lomas de real constellation energy commodities group inc comprise 20 percent 16 percent 15 percent 12 percent respectively net financial asset exposure december 31 2006 three counterparties deutsche bank ag j aron company constellation energy commodities group inc comprised 39 percent 18 percent 16 percent net financial instrument asset exposure concentration counterparties may impact overall exposure credit risk either positively negatively counterparties may similarly affected changes economic regulatory conditions 8 regulatory assets liabilities regulatory assets liabilities relate interstate pipeline operations included current noncurrent assets liabilities balance sheets balances recoverable reimbursable various periods details regulatory assets liabilities december 31 9 assets liabilities detail current noncurrent assets liabilities balance sheets december 31 10 property plant equipment depreciable lives table presents depreciation method depreciable lives property plant equipment 1 composite group method assets similar useful lives characteristics grouped depreciated one asset apply depreciation rate approved rate settlements total cost group net book value equals salvage value reevaluate depreciation rates time redevelop transportation rates file ferc increase decrease rates 2 capitalized costs associated proved reserves amortized life reserves using unit production method conversely capitalized costs associated unproved properties excluded amortizable base properties evaluated see note 1 additional information excess purchase costs december 31 2007 2006 tgp epng excess purchase costs associated historical acquisition total excess costs pipelines approximately 25 billion accumulated depreciation approximately 04 billion december 31 2007 2006 excess costs depreciated life pipeline assets costs assigned related depreciation expense year ended december 31 2007 2006 2005 approximately 42 million currently earn return excess purchase costs rate payers capitalized costs construction capitalize carrying cost funds related construction longlived assets reflect increases cost asset balance sheet carrying cost consists interest cost debt could attributed assets constructed ii regulated transmission business return equity could attributed assets constructed debt portion calculated based average cost debt interest costs capitalized included reduction interest expense income statements 50 million 41 million 41 million years ended december 31 2007 2006 2005 equity portion calculated using recent ferc approved equity rate return equity amounts capitalized included nonoperating income statement 32 million 20 million 23 million years ended december 31 2007 2006 2005 construction workin progress december 31 2007 2006 approximately 16 billion 1 billion construction workinprogress included property plant equipment asset retirement obligations legal obligations associated retirement natural gas oil wells related infrastructure natural gas pipelines transmission facilities storage wells obligations related corporate headquarters building production operations obligations plug wells abandoned production exhausted longer plan use wells pipeline operations legal obligations primarily involve purging sealing pipelines abandoned also obligations remove hazardous materials associated natural gas transmission facilities corporate headquarters facilities ever demolished replaced renovated continue evaluate asset retirement obligations future developments could impact amounts record reasonably estimate asset retirement obligation liability accrue liability based estimate timing amount settlement estimating fair value liabilities associated asset retirement obligations utilize several assumptions including projected inflation rate 25 percent creditadjusted discount rates currently range six eight percent record changes estimates based expected amount timing payments settle asset retirement obligations typically changes result obtaining new information exploration production segment timing obligations plug natural gas oil wells costs 2006 also revised estimates due primarily impacts hurricanes katrina rita pipelines operations intend operating maintaining natural gas pipeline storage systems long supply demand natural gas exists expect foreseeable future therefore believe cannot reasonably estimate asset retirement obligation liability substantial majority natural gas pipeline storage system assets indeterminate lives net asset retirement liability december 31 reported balance sheet current noncurrent liabilities changes net liability years ended december 31 follows 11 debt financing obligations credit facilities following provides additional detail longterm financing obligations changes longterm financing obligations 2007 following changes longterm financing obligations 2007 recorded 291 million pretax losses extinguishment certain debt obligations repurchased debt refinanced prior redemption 2006 recorded accretion expense zero coupon debentures increased principal balance longterm debt period 2006 2005 accretion recorded interest expense 4 million 25 million 2006 2005 redeemed 615 million 236 million zero coupon convertible debentures 110 million 34 million represented increased principal due accretion interest debentures account redemptions financing activities statement cash flows debt maturities aggregate maturities principal amounts longterm financing obligations next 5 years total thereafter follows millions credit facilitiesletters credit december 31 2007 subject terms various agreements available capacity credit agreements approximately 10 billion exclusive capacity el paso pipeline partners lp eppp facility discussed description existing credit facilities december 31 2007 15 billion revolving credit agreement november 2007 restructured 175 billion credit agreement eliminate 05 billion deposit letter credit facility increase revolving credit facility 125 billion 15 billion el paso certain subsidiaries guaranteed 15 billion revolving credit agreement collateralized stock ownership epng tgp also eligible borrowers 15 billion revolving credit agreement 15 billion revolving credit facility matures november 2012 borrow funds libor plus 125 based current applicable margin issue letters credit 1375 amount issued pay annual commitment fee 025 based current applicable margin unused capacity revolving credit facility credit agreement applicable margin used calculate interest borrowings letters credit commitment fees determined variable pricing grid tied credit ratings senior secured debt december 31 2007 approximately 03 billion letters credit issued 04 billion debt outstanding facility unsecured revolving credit facility 500 million unsecured revolving credit facility matures july 2011 third party third party trust provides borrowings issuing letters credit required pay fixed facility fees rate 234 total committed amount facility addition pay interest borrowings rate comprised either libor base rate substantially capacity facility used issue letters credit unsecured credit facility june 2007 entered 150 million unsecured facility provides borrowings issuing letters credit december 31 2007 increased capacity facility 500 million facility matures various tranches 2009 based facility size required pay fixed facility fee weighted average rate 158 per annum full facility amount borrowings carry interest rate libor addition facility fee substantially capacity facility used issue letters credit epep 10 billion revolving credit agreement september 2007 amended restated epep’s revolving credit facility increasing capacity 05 billion 10 billion material terms conditions facility remain december 31 2007 08 billion outstanding facility based current borrowing levels pay interest libor plus 125 borrowings commitment fee 030 unused capacity facility collateralized certain natural gas oil properties subject revaluation semiannual basis december 31 2007 recent determination sufficient fully support facility contingent letter credit facility 250 million unsecured contingent letter credit facility matures march 2008 letters credit available us facility average nymex gas price strip remaining calendar months march 2008 equal exceeds 1175 per mmbtu facility fee triggered 166 per annum el paso pipeline partners lp revolving credit facility november 2007 eppp wic subsidiary entered unsecured 5year revolving credit facility initial aggregate borrowing capacity 750 million expandable 125 billion certain expansion projects acquisitions facility available eppp subsidiaries borrowings guaranteed eppp subsidiaries amounts borrowed nonrecourse el paso approximately 455 million outstanding credit facility december 31 2007 credit facility two pricing grids one based credit ratings based leverage currently leverage pricing grid effect eppp’s cost borrowings libor plus 0525 based eppp’s current leverage eppp also pays 0125 annual commitment fee facility letters credit enter letters credit ordinary course operating activities well periodically conjunction sales assets businesses december 31 2007 outstanding letters credit approximately 13 billion included amount 10 billion letters credit securing recorded obligations related price risk management activities restrictive covenants 15 billion revolving credit agreement covenants 15 billion revolving credit facility include restrictions debt levels restrictions liens securing debt guarantees restrictions mergers sales assets dividend restrictions cross default crossacceleration breach covenants could result acceleration debt financial obligations subsidiaries credit agreement restrictive debt covenants cross default provisions ratio debt consolidated ebitda defined credit agreement shall exceed 55 1 anytime prior june 30 2008 thereafter shall exceed 525 1 maturity b ratio consolidated ebitda defined credit agreement interest expense plus dividends paid shall less 175 1 anytime prior june 30 2008 thereafter shall less 200 1 maturity c epng tgp cannot incur incremental debt incurrence incremental debt would cause debt consolidated ebitda ratio defined credit agreement particular company exceed 50 1 occurrence event default expiration applicable grace period respect debt aggregate principal amount 200 million epep 10 billion revolving credit agreement epep’s borrowings facility subject various conditions financial coverage ratio facility requires epep’s ebitda defined facility interest expense less 20 1 epep’s debt ebitda defined credit agreement must exceed 40 1 eppp revolving credit facility eppp’s borrowings credit facility contains covenants provisions restrictive requires eppp maintain end fiscal quarter consolidated leverage ratio consolidated indebtedness consolidated ebitda defined credit facility less 50 10 four consecutive quarters 55 10 three consecutive quarters subsequent consummation specified permitted acquisitions value greater 25 million eppp also added additional flexibility covenants growth projects case capital construction expansion project excess 20 million adjustments consolidated ebitda approved lenders may made based percentage capital costs expended projected cash flows project adjustments shall limited 25 actual ebitda restrictions provisions addition restrictions provisions andor subsidiaries subject number additional restrictions covenants restrictions covenants include limitations additional debt subsidiaries limitations use proceeds borrowing subsidiaries limitations cases transactions affiliates limitations occurrence liens potential limitations ability subsidiaries declare pay dividends potential limitations subsidiaries participate cash management program restrictive acceleration provision 10 million associated indenture one subsidiaries indenture states event default occur resulting acceleration debt obligations excess 10 million longterm debt obligation containing provision could accelerated acceleration debt would adversely affect liquidity position turn financial condition also issued various guarantees securing financial obligations subsidiaries affiliates similar covenants facilities financing arrangements capital trusts el paso energy capital trust wholly owned business trust formed march 1998 issued 65 million 475 percent trust convertible preferred securities 325 million trust exists sole purpose issuing preferred securities investing proceeds 475 percent convertible subordinated debentures issued due 2028 trust i’s sole source income interest earned debentures interest income used pay distributions preferred securities also two wholly owned business trusts el paso energy capital trust ii iii trust ii iii issued securities provide full unconditional guarantee trust i’s preferred securities would provide guarantee securities issued trust ii iii trust i’s preferred securities nonvoting except limited circumstances pay quarterly distributions annual rate 475 percent carry liquidation value 50 per security plus accrued unpaid distributions convertible common shares time prior close business march 31 2028 option holder rate 12022 common shares trust preferred security equivalent conversion price 4159 per common share classified securities longterm debt right redeem securities time nonrecourse project financings several subsidiaries investments debt obligations related costs construction acquisition project financing debt recourse project company assets ie without recourse el paso december 31 2007 two international power projects accounted equity investments default debt agreements however material exposure result defaults 12 commitments contingencies legal proceedings erisa class action suit december 2002 purported class action lawsuit entitled william h lewis iii v el paso corporation et al filed us district court southern district texas alleging communication participants retirement savings plan included various misrepresentations omissions caused members class hold maintain investments el paso stock violation employee retirement income security act erisa various motions filed awaiting court’s ruling insurance coverage lawsuit subject certain deductibles copay obligations established accruals matter believe adequate cash balance plan lawsuit december 2004 purported class action lawsuit entitled tomlinson et al v el paso corporation el paso corporation pension plan filed us district court denver colorado lawsuit alleges various violations erisa age discrimination employment act result change final average earnings formula pension plan cash balance pension plan certain claims cash balance plan violated erisa recently dismissed trial court costs legal exposure related lawsuit currently determinable shareholder litigation 2007 settled twentyeight shareholder class action lawsuits alleged violations federal securities laws us several current former officers directors settlement contributed approximately 48 million insurers contributed approximately 225 million third party contributed 12 million retiree medical benefits matters serve plan administrator medical benefits plan covers closed group retirees case corporation retired july 1 1994 case formerly subsidiary tenneco inc spun 1994 tenneco retained obligation provide certain medical benefits time spinoff assumed obligation result merger tenneco pursuant agreement applicable union case employees liability benefits subject cap costs excess cap assumed plan participants 2002 case sued individual retirees federal court detroit michigan action entitled yolton et al v el paso tennessee pipeline co case corporation suit alleges among things el paso case violated erisa required pay amounts cap case filed claims el paso asserting el paso obligated indemnify case amounts would required pay separate rulings 2004 court ruled pending trial merits case must pay amounts incurred cap el paso must reimburse case payments january 2006 rulings upheld appeal us court appeals 6th circuit october 2007 pending trial merits court expanded number retirees covered prior preliminary rulings proceed trial merits regard issues whether cap enforceable degree benefits actually vested resolved el paso indemnify case payments case makes cap currently 2 million per month continue defend action filed approval trial court various amendments medical benefit plans would allow us deliver benefits plan participants cost effective manner although uncertain plan amendments ultimately approved approval plan amendments could reduce overall costs result could reduce recorded obligation established accrual matter believe adequate discussed guarantees indemnifications natural gas commodities litigation beginning august 2003 several lawsuits filed el paso marketing lp epm alleging el paso epm energy companies conspired manipulate price natural gas providing false price information industry trade publications published gas indices first cases consolidated federal court new york pretrial purposes styled gas commodity litigation september 2005 court certified class include persons purchased sold nymex natural gas futures january 1 2000 december 31 2002 settlement finalized paid second set cases involving similar allegations behalf commercial residential customers transferred multidistrict litigation proceeding mdl us district court nevada styled western states wholesale natural gas antitrust litigation cases dismissed us court appeals ninth circuit however reversed dismissal ordered cases remanded trial court petition certiorari filed us supreme court third set cases also involve similar allegations behalf certain purchasers natural gas include farmland industries v oneok inc et al filed state court wyandotte county kansas july 2005 missouri public service commission v el paso corporation et al filed circuit court jackson county missouri kansas city october 2006 purported class action lawsuits styled leggett et al v duke energy corporation et al filed chancery court tennessee january 2005 everbloom inc et al v aep energy services inc et al filed federal court eastern district california september 2005 learjet inc et al v oneok inc et al filed state court wyandotte county kansas september 2005 breckenridge et al v oneok inc et al filed state court denver county colorado may 2006 arandell et al v xcel energy et al filed circuit court dane county wisconsin december 2006 heartland et al v oneok inc et al filed circuit court buchanan county missouri march 2007 leggett case dismissed tennessee state court appealed remaining cases transferred mdl proceeding missouri public service case remanded state court dispositive motions filed anticipated filed cases costs legal exposure related lawsuits claims currently determinable gas measurement cases number subsidiaries named defendants actions generally allege mismeasurement natural gas volumes andor heating content resulting underpayment royalties first set cases filed 1997 individual false claims act consolidated pretrial purposes natural gas royalties qui tam litigation us district court district wyoming complaints allege industrywide conspiracy underreport heating value well volumes natural gas produced federal native american lands october 2006 us district judge issued order dismissing claims defendants appeal filed similar allegations filed set actions initiated 1999 price et al v gas pipelines predecessors et al district court stevens county kansas plaintiffs currently seek certification class royalty owners wells nonfederal nonnative american lands kansas wyoming colorado motions class certification briefed argued proceedings parties awaiting court’s ruling plaintiff seeks unspecified amount monetary damages form additional royalty payments along interest expenses punitive damages injunctive relief regard future gas measurement practices costs legal exposure related lawsuits claim currently determinable mtbe certain subsidiaries used gasoline additive methyl tertiarybutyl ether mtbe gasoline certain subsidiaries also produced bought sold distributed mtbe number lawsuits filed throughout us regarding potential impact mtbe water supplies subsidiaries among defendants approximately 80 lawsuits plaintiffs certain state attorneys general various water districts limited number individual water customers generally seek remediation groundwater prevention future contamination damages including natural resource damages punitive damages attorney’s fees court costs among allegations plaintiffs assert gasoline containing mtbe defective product defendant refiners liable proportion market share although suits consolidated pretrial purposes multidistrict litigation us district court southern district new york recent appellate court decision directed two cases remanded back state court limited number cases since remanded separate state court proceedings possible many cases also remanded reached agreement principle plaintiffs settle approximately 60 lawsuits also reached agreement principle insurers whereby insurers would fund substantially consideration provided subsidiaries terms settlement plaintiffs approximately 20 remaining lawsuits covered terms settlement damages claimed remaining actions substantial remains significant legal uncertainty regarding validity causes action asserted availability relief sought plaintiffs tendered remaining cases insurers costs legal exposure related remaining lawsuits currently determinable government investigations inquiries reserve revisions march 2004 received subpoena sec requesting documents relating december 31 2003 natural gas oil reserve revisions continue cooperate sec investigation related reserve revisions originally selfreported matter sec cooperating fully investigation included producing large volume documents making employees available interviews testimony upon request july 13 2007 received notice indicating sec staff made preliminary decision recommend sec institute enforcement action us two subsidiaries related reserve revisions understand staff sec may also issued similar notices several former employees related reserves revisions given opportunity respond staff makes formal recommendation whether action brought sec september 25 2007 submitted response legacy crude oil trading 2007 recorded 77 million income statement related reversal amounts accrued prior 2001 relating shipments crude oil allegedly purchased coastal 1990 reversed amounts following expiration related statute limitation periods completion review matter related defenses addition proceedings subsidiaries affiliates named defendants numerous lawsuits governmental proceedings arise ordinary course business also regulatory rules orders various stages adoption review andor implementation matters evaluate merits case exposure matter possible legal settlement strategies likelihood unfavorable outcome determine unfavorable outcome probable estimated establish necessary accruals outcome matters including discussed cannot predicted certainty still uncertainties related costs may incur based upon evaluation experience date believe established appropriate reserves matters possible however new information future developments could require us reassess potential exposure related matters adjust accruals accordingly adjustments could material december 31 2007 approximately 460 million accrued net related insurance receivables outstanding legal governmental proceedings rates regulatory matters notice inquiry pipeline fuel retention policies september 2007 ferc issued notice inquiry regarding policy inkind recovery fuel lost unaccounted gas natural gas pipeline companies current policy pipelines options recovering costs pipelines tariff states fixed percentage nonnegotiable feeinkind retained volumes tendered shipment shipper also tracker approach pipeline’s tariff provides prospective adjustments fuel retention rates timetotime include mechanism allow pipeline reconcile past underrecoveries fuel finally pipelines’ tariffs provide tracker trueup approach provisions pipeline’s tariff allow periodic adjustments fuel retention rates also provide trueup past underrecoveries fuel lost unaccounted gas proceeding ferc seeking comments whether change current policy prescribe uniform method pipelines use recovering costs pipeline subsidiaries currently utilize variety methodologies time know impact proceeding may ultimately us notice proposed rulemaking october 3 2007 minerals management service mms issued notice proposed rulemaking “oil gas sulphur operations outer continental shelf pipelines pipeline rightsofway” adopted proposed rules would substantially revise mms outer continental shelf ocs pipeline rightsofway row regulations proposed rules would effect 1 increasing financial obligations entities like us pipelines pipeline rightsofway ocs 2 increasing regulatory requirements imposed operation maintenance existing pipelines ocs 3 increasing requirements preconditions obtaining new rightsofway ocs epng august 2007 epng received approval settlement rate case ferc settlement provides benefits epng customers three year period ending december 31 2008 terms settlement epng required file new rate case effective january 1 2009 epng received approval ferc begin billing settlement rates october 1 2007 financial statements reflect epng’s settled rates additionally 2007 2006 recorded rate refund provisions approximately 60 million 65 million inclusive interest reflected accrued liabilities balance sheet fourth quarter 2007 epng refunded 115 million including interest rate refunds customers refunded remaining 10 million january 2008 contingencies navajo nation approximately 900 looped pipeline miles north mainline epng pipeline system located lands held trust united states benefit navajo nation rightsofway lands crossing navajo nation subject pending renewal application filed 2005 department interior’s bureau indian affairs interim agreement navajo nation expired end december 2006 negotiations terms longterm agreement continuing addition continue preserve legal regulatory legislative alternatives include continuing pursue application department interior renewal rightsofway navajo nation lands uncertain whether negotiation alternatives successful ultimate cost obtaining rightsofway whether able recover costs epng’s rates environmental matters subject federal state local laws regulations governing environmental quality pollution control laws regulations require us remove remedy effect environment disposal release specified substances current former operating sites december 31 2007 accrued approximately 260 million reduced 27 million amounts paid directly government sponsored programs accrual includes approximately 251 million expected remediation costs associated onsite offsite groundwater technical studies approximately 9 million related environmental legal costs 260 million accrual 22 million reserved facilities currently operate 238 million reserved nonoperating sites facilities shut sold superfund sites estimates potential liability range approximately 260 million approximately 470 million accrual represents combination two estimation methodologies first likely outcome reasonably estimated cost accrued 18 million second likely outcome cannot estimated range costs established 242 million 452 million one amount range likely lower end expected range accrued environmental remediation projects various stages completion recorded liabilities reflect current estimates amounts expend remediate sites however depending stage completion assessment ultimate extent contamination remediation required may known additional assessments occur remediation efforts continue may incur additional liabilities type site reserves based following estimates reasonably possible outcomes reconciliation accrued liability january 1 2007 december 31 2007 millions 2008 estimate total remediation expenditures approximately 65 million expended government directed cleanup plans addition expect make capital expenditures environmental matters approximately 7 million aggregate years 2008 2011 expenditures primarily relate compliance clean air regulations cercla matters received notice could designated asked information determine whether could designated potentially responsible party prp respect 44 active sites comprehensive response compensation liability act cercla state equivalents sought resolve liability prp sites indemnification third parties settlements provide payment allocable share remediation costs december 31 2007 estimated share remediation costs sites 27 million 49 million cleanup costs estimates subject revision information becomes available extent remediation required cases asserted defense liability estimates could change moreover liability federal cercla statute joint several meaning could required pay excess pro rata share remediation costs understanding financial strength prps considered appropriate estimating liabilities accruals issues included previously indicated estimates superfund sites possible new information future developments could require us reassess potential exposure related environmental matters may incur significant costs liabilities order comply existing environmental laws regulations also possible developments increasingly strict environmental laws regulations orders regulatory agencies well claims damages property environment injuries employees persons resulting current past operations could result substantial costs liabilities future information becomes available relevant developments occur adjust accrual amounts accordingly still uncertainties related ultimate costs may incur based upon evaluation experience date believe reserves adequate commitments purchase obligations matters operating leases maintain operating leases ordinary course business activities leases include office space operating facilities equipment terms agreements vary 2008 2053 minimum annual rental commitments operating leases december 31 2007 follows 1 amounts reduced minimum sublease rentals approximately 1 million due future noncancelable subleases rental expense lease obligations years ended december 31 2007 2006 2005 40 million 43 million 53 million includes 27 million 2005 related consolidating houstonbased operations guarantees involved various joint ventures ownership arrangements sometimes require financial performance guarantees financial guarantee obligated make payments guaranteed party fails make payments violates terms financial arrangement performance guarantee provide assurance guaranteed party execute terms contract required perform behalf also periodically provide indemnification arrangements related assets businesses sold arrangements include limited indemnification income taxes resolution existing disputes environmental matters potential exposure guarantee indemnification agreements range specified amount unlimited dollar amount depending nature claim particular transaction arrangements specified dollar amount maximum stated value approximately 785 million indemnified third parties 15 million amounts exclude guarantees issued related letters credit discussed note 11 included maximum stated value approximately 438 million related indemnification arrangements associated sale anr related operations approximately 119 million related tax matters related interest indemnifications guarantees arising sale macae power facility december 31 2007 recorded obligations 51 million related guarantees indemnification arrangements 8 million related anr related assets macae unable estimate maximum exposure guarantee indemnification agreements provide limits amount future payments due uncertainty exposures addition exposures described trial court ruled upheld appeal required indemnify third party benefits paid closed group retirees one former subsidiaries liability approximately 379 million associated estimated exposure matter december 31 2007 discussion matter see retiree medical benefits matters commercial commitments various commercial commitments purchase obligations recorded balance sheet december 31 2007 firm commitments transportation storage capacity contracts 195 million due various times purchase capital commitments including maintenance engineering procurement construction contracts 709 million substantial majority due less one year also hold cancelable easements rightofway arrangements landowners permitting use land construction operation pipeline systems currently obligation easements material results operations however currently negotiating longterm rightofway agreement navajo nation could result significant commitment us see navajo nation 13 retirement benefits overview retirement benefits pension benefits primary pension plan defined benefit plan covers substantially us employees provides benefits cash balance formula certain employees participated prior pension plans el paso sonat inc coastal corporation receive greater cash balance benefits transition benefits prior plan formulas anticipate making contributions pension plan 2008 addition primary pension plan maintain supplemental executive retirement plan serp provides additional benefits selected officers key management serp provides benefits excess certain irs limits essentially mirror primary pension plan expect contribute 4 million serp 2008 also maintain two frozen pension plans closed new participants provide benefits former employees previously discontinued coal convenience store operations anticipate making contributions frozen pension plans 2008 serp frozen plans together referred pension plans also participate several multiemployer pension plans benefit former employees union members contributions plans 2007 2006 2005 material retirement savings plan maintain defined contribution plan covering us employees match 75 percent participant basic contributions 6 percent eligible compensation make additional discretionary matching contributions depending performance relative peers amounts expensed plan approximately 16 million 30 million 25 million years ended december 31 2007 2006 2005 postretirement benefits provide postretirement medical benefits closed groups retired employees limited postretirement life insurance benefits current retired employees postretirement employee benefits opeb regulated pipeline companies prefunded extent costs recoverable rates extent opeb costs regulated pipeline companies differ amounts recovered rates regulatory asset liability recorded expect contribute 27 million postretirement plans 2008 medical benefits closed groups retirees may subject deductibles copayment provisions limitations dollar caps amount employer costs reserve right change benefits pension postretirement benefits december 31 2006 adopted recognition provisions sfas 158 upon adoption reflected assets liabilities related pension postretirement benefit plans based funded unfunded status actuarial deferrals reclassified component accumulated comprehensive income adoption standard decreased noncurrent assets 601 million noncurrent deferred tax liabilities 210 million accumulated comprehensive income 391 million march 2007 ferc issued guidance requiring regulated pipeline companies recognize regulatory asset liability funded status asset liability would otherwise recorded accumulated comprehensive income sfas 158 probable amounts calculated basis sfas 106 employers’ accounting postretirement benefits pensions would included rates future periods upon adoption ferc guidance reclassified approximately 9 million beginning balance accumulated comprehensive income regulatory liabilities included noncurrent liabilities balance sheet table provides additional information related pension postretirement plans september 30 measurement date benefit obligations plan assets december 31 balance sheet amounts accumulated benefit obligation defined benefit pension plans 20 billion 21 billion december 31 2007 2006 projected benefit obligation accumulated benefit obligation pension plans whose accumulated benefit obligations exceeded fair value plan assets 37 million december 31 2007 167 million december 31 2006 accumulated postretirement benefit obligation postretirement benefit plans whose accumulated postretirement benefit obligations exceeded fair value plan assets 222 million 320 million december 31 2007 2006 accumulated comprehensive income includes approximately 8 million unamortized prior service costs net tax anticipate approximately 16 million accumulated comprehensive loss net tax recognized part net periodic benefit cost 2008 change benefit obligation plan assets funded status benefits presented computed twelve months ended september 30 1 benefit obligation table refers projected benefit obligation pension plans accumulated postretirement benefit obligation postretirement plans 2 defer difference actual return plan assets expected return three year period considered inclusion net benefit expense income deferred actuarial gains losses amortized extent remaining unrecognized actual gains losses exceed greater 10 percent projected benefit obligations market related value plan assets expected payment future benefits december 31 2007 expect following payments plans net participant contributions 1 includes reduction years presented expected subsidy related medicare prescription drug improvement modernization act 2003 components net benefit cost income years ended december 31 components net benefit cost income follows 1 permitted amortization prior service cost determined using straightline amortization cost average remaining service period employees expected receive benefits plan actuarial assumptions sensitivity analysis projected benefit obligations net benefit cost based actuarial estimates assumptions following table details weightedaverage actuarial assumptions used determining projected benefit obligation net benefit costs pension postretirement plans 2007 2006 2005 1 expected return plan assets pretax rate return based targeted portfolio investments postretirement benefit plans’ investment earnings subject unrelated business income tax rate 35 expected return plan assets postretirement benefit plans calculated using aftertax rate return actuarial estimates postretirement benefit plans assumed weightedaverage annual rate increase per capita costs covered health care benefits 94 percent gradually decreasing 50 percent year 2015 assumed health care cost trends significant effect amounts reported postretirement benefit plans onepercentage point change assumed health care cost trends would following effects september 30 plan assets primary investment objective plans ensure longterm life plans adequate pool sufficiently liquid assets meet benefit obligations participants retirees beneficiaries exists investment objectives longterm nature covering typical market cycles three five years shortfall investment performance compared investment objectives result general economic capital market conditions following table provides target actual asset allocations pension postretirement benefit plans september 30 matters trial court ruled upheld appeal required indemnify third party benefits paid closed group retirees estimated liability ruling utilizing actuarial methods similar used estimating obligations associated postretirement benefit plans however legal reserves included disclosures related pension postretirement benefits discussion matter see note 12 14 stockholders’ equity minority interest stockholders’ equity common stock 2006 issued 357 million shares common stock net proceeds approximately 500 million 2005 issued approximately 136 million shares common stock remaining holders 272 million notes originally formed portion equity security units settlement commitment purchase shares convertible perpetual preferred stock 2005 issued 750 million convertible perpetual preferred stock dividends preferred stock declared quarterly rate 499 per annum approved board directors dividends accumulate paid share preferred stock convertible holder’s option time subject adjustment 767754 shares common stock certain conditions conversion rate represents equivalent conversion price approximately 1303 per share conversion rate subject adjustment based certain events include limited fundamental changes business mergers business combinations well distributions common stock adjustments current rate dividends common stock able cause preferred stock converted common stock five years issuance common stock trading premium 130 percent conversion price net proceeds issuance preferred stock along cash hand used settle litigation approximately 442 million redeem 6 million outstanding shares 825 series cumulative preferred stock subsidiary el paso tennessee pipeline company approximately 300 million dividends table shows amount dividends paid declared millions except per share amounts dividends common stock preferred stock treated reduction additional paidincapital since currently accumulated deficit expect dividends paid common preferred stock 2007 taxable stockholders anticipate dividends paid current accumulated earnings profits tax purposes terms 750000 outstanding shares 499 convertible preferred stock prohibit payment dividends common stock unless paid set aside payment accumulated unpaid dividends preferred stock preceding dividend periods addition although credit facilities contain direct restriction payment dividends included fixed charge calculation fixed charge coverage ratio credit facilities fixed charge ratio exceed permitted maximum level ability pay additional dividends would restricted accumulated comprehensive income following table provides components accumulated comprehensive income loss december 31 minority interest november 2007 issued common units subsidiary el paso pipeline partners lp master limited partnership accordingly recorded minority interest balance sheet 537 million partnership agreement mlp obligated distribute available cash defined agreement currently mlp’s minimum quarterly distribution common units 02875unit per quarter 15 stockbased compensation overview stockbased compensation plans may issue employees incentive stock options common stock intended qualify section 422 internal revenue code nonqualified stock options restricted stock restricted stock units stock appreciation rights performance shares performance units stockbased awards authorized grant awards approximately 425 million shares common stock current plans includes 35 million shares employee plan 25 million shares nonemployee director plan 5 million shares employee stock purchase plan december 31 2007 approximately 29 million shares remain available grant current plans addition approximately 18 million shares stock option awards outstanding granted terminated plans obligate us issue additional shares common stock exercised stock option exercises restricted stock funded primarily issuance new common shares record stockbased compensation expense excluding amounts capitalized operation maintenance expense requisite service period separately vesting portion award net estimates forfeitures actual forfeitures differ estimates additional adjustments compensation expense required future periods nonqualified stock options grant nonqualified stock options employees exercise price equal market value stock grant date stock option awards contractual terms 10 years generally vest equal amounts three years grant date pay dividends unexercised options summary stock option transactions year ended december 31 2007 presented 2007 2006 recognized 16 million 11 million pretax compensation expense stock options capitalized approximately 4 million 2 million expense respective year part fixed assets recorded 6 million 4 million income tax benefits total compensation cost related nonvested option awards yet recognized december 31 2007 approximately 16 million expected recognized weighted average period 10 months options exercised year ended december 31 2007 2006 total intrinsic value approximately 6 million 5 million generated 7 million 6 million cash proceeds generate significant associated income tax benefit total intrinsic value cash received income tax benefit generated option exercises material year ended december 31 2005 fair value assumptions fair value stock option granted estimated date grant using blackscholes optionpricing model based several assumptions based management’s best estimate time grant years ended december 31 2007 2006 2005 weighted average grant date fair value per share options granted 553 489 388 listed weighted average assumption based grants fiscal year estimate expected volatility based analysis implied volatilities traded options common stock historical stock price volatility expected term adjusted certain time periods believe representative future stock performance prior january 1 2006 estimated expected volatility based primarily adjusted historical stock price volatility effective january 1 2006 adopted provisions sec staff accounting bulletin sab 107 estimate expected term option awards based vesting period average remaining contractual term expect continue use approach stock option contracts consistent sec sab 110 share based payment allows us continue use “simplified method” estimating expected term consistent manner determined expected term sab 107 use method due lack sufficient historical data provide reasonable basis estimating expected term based significant changes composition employees receiving stockbased compensation awards last several years restricted stock may grant shares restricted common stock carry voting dividend rights officers employees sale transfer shares restricted vest currently outstanding grant timebased restricted stock fair value timebased restricted shares determined grant date shares generally vest equal amounts three years date grant summary changes nonvested restricted shares fiscal years presented weighted average grant date fair value per share restricted stock granted 2007 2006 2005 1473 1309 1078 total fair value shares vested 2007 2006 2005 31 million 24 million 14 million 2007 2006 2005 recognized approximately 25 million 17 million 18 million pretax compensation expense restricted share awards capitalized approximately 7 million 2007 2 million 2006 2005 part fixed assets recorded 9 million 6 million 6 million income tax benefits related restricted stock arrangements total unrecognized compensation cost related arrangements december 31 2007 approximately 24 million expected recognized weighted average period 10 months employee stock purchase plan employee stock purchase plan allows participating employees right purchase common stock 95 percent market price last trading day month plan noncompensatory provisions sfas 123r shares issued plan insignificant 2007 2006 2005 16 business segment information december 31 2007 business consists two core segments pipelines exploration production also marketing power segments prior 2006 also field services segment segments strategic business units provide variety energy products services managed separately segment requires different technology marketing strategies corporate activities include general administrative functions well miscellaneous businesses various contracts assets immaterial discussion segment follows pipelines provides natural gas transmission storage related services primarily united states december 31 2007 conducted activities primarily seven wholly majority owned interstate pipeline systems equity interests three interstate transmission systems along two underground natural gas storage entities lng terminalling facility exploration production engaged exploration acquisition development production natural gas oil ngl primarily united states brazil egypt marketing markets manages price risks associated natural gas oil production well remaining legacy trading portfolio power manages risks associated remaining international power assets primarily brazil asia central america continue pursue sale assets prior january 1 2006 field services segment conducted midstream activities disposed substantially assets segment customers whose revenues exceeded 10 percent total revenues 2007 2006 2005 management uses earnings interest expense income taxes ebit assess operating results effectiveness business segments consist consolidated businesses investments unconsolidated affiliates believe ebit useful investors allows effectively evaluate operating performance using performance measure analyzed internally management define ebit net income loss adjusted items impact income loss continuing operations discontinued operations impact accounting changes ii income taxes iii interest debt expense exclude interest debt expense investors may evaluate operating results without regard financing methods capital structure ebit may comparable measures used companies additionally ebit considered conjunction net income performance measures operating income operating cash flow reconciliation ebit income continuing operations periods ended december 31 following tables reflect segment results three years ended december 31 1 includes eliminations intercompany transactions intersegment revenues along intersegment operating expenses incurred normal course business operating segments recorded intersegment revenue elimination 19 million operation maintenance expense elimination 1 million included “corporate” column remove intersegment transactions 2 revenues external customers include gains losses related hedging price risk associated natural gas oil production intersegment revenues represent sales marketing segment responsible marketing production third parties 3 total foreign assets approximately 06 billion relates property plant equipment approximately 06 billion relates investments advances unconsolidated affiliates 4 amounts net third party reimbursements capital expenditures returns invested capital 5 includes debt extinguishment costs 86 million related refinancing epep’s 12 billion notes 1 includes eliminations intercompany transactions intersegment revenues along intersegment operating expenses incurred normal course business operating segments recorded intersegment revenue elimination 37 million operation maintenance expense elimination 13 million included “corporate” column remove intersegment transactions 2 revenues external customers include gains losses related hedging price risk associated natural gas oil production intersegment revenues represent sales marketing segment responsible marketing production third parties 3 excludes assets discontinued operations 4133 million see note 2 4 approximately 04 billion total foreign assets relates property plant equipment approximately 07 billion relates investments advances unconsolidated affiliates 5 amounts net third party reimbursements capital expenditures returns invested capital 1 includes eliminations intercompany transactions intersegment revenues along intersegment operating expenses incurred normal course business operating segments recorded intersegment revenue elimination 91 million operation maintenance expense elimination 2 million included “corporate” column remove intersegment transactions 2 revenues external customers include gains losses related hedging price risk associated natural gas oil production intersegment revenues represent sales marketing segment responsible marketing production third parties 3 relates intercompany activities continuing operations discontinued operations 4 excludes assets discontinued operations 4649 million 5 total foreign assets approximately 03 billion relates property plant equipment approximately 10 billion relates investments advances unconsolidated affiliates 6 amounts net third party reimbursements capital expenditures returns invested capital 17 investments earnings transactions unconsolidated affiliates hold investments unconsolidated affiliates accounted using equity method accounting income statement typically reflects share net earnings directly attributable unconsolidated affiliates ii impairments adjustments recorded us investment balance differs underlying net equity investments due primarily purchase price adjustments impairment charges recorded us december 31 2007 2006 investment balance exceeded net equity underlying net assets investments 377 million 409 million due items majority purchase price adjustments related investment four star acquired 2005 generally amortize assess recoverability amount based development production underlying estimated proved natural gas oil reserves four star net ownership interest investments earnings losses unconsolidated affiliates follows years ended december 31 impairment charges gains losses sales equity investments included earnings unconsolidated affiliates 2007 2006 2005 impairments gains losses primarily result decision sell number investments based declines fair value investments due changes economics investments’ underlying contracts markets serve gains losses consisted following summarized financial information proportionate share operating results financial position unconsolidated affiliates including hold greater 50 percent interest received distributions dividends 223 million 177 million 2007 2006 includes 34 million 38 million returns capital investments following table shows revenues charges resulting transactions unconsolidated affiliates 1 decrease primarily due sale investments power segment 2 decrease primarily due impairment porto velho note receivable 2007 described accounts receivable sales program several pipeline subsidiaries agreements sell certain accounts receivable qualifying special purpose entities qspes sfas 140 accounting transfers servicing financial assets extinguishments liabilities december 31 2007 2006 sold approximately 189 million 202 million receivables received cash approximately 79 million 108 million received subordinated beneficial interests approximately 107 million 91 million recognized loss approximately 3 million years conjunction sale qspes also issued senior beneficial interests receivables sold third party financial institution totaled 80 million 111 million december 31 2007 2006 reflect subordinated beneficial interest receivables sold accounts receivable affiliates balance sheet reflect accounts receivable sold program changes subordinated beneficial interests operating cash flows statement cash flows agreements earn fee servicing accounts receivable performing administrative duties qspes reflected reduction operation maintenance expense income statement fair value servicing administrative agreements well fees earned material financial statements years ended december 31 2007 2006 matters could impact investments international power 2006 completed sales domestic power facilities accordingly remaining power investments international power facilities december 31 2007 equity investments six power generation transmission facilities asia central america brazil considered variable interests fin 46r operate facilities supply significant portion fuel consumed purchase significant portion power generated facilities additionally longterm debt issued entities recourse project investments advances entities well guarantees agreements follows december 31 2007 porto velho equity investment note receivable porto velho project brazil power generated porto velho project committed stateowned utility power purchase agreements largest extends 2023 july 2007 received offer partner purchase investment project less overall carrying value discussions partner offer temporarily suspended pending resolution certain claims stateowned utility described decision sell investment made time power markets brazil continue evolve mature third quarter 2007 brazilian national power grid operator communicated porto velho’s management power plant region plant serves interconnected integrated power grid brazil soon late 2008 interconnection completed stateowned utility access sources power rates may less price porto velho’s existing power purchase agreements furthermore plans construct new hydroelectric plants northern brazil could reportedly completed early 2012 connected grid could reduce regional power prices amount power porto velho able sell power purchase agreements based assessment impact ongoing developments may northern brazil’s electricity markets porto velho’s power purchase agreements recorded incremental losses investment 2007 approximately 32 million also recorded 25 million impairment note receivable project discontinued accruing interest note adjustments total investment porto velho project approximately 275 million december 31 2007 comprised primarily note receivable project february 2008 received dividend project approximately 29 million partner extended date upon required convert approximately 80 million amounts due note equity investment project july 2008 addition may required convert additional 80 million note july 2008 depending level equity partner contributes project would increase percentage ownership porto velho december 2006 brazilian tax authorities assessed 30 million fine porto velho power project allegedly filing proper tax forms related delivery fuel power facility power purchase agreements believe claim tax authorities without merit addition beginning fourth quarter 2007 stateowned utility made claims porto velho project period 2003 2007 totaling approximately 60 million related alleged excess fuel consumption believe valid defenses fuel claims stateowned utility made additional net claims 30 million retroactive currency indexation adjustments partially offset retroactive revenue surcharges periods plant uses oil fuel currently evaluating claim adverse developments brazilian power markets project could impact ability recover remaining investment future manaus rio negro january 15 2008 transferred ownership manaus rio negro facilities plants’ power purchaser required power purchase agreements transfer date approximately 69 million accounts receivable owed us projects terminated power purchase agreements guaranteed purchaser’s parent purchaser withheld payment receivables light dispute approximately 54 million maintenance items purchaser claims performed plants prior transfer intend recover receivable legal rights enforce parental guarantee independent resolution disputed claim ultimate resolution matters unknown time 2007 recorded impairment investments projects approximately 15 million result assessment matters unrelated mechanical failures plants adverse developments related either ability collect amounts due us related dispute could require us record additional losses future asian central american power investments december 31 2007 total investment including advances projects guarantees related projects approximately 78 million process selling assets changes political economic conditions could negatively impact amount net proceeds expect receive upon sale may result additional impairments investment bolivia 8 percent interest bolivia brazil pipeline december 31 2007 total investment guarantees related pipeline project approximately 117 million bolivian portion 3 million 2006 bolivian government announced decree significantly increasing interest control bolivia’s oil gas assets continue monitor evaluate together partners potential commercial impact political events bolivia could investment new information becomes available future material developments arise may required record impairment investment argentina approximate 22 percent interest argentina chile pipeline december 31 2007 total investment pipeline project approximately 21 million currently evaluating opportunities sell interest pipeline addition july 2006 ministry economy production argentina issued decree significantly increases export taxes natural gas continue evaluate together partners potential commercial impact decrees could argentina chile pipeline potential value expect receive upon sale investment new information becomes available future material developments arise may required record impairment investment supplemental selected quarterly financial information unaudited financial information quarter adjusted reflect discontinued operations summarized unusual infrequently occurring items respective quarters 2007 2006 september 30 2007 items include 77 million gain income related reversal liability related legacy crude oil marketing trading business matter ii losses 64 million 72 million year ended december 31 2007 related porto velho manaus rio negro projects june 30 2007 items include 86 million loss debt extinguishment relating repurchasing notes el paso exploration production company ii 35 million loss 100 million year ended december 31 2007 pjm power contracts primarily resulting increases installed capacity prices march 31 2007 items include gain 651 million net taxes 356 million sale anr related assets recorded discontinued operations ii loss extinguishment debt 201 million conjunction repurchase 35 billion debt obligations december 31 2006 items include 188 million charge associated release capacity alliance contract ii approximately 188 million deferred taxes related anr discontinued operations note 2 september 30 2006 items include marktomarket losses 133 million mcv supply agreement recorded conjunction sale interest related power facility ii 105 million income tax benefit associated reduction tax contingencies reinstatement certain tax credits result irs audit settlements net tax amounts recognized certain foreign investments note 4 june 30 2006 items include income tax benefit 34 million associated irs audit settlements note 4 supplemental natural gas oil operations unaudited exploration production segment engaged exploration acquisition development production natural gas oil ngl united states brazil egypt capitalized costs capitalized costs relating natural gas oil producing activities related accumulated depreciation depletion amortization follows december 31 millions total costs incurred costs incurred natural gas oil producing activities whether capitalized expensed follows year ended december 31 millions pursuant full cost method accounting capitalize certain general administrative expenses related property acquisition exploration development activities interest costs incurred attributable unproved oil gas properties major development projects oil gas properties table includes capitalized internal general administrative costs incurred connection acquisition development exploration natural gas oil reserves 69 million 50 million 47 million years ended december 31 2007 2006 2005 also capitalized interest 35 million 30 million 30 million years ended december 31 2007 2006 2005 january 1 2008 reserve report amounts estimated spent 2008 2009 2010 develop consolidated worldwide proved undeveloped reserves 743 million 515 million 170 million unevaluated capitalized costs exclude capitalized costs natural gas oil properties amortization various stages evaluation expect majority costs included amortization calculation 2008 2009 presented analysis capitalized costs natural gas oil properties year expenditures amortized december 31 2007 pending determination proved reserves millions natural gas oil reserves net quantities proved developed undeveloped reserves natural gas ngl oil condensate changes reserves december 31 2007 presented tables based internal reserve report net proved reserves exclude royalties interests owned others reflect contractual arrangements royalty obligations effect time estimate consolidated reserves consistent estimates reserves filed federal agencies except differences less five percent resulting actual production acquisitions property sales necessary reserve revisions additions reflect actual experience ryder scott independent reservoir engineering firm reports audit committee board directors conducted audit estimates 84 percent consolidated natural gas oil reserves scope audit performed ryder scott included preparation independent estimate proved natural gas oil reserves estimates fields comprising greater 80 percent total worldwide present value future cash flows pretax specific fields included ryder scott’s audit represented largest fields based value ryder scott also conducted audit estimates 75 percent proved reserves four star unconsolidated affiliate estimates four star’s proved natural gas oil reserves prepared internal reservoir engineers reflect prepared engineers four star based amount proved reserves determined ryder scott believe reported reserve amounts reasonable ryder scott’s reports included exhibits annual report form 10k 2007 341 bcfe extensions discoveries 80 bcfe related raton area northern new mexico 43 bcfe related mccook area south texas 34 bcfe related zapata area south texas 26 bcfe related success niobrara johnson counties wyoming 22 bcfe related mustang island 739740 block gulf mexico 20 bcfe related victoria area south texas 2006 299 bcfe extensions discoveries 45 bcfe related coal bed methane projects central alabama 37 bcfe related house creek parkman county line areas northeast wyoming 35 bcfe related mccook area south texas 27 bcfe related raton area northern new mexico 18 bcfe related victoria area south texas 18 bcfe related bear creek area northern louisiana 16 bcfe related minden area east texas 2005 242 bcfe extensions discoveries 46 bcfe related holly minden fields northwest louisiana east texas 39 bcfe related west cameron 6275 offshore block gulf mexico 25 bcfe related raton area northern new mexico 22 bcfe related coal bed methane projects central alabama 22 bcfe related house creek parkman area northeast wyoming 14 bcfe related altamontbluebell area northeast utah numerous uncertainties inherent estimating quantities proved reserves projecting future rates production projecting timing development expenditures including many factors beyond control reserve data represents estimates reservoir engineering subjective process estimating underground accumulations natural gas oil cannot measured exact manner accuracy reserve estimate function quality available data engineering geological interpretations judgment estimates proved reserves determined according rules prescribed sec rules indicate standard “reasonable certainty” applied proved reserve estimates concept reasonable certainty implies technical data becomes available positive upward revision likely negative downward revision estimates subject revision based upon number factors including reservoir performance prices economic conditions government restrictions addition results drilling testing production subsequent date estimate may justify revision estimate reserve estimates often different quantities natural gas oil ultimately recovered meaningfulness reserve estimates highly dependent accuracy assumptions based general volume production natural gas oil properties declines reserves depleted except extent conduct successful exploration development activities acquire additional properties containing proved reserves proved reserves decline reserves produced major discoveries events favorable adverse may considered caused significant change estimated proved reserves since december 31 2007 results operations results operations producing activities fiscal year follows december 31 millions 1 cost products services consists primarily transportation costs 2 production costs include lease operating costs production related taxes including ad valorem severance taxes 3 acquired august 2005 standardized measure discounted future net cash flows standardized measure discounted future net cash flows relating consolidated proved natural gas oil reserves december 31 follows millions calculations preceding table estimated future cash inflows estimated future production proved reserves computed using yearend prices 680 564 1008 per mmbtu natural gas 9598 6105 6104 per barrel oil december 31 2007 2006 2005 united states adjustments transportation charges net prices 640 per mcf gas 8788 per barrel oil 5863 per barrel ngl december 31 2007 may receive amounts different standardized measure discounted cash flow number reasons including price changes effects hedging activities changes standardized measure discounted future net cash flows following principal sources change consolidated worldwide standardized measure discounted future net cash flows millions 1 disclosure reflects changes standardized measure calculation excluding effects hedging activities schedule ii el paso corporation valuation qualifying accounts years ended december 31 2007 2006 2005 millions 1 amounts reflect reclassification discontinued operations 2 included settlement shareholder litigation lawsuits 3 2006 2007 recorded reserves rate refunds epng’s rate case settled 2007 refunds paid customers 4 2006 relates primarily sale accounts receivable accounts receivable sales program 2005 relates primarily accounts written 5 relates primarily valuation allowances deferred tax assets related western energy settlement foreign ceiling test charges foreign asset impairments state foreign net operating loss carryovers 6 relates primarily payments various litigation reserves including 442 million related western energy settlement environmental remediation reserves revenue crediting rate settlement reserves 7 amounts net related insurance receivables item 9item 8 financial statements supplementary data index items contained part ii item 8 financial statements supplementary data management’s annual report internal control financial reporting management responsible establishing maintaining adequate internal control financial reporting defined sec rules adopted securities exchange act 1934 amended internal control financial reporting designed provide reasonable assurance regarding reliability financial reporting preparation financial statements external purposes accordance generally accepted accounting principles consists policies procedures • pertain maintenance records reasonable detail accurately fairly reflect transactions dispositions assets • provide reasonable assurance transactions recorded necessary permit preparation financial statements accordance generally accepted accounting principles receipts expenditures made accordance authorizations management directors • provide reasonable assurance regarding prevention timely detection unauthorized acquisition use disposition assets could material effect financial statements supervision participation management including chief executive officer ceo chief financial officer cfo made assessment effectiveness internal control financial reporting december 31 2008 making assessment used criteria established internal control integrated framework issued committee sponsoring organizations treadway commission coso based evaluation concluded internal control financial reporting effective december 31 2008 effectiveness internal control financial reporting december 31 2008 audited ernst young llp independent registered public accounting firm stated report included herein report independent registered public accounting firm board directors stockholders el paso corporation audited accompanying consolidated balance sheets el paso corporation december 31 2008 2007 related consolidated statements income comprehensive income stockholders’ equity cash flows three years period ended december 31 2008 audits also included financial statement schedule listed index item 15a financial statements schedule responsibility company’s management responsibility express opinion financial statements schedule based audits financial statements citrus corp subsidiaries corporation company 50 interest december 31 2008 2007 2006 four star oil gas company corporation company approximately 49 interest december 31 2008 2007 43 interest december 31 2006 audited auditors whose reports furnished us opinion consolidated financial statements insofar relates amounts included citrus corp subsidiaries four star oil gas company based solely reports auditors consolidated financial statements company’s combined investments companies include approximately 744 million 736 million december 31 2008 2007 respectively company’s combined earnings unconsolidated affiliates companies include approximately 147 million 149 million 126 million three years period ended december 31 2008 audited auditors conducted audits accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements audit also includes assessing accounting principles used significant estimates made management well evaluating overall financial statement presentation believe audits reports auditors provide reasonable basis opinion based audits reports auditors financial statements referred present fairly material respects consolidated financial position el paso corporation december 31 2008 2007 consolidated results operations cash flows three years period ended december 31 2008 conformity us generally accepted accounting principles also opinion related financial statement schedule considered relation basic financial statements taken whole presents fairly material respects information set forth therein discussed note 1 consolidated financial statements effective january 1 2008 company adopted measurement provisions statement financial accounting standards 158 employers’ accounting defined benefit pension postretirement plans amendment fasb statements 87 88 106 132r effective january 1 2007 company adopted provisions financial accounting standards board interpretation 48 accounting uncertainty income taxes interpretation fasb statement 109 effective december 31 2006 company adopted recognition provisions statement financial accounting standards 158 employers’ accounting defined benefit pension postretirement plans amendment fasb statements 87 88 106 132r also audited accordance standards public company accounting oversight board united states el paso corporation’s internal control financial reporting december 31 2008 based criteria established internal controlintegrated framework issued committee sponsoring organizations treadway commission report dated february 26 2009 expressed unqualified opinion thereon report independent registered public accounting firm board directors stockholders el paso corporation audited el paso corporation’s internal control financial reporting december 31 2008 based criteria established internal control integrated framework issued committee sponsoring organizations treadway commission coso criteria el paso corporation’s management responsible maintaining effective internal control financial reporting assessment effectiveness internal control financial reporting included accompanying management’s annual report internal control financial reporting responsibility express opinion company’s internal control financial reporting based audit conducted audit accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether effective internal control financial reporting maintained material respects audit included obtaining understanding internal control financial reporting assessing risk material weakness exists testing evaluating design operating effectiveness internal control based assessed risk performing procedures considered necessary circumstances believe audit provides reasonable basis opinion company’s internal control financial reporting process designed provide reasonable assurance regarding reliability financial reporting preparation financial statements external purposes accordance generally accepted accounting principles company’s internal control financial reporting includes policies procedures 1 pertain maintenance records reasonable detail accurately fairly reflect transactions dispositions assets company 2 provide reasonable assurance transactions recorded necessary permit preparation financial statements accordance generally accepted accounting principles receipts expenditures company made accordance authorizations management directors company 3 provide reasonable assurance regarding prevention timely detection unauthorized acquisition use disposition company’s assets could material effect financial statements inherent limitations internal control financial reporting may prevent detect misstatements also projections evaluation effectiveness future periods subject risk controls may become inadequate changes conditions degree compliance policies procedures may deteriorate opinion el paso corporation maintained material respects effective internal control financial reporting december 31 2008 based coso criteria also audited accordance standards public company accounting oversight board united states 2008 consolidated financial statements el paso corporation report dated february 26 2009 expressed unqualified opinion thereon report independent registered public accounting firm stockholders four star oil gas company opinion consolidated balance sheets related consolidated statements income stockholders’ equity cash flows presented separately herein present fairly material respects financial position four star oil gas company “company” subsidiary december 31 2008 2007 results operations cash flows three years period ended december 31 2008 conformity accounting principles generally accepted united states america financial statements responsibility company’s management responsibility express opinion financial statements based audits conducted audits statements accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements assessing accounting principles used significant estimates made management evaluating overall financial statement presentation believe audits provide reasonable basis opinion described notes 3 4 financial statements company significant transactions affiliated companies relationships possible terms transactions would result transactions among wholly unrelated parties report independent registered public accounting firm board directors stockholders citrus corp opinion consolidated balance sheets related consolidated statements income comprehensive income stockholders’ equity cash flows presented separately herein present fairly material respects financial position citrus corp subsidiaries “company” december 31 2008 2007 results operations cash flows three years period ended december 31 2008 conformity accounting principles generally accepted united states america financial statements responsibility company’s management responsibility express opinion financial statements based audits conducted audits statements accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements assessing accounting principles used significant estimates made management evaluating overall financial statement presentation believe audits provide reasonable basis opinion pricewaterhousecoopers llp houston texas february 26 2009 el paso corporation consolidated statements income millions except per common share amounts see accompanying notes el paso corporation consolidated balance sheets millions except share amounts see accompanying notes el paso corporation consolidated balance sheets millions except share amounts see accompanying notes el paso corporation consolidated statements cash flows millions see accompanying notes el paso corporation consolidated statements stockholders’ equity millions see accompanying notes el paso corporation consolidated statements comprehensive income millions see accompanying notes el paso corporation notes consolidated financial statements 1 basis presentation significant accounting policies basis presentation principles consolidation consolidated financial statements prepared accordance us generally accepted accounting principles gaap include accounts majority owned controlled subsidiaries elimination significant intercompany accounts transactions financial statements prior periods include reclassifications made conform current year presentation reclassifications impact reported net income loss stockholders’ equity consolidate entities either ability control operating financial decisions policies entity ii allocated majority entity’s losses andor returns variable interests entity determination ability control exert significant influence entity whether allocated majority entity’s losses andor returns involves use judgment apply equity method accounting exert significant influence control policies decisions entity allocated majority entity’s losses andor returns use cost method accounting unable exert significant influence entity use estimates preparation financial statements requires use estimates assumptions affect amounts report assets liabilities revenues expenses disclosures financial statements actual results often differ estimates regulated operations interstate natural gas pipelines storage operations subject jurisdiction federal energy regulatory commission ferc natural gas act 1938 natural gas policy act 1978 energy policy act 2005 pipelines follow regulatory accounting principles prescribed statement financial accounting standards sfas 71 accounting effects certain types regulation sfas 71 record regulatory assets liabilities would recorded gaap nonregulated entities regulatory assets liabilities represent probable future revenues expenses associated certain charges credits recovered refunded customers rate making process items apply regulatory accounting requirements include certain postretirement employee benefit plan costs equity return component regulated capital projects certain costs related gas used operations costs included expected included future rates cash equivalents consider shortterm investments original maturity less three months cash equivalents maintain cash deposit banks insurance companies pledged particular use restricted support potential liability classify balances restricted cash current noncurrent assets balance sheet based expect restrictions cash removed december 31 2008 2 million restricted cash current assets 57 million noncurrent assets december 31 2007 7 million restricted cash current assets 91 million noncurrent assets allowance doubtful accounts establish provisions losses accounts notes receivable natural gas imbalances due shippers operators determine collect part outstanding balance regularly review collectibility establish adjust allowance necessary using specific identification method property plant equipment pipelines excluding natural gas oil properties property plant equipment recorded original cost construction upon acquisition fair value assets acquired assets construct capitalize direct costs labor materials indirect costs overhead interest equity return component regulated businesses capitalize major units property replacements improvements expense minor items description methods use depreciate regulated property plant equipment see note 11 included pipeline property balances additional acquisition costs represent excess purchase costs associated purchase business combinations allocated regulated interstate systems’ property plant equipment costs amortized straightline basis recover excess costs rates retire property plant equipment regulated operations charge accumulated depreciation amortization original cost assets addition cost remove sell dispose assets less salvage value recognize gain loss unless sell entire operating unit include gains losses dispositions operating units operating income natural gas oil properties use full cost method account natural gas oil properties full cost method substantially costs incurred connection acquisition development exploration natural gas oil reserves capitalized countrybycountry basis capitalized amounts include costs unproved properties internal costs directly related acquisition development exploration activities asset retirement costs capitalized interest full cost method dry hole costs geological geophysical costs capitalized full cost pool subject amortization periodically assessed impairment ceiling test calculation discussed capitalized costs associated proved reserves amortized life reserves using unit production method conversely capitalized costs associated unproved properties excluded amortizable base properties evaluated occurs quarterly transfer unproved property costs amortizable base properties determined proved reserves addition countries natural gas oil reserve base exists transfer unproved property costs amortizable base completed evaluation unproved properties determined impaired exploratory wells determined unsuccessful additionally amortizable base includes future development costs dismantlement restoration abandonment costs net estimated salvage values geological geophysical costs incurred cannot associated specific unevaluated properties prospects direct interest capitalized costs country net related income tax effects limited ceiling based present value future net revenues discounted 10 percent plus lower cost fair market value unproved properties net related income tax effects utilize endofperiod spot prices calculating future net revenues unless prices result ceiling test charge case may evaluate price recoveries subsequent end period total capitalized costs exceed ceiling required writedown capitalized costs ceiling perform ceiling test calculation quarter required writedown included income statement ceiling test charge ceiling test calculations include effects derivative instruments designated qualify cash flow hedges anticipated future natural gas oil production date calculation ceiling test calculations exclude estimated future cash outflows associated asset retirement liabilities related proved developed reserves sell convey interests natural gas oil properties reduce natural gas oil reserves amount attributable sold conveyed interest recognize gain loss sales natural gas oil properties unless sales would significantly alter relationship capitalized costs proved reserves treat sales proceeds nonsignificant sales adjustment cost properties asset investment divestituresimpairments evaluate assets investments impairment events circumstances indicate carrying values may recovered events include market declines believed temporary changes manner intend use longlived asset decisions sell asset investment adverse changes legal business environment adverse actions regulators event occurs evaluate recoverability carrying value based either longlived asset’s ability generate future cash flows undiscounted basis ii fair value investment unconsolidated affiliate impairment indicated decide sell longlived asset group assets adjust carrying values asset downward necessary estimated fair value fair value estimates generally based market data obtained sales process analysis expected discounted cash flows magnitude impairment impacted number factors including nature assets sold established time frame completing sale among factors reclassify assets groups assets sold either heldforsale discontinued operations depending among criteria whether significant longterm continuing involvement assets sold cease depreciating assets period reclassified either held sale discontinued operations pension postretirement benefits maintain several pension postretirement benefit plans make contributions plans required fund benefits paid participants retirees contributions invested benefits paid plan participants record net benefit cost related plans income statement net benefit cost function many factors including benefits earned year plan participants function employee’s salary level benefits provided plan actuarial assumptions passage time expected returns plan assets amortization certain deferred gains losses discussion policies respect pension postretirement plans see note 14 effective december 31 2006 began accounting pension postretirement benefit plans recognition provisions sfas 158 employers’ accounting defined benefit pension postretirement plans amendment fasb statements 87 88 106 132r recorded 391 million increase net income taxes 210 million accumulated comprehensive loss related adoption standard sfas 158 record asset liability pension postretirement benefit plans based funded status deferred amounts related unrecognized gains losses changes actuarial assumptions recorded either regulatory asset liability regulated operations accumulated comprehensive income loss component stockholders’ equity nonregulated operations gains losses recognized income statement effective january 1 2008 adopted measurement date provisions sfas 158 changed measurement date pension postretirement benefit plans september 30 december 31 recorded 4 million decrease net income taxes 2 million january 1 2008 accumulated deficit 3 million decrease net income taxes 2 million january 1 2008 accumulated comprehensive loss upon adoption measurement date provisions standard reflect additional three months net periodic benefit income based september 30 2007 measurement discussion application sfas 158 see note 14 revenue recognition business segments provide number services sell variety products record revenues products services include estimates amounts earned unbilled estimate unbilled revenues related services provided products delivered based contract data regulatory information commodity prices preliminary throughput allocation measurements among items revenue recognition policies significant operating segments follows pipelines revenues pipelines segment derives revenues primarily transportation storage services revenues services generally based thermal quantity gas delivered subscribed price specified contract transportation storage services recognize reservation revenues firm contracted capacity ratably contract period regardless amount natural gas transported stored interruptible volumetric based services record revenues physical deliveries natural gas made agreed upon delivery point gas injected withdrawn storage facility gas needed operations based volumes allowed retain relative amounts gas use operating purposes recognize revenue gas used operations shippers retain volumes market prices required tariffs subject ferc regulations result revenues collect rate proceedings may subject refund establish reserves potential refunds exploration production revenues exploration production segment derives revenues primarily physical sale natural gas oil condensate ngl revenues sales products recorded upon delivery passage title using sales method net royalty interests profit interests produced product actual sales volumes exceed entitled share sales volumes overproduced imbalance occurs extent overproduced imbalance exceeds share remaining estimated proved reserves given property record liability costs associated transportation delivery production included cost products services marketing revenues marketing segment derives revenues physical natural gas power transactions management derivative contracts derivative transactions recorded fair value changes fair value reflected net operating revenues discussion income recognition policies derivatives see price risk management activities impact nonderivative transactions including transportation contracts recognized net operating revenues based contractual market price related volumes time commodity delivered contracts terminated environmental costs contingencies environmental costs record liabilities undiscounted amounts balance sheet current longterm liabilities environmental assessments indicate remediation efforts probable costs reasonably estimated estimates liabilities based currently available facts existing technology presently enacted laws regulations taking consideration likely effects societal economic factors include estimates associated legal costs amounts also consider prior experience remediating contaminated sites companies’ cleanup experience data released epa organizations estimates subject revision future periods based actual costs new circumstances capitalize costs benefit future periods recognize current period charge operation maintenance expense cleanup efforts benefit future periods evaluate amounts paid directly reimbursed government sponsored programs potential recoveries reimbursements remediation costs third parties including insurance coverage separately liability recovery evaluated based creditworthiness solvency third party among factors recovery assured record report asset separately associated liability balance sheet contingencies recognize liabilities contingencies exposure fully analyzed indicates probable liability incurred amount loss reasonably estimated likely outcome contingency reasonably estimated accrue liability amount likely outcome cannot estimated range potential losses established one amount range likely low end range accrued price risk management activities price risk management activities relate primarily derivatives entered hedge otherwise reduce commodity exposure natural gas oil production interest rate foreign currency exposure longterm debt also hold derivatives intended hedge exposures including related legacy trading activities derivatives reflected balance sheet fair value assets liabilities price risk management activities cash collateral associated derivatives significant financial statements classify derivatives either current noncurrent assets liabilities based anticipated settlement date net derivative assets liabilities counterparties legal right offset see note 8 discussion price risk management activities derivatives designated accounting hedges impact revenues expenses based nature timing transactions hedge derivatives designated hedges markedtomarket period changes fair value well realized amounts reflected operating revenues exploration production segment marketing segment cash flow statement cash inflows outflows associated settlement derivative instruments recognized operating cash flows derivatives intended hedge principal amounts foreign currency denominated debt balance sheet receivables payables resulting settlement derivative instruments reported trade receivables payables income taxes record current income taxes based current taxable income provide deferred income taxes reflect estimated future tax payments receipts deferred taxes represent tax impacts differences financial statement tax bases assets liabilities carryovers year end account tax credits flowthrough method reduces provision income taxes year tax credits first become available reduce deferred tax assets valuation allowance based estimates likely portion assets realized future period estimates utilized recognition deferred tax assets subject revision either future periods based new facts circumstances effective january 1 2007 began applying provisions financial accounting standards board fasb interpretation fin 48 accounting uncertainty income taxes interpretation fasb statement 109 clarifies sfas 109 accounting income taxes recorded 4 million increase january 1 2007 accumulated deficit balance increase 2 million additional paidincapital related adoption standard requires us evaluate tax positions jurisdictions years statute limitations expired fin 48 requires companies meet “morelikelythannot” threshold ie greater 50 percent likelihood tax position sustained examination prior recording benefit tax positions additionally tax positions meeting “morelikelythannot” threshold amount benefit limited largest benefit greater 50 percent probability realized upon effective settlement discussion impact application fin 48 see note 5 accounting asset retirement obligations account asset retirement obligations accordance sfas 143 accounting asset retirement obligations fin 47 accounting conditional asset retirement obligations record liability legal obligations associated replacement removal retirement longlived assets period obligation incurred asset retirement liabilities recorded estimated fair value corresponding increase property plant equipment increase property plant equipment depreciated useful life longlived asset liability relates ongoing expense also recognized changes value liability result passage time record depreciation depletion amortization expense income statement regulated pipelines ability recover certain costs customers recorded asset rather expense associated depreciation property plant equipment accretion liabilities described accounting stockbased compensation measure employee stockbased compensation awards fair value date granted employees recognize compensation cost financial statements requisite service period additional information stockbased compensation awards see note 16 new accounting pronouncements issued yet adopted december 31 2008 following accounting standards interpretations yet adopted us fair value measurements adopted provisions sfas 157 fair value measurements measuring fair value financial assets liabilities financial statements elected defer adoption sfas 157 certain nonfinancial assets liabilities january 1 2009 adoption material impact financial statements september 2008 emerging issues task force issued issue 085 issuer’s accounting liabilities measured fair value thirdparty credit enhancement provides guidance companies consider credit determining fair value liabilities third party credit enhancements related standard requires noncash credit enhancements letters credit considered determining fair value liabilities including derivative liabilities adopt provisions standard first quarter 2009 currently evaluating impact standard financial statements business combinations december 2007 fasb issued sfas 141r business combinations provides revised guidance accounting acquisitions businesses standard changes current guidance require acquired assets liabilities minority interest certain contingencies measured fair value certain acquisitionrelated costs expensed rather capitalized sfas 141r apply acquisitions effective december 31 2008 application standard acquisitions prior date permitted noncontrolling interests december 2007 fasb issued sfas 160 noncontrolling interests consolidated financial statements provides guidance presentation minority interest subsequently renamed “noncontrolling interest ” financial statements standard requires noncontrolling interest presented separate component equity rather “mezzanine” item liabilities equity also requires noncontrolling interest presented separate caption income statement standard also requires transactions noncontrolling interest holders including issuance repurchase noncontrolling interests accounted equity transactions unless change control subsidiary occurs adopt provisions standard effective january 1 2009 impact presentation noncontrolling interests balance sheets income statements oil gas reserves reporting december 2008 securities exchange commission sec issued final rule adopting revisions oil gas reporting requirements revisions impact determination disclosure oil gas reserves information among things new rules revise definition proved reserves require companies use twelve month average commodity price determining future net revenues rather period end price currently required changes along proposed changes impact manner perform full cost ceiling test calculation determine related charge provisions final rule effective december 31 2009 cannot applied earlier date currently assessing impact final rule may determination disclosure oil gas reserves information 2 acquisitions divestitures acquisitions gulf lng february 2008 paid 295 million complete acquisition 50 percent interest gulf lng clean energy project liquefied natural gas lng terminal currently construction pascagoula mississippi terminal expected placed service late 2011 estimated total cost 11 billion addition commitment loan gulf lng 150 million advanced approximately 26 million december 31 2008 partner project commitment loan 64 million account investment gulf lng using equity method exploration production properties year ended december 31 2008 acquired interests domestic natural gas oil properties 61 million including producing properties 51 million 2007 acquired operated natural gas oil producing properties undeveloped acreage south texas 254 million also acquired peoples energy production company peoples 887 million peoples exploration production company natural gas oil properties located primarily arklatex texas gulf coast mississippi areas san juan arkoma basins divestitures 2008 2007 2006 sold number assets investments business segments corporate activities table discussions summarize assets sold proceeds sales exploration production assets sold 2008 consisted primarily natural gas oil properties gulf mexico texas gulf coast regions sales 2006 consisted natural gas oil properties south texas power assets sold 2008 consist power investments central america asia assets sold 2006 consisted primarily interests midland cogeneration venture power plants brazil asia central america marketing pipelines corporate assets sold consisted primarily fuel oil terminal 2008 investment new york mercantile exchange stagecoach pipeline lateral 2007 discontinued operations assets held sale sfas 144 accounting impairment disposal longlived assets classify assets groups assets disposed held sale appropriate discontinued operations received appropriate approvals disposed management board directors meet criteria cash flows discontinued businesses reflected discontinued operating investing financing activities statement cash flows extent operations maintain separate cash balances reflect net cash flows generated businesses contribution continuing operations cash continuing financing activities following description discontinued operations summarized results operations periods ended december 31 2007 2006 december 31 2007 assets liabilities related discontinued operations assets held sale sold anr related operations february 2007 sold anr michigan storage assets 50 percent interest great lakes gas transmission approximately 37 billion recorded gain sale 648 million net taxes 354 million included net assets discontinued operations date sale net deferred tax liabilities assumed purchaser also recorded approximately 188 million deferred taxes 2006 conjunction sale international power operations 2006 completed sale discontinued international power operations including macae wholly owned power plant facility brazil asian central american power assets total net proceeds approximately 368 million income taxes discontinued operations years ended december 31 2007 2006 incurred income tax expense associated discontinued operations 369 million 274 million resulting effective tax rate discontinued operations approximately 35 126 years effective tax rate 2006 significantly higher statutory rate 35 primarily due 188 million deferred taxes recorded upon agreement sell stock anr michigan storage assets 50 percent interest great lakes gas transmission prior decision sell recorded deferred taxes individual assetsliabilities portion investment stock one companies summarized operating results discontinued operations follows 1 includes loss approximately 19 million associated extinguishment certain debt obligations 3 ceiling test charges fourth quarter 2008 recorded reduction property plant equipment due noncash ceiling test charges 27 billion resulted declines commodity prices capitalized costs exceeded ceiling limit 22 billion domestic full cost pool 05 billion brazilian full cost pool calculation charges based december 31 2008 spot natural gas price 571 per mmbtu oil price 4460 per barrel calculating ceiling test charges required hold prices constant life reserves even though actual prices natural gas oil volatile change period first two months 2009 natural gas oil prices declined levels december 31 2008 may required record additional ceiling test charges future unless commodity prices significantly increase oilfield service costs significantly decrease current levels 4 income expenses following components income expenses continuing operations three years ended december 31 5 income taxes pretax income loss income tax expense benefit tables show pretax income loss continuing operations components income tax expense benefit years ended december 31 effective tax rate reconciliation income taxes included income continuing operations differs amount computed applying statutory federal income tax rate 35 percent following reasons three years ended december 31 2008 overall effective tax rate differed statutory rate due primarily 05 billion ceiling test charge brazilian full cost pool corresponding us brazilian tax benefit impact ceiling test charge effective tax rate included foreign income loss taxed different rates valuation allowances table 2006 effective tax rate continuing operations significantly different statutory rate due primarily conclusion irs audits coastal corporation’s 19982000 tax years el paso’s 2001 2002 tax years resulted reduction tax contingencies reinstatement certain tax credits deferred tax assets liabilities following components net deferred tax liability related continuing operations december 31 cumulative undistributed earnings substantially foreign subsidiaries foreign corporate joint ventures intended indefinitely reinvested foreign operations therefore provision made us taxes foreign withholding taxes may applicable upon actual deemed repatriation estimate taxes earnings repatriated practical december 31 2008 portion cumulative undistributed earnings investments recorded us income taxes approximately 110 million unrecognized tax benefits liabilities uncertain tax matters fin 48 subject taxation us various states foreign jurisdictions exceptions longer subject state local foreign income tax examinations tax authorities years prior 1999 us income tax examinations years prior 2005 june 2008 internal revenue service’s examination el paso’s us income tax returns 2003 2004 settled appellate level approval joint committee taxation settlement issues raised examination materially impact results operations financial condition liquidity years returns still subject review unrecognized tax benefits liabilities uncertain tax matters could increase decrease income tax expense effective income tax rates matters finalized currently unable estimate range potential impacts resolution contested matters could financial statements upon adoption fin 48 recorded additional liabilities unrecognized tax benefits 2 million including interest penalties accounted increase 4 million january 1 2007 accumulated deficit increase 2 million additional paidin capital following table shows change unrecognized tax benefits december 31 2008 2007 approximately 169 million 132 million net federal tax benefits unrecognized tax benefits would affect income tax expense effective income tax rate recognized future periods amount unrecognized tax benefits could change next twelve months expect change significant impact results operations financial position recognize interest accrual related unrecognized tax benefits penalties income tax expense 2008 2007 recognized 4 million 6 million interest related unrecognized tax benefits noted 49 million 45 million accrued payment interest penalties december 31 2008 2007 tax credit nol carryovers december 31 2008 us federal alternative minimum tax credits 314 million carryover indefinitely table presents details federal state net operating loss carryover periods december 31 2008 also 381 million foreign net operating loss carryovers 53 million foreign capital loss carryovers carryover indefinitely usage us federal carryovers subject limitations provided sections 382 383 internal revenue code well separate return limitation year rules irs regulations valuation allowances deferred tax assets recorded net operating losses temporary differences book tax basis assets liabilities expected produce tax deductions future periods realization assets depends recognition sufficient future taxable income specific tax jurisdictions periods temporary differences net operating losses deductible assessing need valuation allowance deferred tax assets consider whether likely portion realized part assessment consider future reversals existing taxable temporary differences primarily related depreciation 2008 provided valuation allowance 202 million deferred tax assets associated brazil net operating losses ceiling test charges valuation allowance established primarily result changes worldwide economic conditions creating uncertainty outlook future taxable income particular tax jurisdiction believe likely realize benefit deferred tax assets net existing valuation allowances 6 earnings per share calculated basic diluted earnings per common share follows three years ended december 31 exclude potentially dilutive securities determination diluted earnings per share well related income statement impacts impact income continuing operations per common share antidilutive potentially dilutive securities consist employee stock options restricted stock convertible preferred stock trust preferred securities zero coupon convertible debentures paid april 2006 year ended december 31 2008 incurred losses continuing operations accordingly excluded potentially dilutive securities determination diluted earnings per share impact loss per common share antidilutive year ended december 31 2007 2006 certain employee stock options trust preferred securities antidilutive additionally 2006 zero coupon convertible debentures redeemed april 2006 antidilutive 2007 convertible preferred stock antidilutive discussion capital stock activity stockbased compensation arrangements instruments noted see notes 15 16 7 fair value financial instruments january 1 2008 adopted provisions sfas 157 fair value measurements sfas 159 fair value option financial assets financial liabilities financial assets liabilities sfas 157 expands disclosure requirements financial instruments derivatives recorded fair value also requires company’s credit risk considered determining fair value instruments adoption sfas 157 resulted 6 million increase operating revenues 4 million pretax increase comprehensive income 10 million reduction liabilities reflect consideration credit risk liabilities recorded fair value considering collateral related positions sfas 159 impact financial statements elected apply fair value accounting adoption applicable financial assets liabilities use various methods determine fair values financial instruments derivatives depend number factors including availability observable market data contractual term underlying instrument instruments fair value calculated based directly observable market data available similar instruments similar markets instruments fair value may calculated based inputs well assumptions related estimates future settlements instruments separate financial instruments derivatives three levels 1 2 3 based assessment availability observable market data significance nonobservable data used determine fair value instruments assessment instrument change time based maturity liquidity instrument could result change classification instruments levels corresponding instruments classified level described • level 1 instruments’ fair values based quoted prices instruments actively traded markets included level marketable securities invested nonqualified compensation plans whose fair value determined using quoted prices instruments • level 2 instruments’ fair values primarily based pricing data representative quoted prices similar assets liabilities active markets identical assets liabilities less active markets included level foreign currency interest rate swaps also included level productionrelated natural gas oil derivatives certain natural gas derivatives natural gas supply arrangements whose fair values based commodity pricing data obtained third party pricing sources creditworthiness counterparties adjusted collateral related positions • level 3 instruments’ fair values partially calculated using pricing data similar level 2 fair value also reflects adjustments less liquid markets longer contractual terms instruments obtain pricing data third party pricing sources adjust data based liquidity underlying forward markets contractual terms use adjusted pricing data develop estimate forward price curves market participants would use curves used estimate value settlements future periods based contractual settlement quantities dates valuation instruments considers specific contractual terms statistical simulation analysis present value concepts internal assumptions related contract maturities extend beyond periods quoted market prices available ii uniqueness contract terms iii limited availability forward pricing information markets lack viable participants pjm forward power market forward market ammonia iv creditworthiness counterparties adjusted collateral related positions since significant portion fair value powerrelated derivatives certain remaining natural gas derivatives longer terms less liquid markets similar level 2 derivatives rely techniques discussed classify instruments level 3 instruments listed fair values financial instruments recorded fair value classified level december 31 2008 millions certain derivative contracts recorded assets exposed risk counterparties may able perform post required collateral us assessed counterparty risk light collateral counterparties posted us recent instability credit markets based assessment determined exposure primarily related productionrelated derivatives foreign currency swaps limited five financial institutions current standard poor’s credit rating better following table presents changes financial assets liabilities included level 3 year ended december 31 2008 millions following table reflects carrying value fair value financial instruments december 31 2008 2007 carrying amounts cash equivalents shortterm borrowings trade receivables payables represented fair value shortterm nature instruments carrying amounts restricted cash noncurrent receivables approximate fair value based interest rates assessment ability recover amounts estimated fair value debt based quoted market prices similar issues including consideration credit risk related instruments 8 price risk management activities following table summarizes carrying value derivatives used price risk management activities december 31 2008 2007 commoditybased derivative contracts include options swaps use manage natural gas oil exposures natural gas power purchase supply contracts derivatives related legacy energy trading activities interest rate foreign currency derivatives consist swaps primarily designated accounting hedges interest rate foreign currency risk longterm debt 1 included current noncurrent assets liabilities balance sheet derivatives designated hedges engage two types hedging activities hedges cash flow exposure hedges fair value exposure enter derivative contract may designate derivative either cash flow hedge fair value hedge time prepare documentation required sfas 133 hedges cash flow exposure primarily relate natural gas oil production hedges interest rate risks longterm debt designed hedge forecasted sales transactions limit variability cash flows received paid related recognized asset liability hedges fair value exposure entered protect fair value recognized asset liability firm commitment hedges interest rate foreign currency exposure designated either cash flow hedges fair value hedges based whether interest underlying debt converted either fixed floating interest rate changes derivative fair values designated cash flow hedges deferred accumulated comprehensive income loss extent effective recognized earnings hedged transactions occur changes fair value derivatives designated fair value hedges recognized earnings offsets changes fair values related hedged assets liabilities firm commitments discussion hedging activities follows cash flow hedges majority commodity sales purchases spot market forward market prices use fixed price swaps floor ceiling option contracts limit exposure decreases commodity prices well fluctuations foreign currency interest rates objective limiting variability cash flows activities summary impacts cash flow hedges included accumulated comprehensive income loss net income taxes december 31 2008 2007 follows 1 reclassifications occur upon physical delivery hedged commodity forecasted transaction longer probable years ended december 31 2008 2007 2006 recognized net gain 1 million net loss 3 million net gain 10 million net income taxes respectively income loss continuing operations related ineffective portion cash flow hedges fourth quarter 2008 removed hedging designation commoditybased derivatives based decision discontinue use hedge accounting prospectively derivatives accumulated comprehensive income 241 million net income taxes associated derivatives reclassified earnings original hedged transactions occur 2012 fair value hedges fixed rate us dollar foreign currency denominated debt exposes us paying higher market rates interest rates decline use interest rate swaps protect value debt instruments converting fixed amounts interest due debt agreements variable interest payments recorded fair value derivatives component longterm debt related accrued interest december 31 2008 2007 derivatives follows amounts millions credit risk subject credit risk related financial instrument assets credit risk relates risk loss would incur result nonperformance counterparties pursuant terms contractual obligations exposures netted legally enforceable right setoff maintain credit policies regard counterparties price risk management activities minimize overall credit risk policies require evaluation potential counterparties’ financial condition including credit rating ii collateral certain circumstances including cash advance letters credit guarantees iii use margining provisions standard contracts iv use master netting agreements allow netting positive negative exposures various contracts associated single counterparty use daily margining provisions financial contracts physical power agreements master netting agreements require counterparty post cash letters credit fair value contract exceeds daily contractual threshold amount typically tied published credit rating counterparty margining collateral provisions also allow us terminate contract liquidate positions counterparty unable provide required collateral margining provisions required return collateral amount posted collateral exceeds amount collateral required collateral received returned vary significantly day based changes market values counterparty’s credit ratings furthermore amount collateral hold may less fair value derivative contracts counterparty given period following table presents summary fair value derivative contracts net collateral liabilities right offset exists presented type derivative counterparty net asset exposure december 31 2008 2007 1 “investment grade” “below investment grade” determined using publicly available credit ratings “investment grade” includes counterparties minimum standard poor’s rating bbb moody’s rating baa3 “below investment grade” includes counterparties public credit rating meet criteria “investment grade” “not rated” includes counterparties rated public rating service approximately 26 counterparties december 31 2008 one counterparties fails perform may recognize immediate loss earnings well additional financial impacts future delivery periods extent replacement contract prices quantities cannot established december 31 2008 three counterparties j aron merrill lynch societe generale comprise 30 percent 37 percent 12 percent respectively net financial instrument exposure december 31 2007 four counterparties merrill lynch commodities morgan stanley group central lomas de real constellation energy commodities group inc comprised 20 percent 16 percent 15 percent 12 percent respectively net financial instrument asset exposure concentration counterparties may impact overall exposure credit risk either positively negatively counterparties may similarly affected changes economic regulatory conditions 9 regulatory assets liabilities regulatory assets liabilities relate interstate pipeline operations included current noncurrent assets liabilities balance sheets balances recoverable reimbursable various periods details regulatory assets liabilities december 31 10 assets liabilities detail current noncurrent assets liabilities balance sheets december 31 11property plant equipment depreciable lives table presents depreciation method depreciable lives property plant equipment 1 composite group method assets similar useful lives characteristics grouped depreciated one asset apply depreciation rate approved rate settlements total cost group net book value equals salvage value reevaluate depreciation rates time redevelop transportation rates file ferc increase decrease rates 2 capitalized costs associated proved reserves amortized life reserves using unit production method conversely capitalized costs associated unproved properties excluded amortizable base properties evaluated impaired see note 1 additional information excess purchase costs december 31 2008 2007 tgp epng excess purchase costs associated historical acquisition total excess costs pipelines approximately 25 billion accumulated depreciation approximately 05 billion 04 billion december 31 2008 2007 excess costs depreciated estimated life pipeline assets costs assigned related depreciation expense year ended december 31 2008 2007 2006 approximately 42 million currently earn return excess purchase costs rate payers capitalized costs construction capitalize carrying cost funds related construction longlived assets reflect increases cost asset balance sheet carrying cost consists interest cost debt could attributed assets constructed ii regulated transmission business return equity could attributed assets constructed debt portion calculated based average cost debt interest costs capitalized included reduction interest expense income statements 45 million 50 million 41 million years ended december 31 2008 2007 2006 equity portion calculated using recent ferc approved equity rate return equity amounts capitalized included nonoperating income statement 37 million 32 million 20 million years ended december 31 2008 2007 2006 construction workin progress december 31 2008 2007 approximately 26 billion 16 billion construction workinprogress included property plant equipment asset retirement obligations legal obligations associated retirement natural gas oil wells related infrastructure natural gas pipelines transmission facilities storage wells obligations related corporate headquarters building production operations obligations plug wells abandoned production exhausted longer plan use wells pipeline operations legal obligations primarily involve purging sealing pipelines abandoned also obligations remove hazardous materials associated natural gas transmission facilities corporate headquarters facilities ever demolished replaced renovated continue evaluate asset retirement obligations future developments could impact amounts record reasonably estimate asset retirement obligation liability accrue liability based estimate timing amount settlement estimating fair value liabilities associated asset retirement obligations utilize several assumptions including projected inflation rate 25 percent creditadjusted discount rates currently range 6 12 percent based liabilities recorded record changes estimates based expected amount timing payments settle asset retirement obligations typically changes result obtaining new information exploration production segment timing obligations plug natural gas oil wells costs certain events accelerate timing asset retirements eg impact hurricanes exploration production segment pipelines segment pipelines operations intend operating maintaining natural gas pipeline storage systems long supply demand natural gas exists expect foreseeable future therefore believe cannot reasonably estimate asset retirement obligation liability substantial majority natural gas pipeline storage system assets indeterminate lives asset retirement liabilities december 31 2008 reflect reduction approximately 109 million related 2008 sale portion natural gas oil properties gulf mexico texas gulf coast regions increase approximately 62 million resulting 2008 impacts hurricanes ike gustav exploration production pipeline assets reflected change estimate table net asset retirement liability december 31 reported balance sheet current noncurrent liabilities changes net liability years ended december 31 follows 12 debt financing obligations credit facilities following provides additional detail longterm financing obligations changes longterm financing obligations 2008 following changes longterm financing obligations millions 1 principal amount note 500 million 2 amounts presented net associated underwriting discounts expenses first two months 2009 tgp subsidiary issued 250 million 800 senior notes net proceeds approximately 235 million ii issued 500 million 825 senior notes net proceeds approximately 473 million tgp el paso notes mature february 2016 additionally subsidiary owns elba island lng facility issued 135 million debt consisting 71 million fiveyear notes 64 million sevenyear notes weighted average cost 96 debt maturities aggregate maturities principal amounts longterm financing obligations december 31 2008 next 5 years total thereafter follows millions 1 amount include fair value fixedtofloating cross currency derivative assets 94 million credit facilitiesletters credit december 31 2008 subject terms various agreements available capacity credit agreements including capacity available epb’s 750 million revolving credit facility approximately 12 billion part determination available capacity credit agreements completed assessment available lenders credit facilities based assessment available capacity noted previously reduced reflect potential exposure loss available capacity approximately 28 million el paso’s 15 billion revolving credit facility approximately 2 million epep’s 10 billion revolving credit facility assessment available lenders also reduced epb’s available capacity approximately 15 million assessment based upon fact one lenders failed fund previous requests facilities filed bankruptcy description existing credit facilities december 31 2008 15 billion revolving credit agreement 15 billion revolving credit facility matures november 2012 el paso certain subsidiaries guaranteed 15 billion revolving credit agreement collateralized stock ownership epng tgp also eligible borrowers 15 billion revolving credit agreement 15 billion revolving credit facility borrow funds libor plus 125 based current applicable margin issue letters credit 1375 amount issued pay annual commitment fee 025 based current applicable margin unused capacity revolving credit facility credit agreement applicable margin used calculate interest borrowings letters credit commitment fees determined variable pricing grid tied credit ratings senior secured debt december 31 2008 approximately 02 billion letters credit issued 05 billion debt outstanding facility december 31 2008 remaining capacity facility approximately 07 billion unsecured revolving credit facility 500 million unsecured revolving credit facility matures july 2011 third party third party trust provides borrowings issuing letters credit required pay fixed facility fees rate 234 total committed amount facility addition pay interest borrowings rate comprised either libor base rate substantially capacity facility used issue letters credit december 31 2008 remaining capacity facility approximately 53 million unsecured credit facilities 500 million unsecured facility provides borrowings issuing letters credit facility matures various tranches 2009 based facility size required pay fixed facility fee weighted average rate 158 per annum full facility amount borrowings carry interest rate libor addition facility fee substantially capacity facility used issue letters credit approximately 54 million available facility december 31 2008 february 2009 entered similar 100 million facility matures various tranches beginning 2013 2014 weighted average fixed facility fee 791 epep 10 billion revolving credit agreement december 31 2008 09 billion outstanding epep’s 10 billion revolving credit facility 01 billion available capacity based current borrowing levels pay interest libor plus 175 borrowings commitment fee 0375 unused capacity facility collateralized certain natural gas oil properties subject revaluation semiannual basis december 31 2008 recent determination sufficient fully support facility matures 2012 epep 300 million revolving credit agreement december 31 2008 300 million available capacity epep’s new 300 million 364day secured revolving credit facility matures december 2009 pay libor plus 35 borrowed money 100 commitment fee facility collateralized certain natural gas oil properties epb’s 750 million revolving credit facility 2007 epb wic epb’s subsidiary entered unsecured 5year revolving credit facility initial aggregate borrowing capacity 750 million expandable 125 billion certain expansion projects acquisitions facility available epb subsidiaries borrowings guaranteed epb subsidiaries amounts borrowed nonrecourse el paso approximately 585 million outstanding credit facility epb remaining capacity approximately 150 million december 31 2008 credit facility two pricing grids one based credit ratings based leverage currently leverage pricing grid effect epb’s cost borrowings libor plus 0425 based epb’s current leverage epb also pays 0125 facility fee 010 commitment utilization fee annually facility letters credit enter letters credit ordinary course operating activities well periodically conjunction sales assets businesses 2008 entered new letter credit facility bank support purchase commitments pipe related ruby pipeline project issued two letters credit facility total approximately 450 million outstanding letters credit facility pay 085 annually approximately 180 million maturing one year 100 annually approximately 270 million maturing two years december 31 2008 total outstanding letters credit issued facilities approximately 16 billion included amount 08 billion letters credit securing recorded obligations related price risk management activities restrictive covenants 15 billion revolving credit agreement covenants 15 billion revolving credit facility include restrictions debt levels restrictions liens securing debt guarantees restrictions mergers sales assets dividend restrictions cross default crossacceleration breach covenants could result acceleration debt financial obligations subsidiaries credit agreement restrictive debt covenants cross default provisions ratio debt consolidated ebitda defined credit agreement shall exceed 525 1 maturity b ratio consolidated ebitda defined credit agreement interest expense plus dividends paid shall less 200 1 maturity c epng tgp cannot incur incremental debt incurrence incremental debt would cause debt consolidated ebitda ratio defined credit agreement particular company exceed 50 1 occurrence event default expiration applicable grace period respect debt aggregate principal amount 200 million epep 10 billion 300 million revolving credit agreements epep’s borrowings facilities subject various conditions financial coverage ratio facilities requires epep’s ebitda defined facility interest expense less 20 1 epep’s debt ebitda defined credit agreement must exceed 40 1 epb’s 750 million revolving credit facility requires epb maintain end fiscal quarter consolidated leverage ratio defined facility less 50 1 four consecutive quarters 55 1 three consecutive quarters subsequent consummation specified permitted acquisitions value greater 25 million restrictions provisions addition restrictions provisions andor subsidiaries subject number additional restrictions covenants restrictions covenants include limitations additional debt subsidiaries limitations use proceeds borrowing subsidiaries limitations cases transactions affiliates limitations incurrence liens potential limitations ability subsidiaries declare pay dividends potential limitations subsidiaries participate cash management program restrictive crossacceleration provision associated indenture one subsidiaries indenture states event default occur resulting acceleration debt obligations subsidiary excess 10 million longterm debt obligation containing provision could accelerated acceleration debt would adversely affect liquidity position turn financial condition also issued various guarantees securing financial obligations subsidiaries affiliates similar covenants facilities financing arrangements capital trusts el paso energy capital trust wholly owned business trust formed march 1998 issued 65 million 475 percent trust convertible preferred securities 325 million trust exists sole purpose issuing preferred securities investing proceeds 475 percent convertible subordinated debentures issued due 2028 trust i’s sole source income interest earned debentures interest income used pay distributions preferred securities also two wholly owned business trusts el paso energy capital trust ii iii trust ii iii issued securities provide full unconditional guarantee trust i’s preferred securities would provide guarantee securities issued trust ii iii trust i’s preferred securities nonvoting except limited circumstances pay quarterly distributions annual rate 475 percent carry liquidation value 50 per security plus accrued unpaid distributions convertible common shares time prior close business march 31 2028 option holder rate 12022 common shares trust preferred security equivalent conversion price 4159 per common share classified securities longterm debt right redeem securities time wyco november 2008 high plains pipeline placed service constructed pipeline joint venture partner affiliate public service company colorado psco wyco funded 50 percent pipeline construction costs reflected noncurrent liability balance sheet construction period upon completion construction obligation affiliate psco construction advances converted financing obligation wyco accordingly reclassified amounts noncurrent liabilities debt financing obligations fourth quarter 2008 principal amount obligation 108 million december 31 2008 paid monthly installments 2043 nonrecourse project financings several subsidiaries investments debt obligations related costs construction acquisition project financing debt recourse project company assets ie without recourse el paso december 31 2008 one international power project accounted equity investment default debt agreement however material exposure result default 13 commitments contingencies legal proceedings erisa class action suit december 2002 purported class action lawsuit entitled william h lewis iii v el paso corporation et al filed us district court southern district texas alleging communication participants retirement savings plan included various misrepresentations omissions caused members class hold maintain investments el paso stock violation employee retirement income security act erisa insurance coverage lawsuit subject certain deductibles copay obligations executed agreements settle matter settlement subject approval court established accruals matter believe adequate cash balance plan lawsuit december 2004 purported class action lawsuit entitled tomlinson et al v el paso corporation el paso corporation pension plan filed us district court denver colorado lawsuit alleges various violations erisa age discrimination employment act result change final average earnings formula pension plan cash balance pension plan trial court dismissed plaintiffs’ claims plaintiffs filed motion seeking overturn dismissal case costs legal exposure related lawsuit currently determinable retiree medical benefits matters 2002 lawsuit entitled yolton et al v el paso tennessee pipeline co case corporation filed federal court detroit michigan lawsuit filed behalf group retirees case corporation case alleged entitled retiree medical benefits medical benefits plan serve plan administrator pursuant merger agreement tenneco inc although asserted obligations plan subject cap pursuant agreement union case employees first quarter 2008 trial court granted summary judgment ruled benefits vested subject cap result obligated pay amounts cap adjusted existing indemnification accrual using current actuarial assumptions reclassified liability postretirement benefit obligation see note 14 discussion impact matter intend pursue appellate options following determination trial court damages incurred plaintiffs period premium payments cap paid retirees believe accruals established matter adequate price reporting litigation beginning 2003 several lawsuits filed el paso marketing lp epm alleging el paso epm energy companies conspired manipulate price natural gas providing false price information industry trade publications published gas indices first set cases involving similar allegations behalf commercial residential customers transferred multidistrict litigation proceeding mdl us district court nevada styled western states wholesale natural gas antitrust litigation cases dismissed us court appeals ninth circuit however reversed dismissal ordered cases remanded trial court second set cases also involve similar allegations behalf certain purchasers natural gas include farmland industries v oneok inc et al filed state court wyandotte county kansas july 2005 missouri public service commission v el paso corporation et al filed circuit court jackson county missouri kansas city october 2006 purported class action lawsuits styled leggett et al v duke energy corporation et al filed chancery court tennessee january 2005 everbloom inc et al v aep energy services inc et al filed federal court eastern district california september 2005 learjet inc et al v oneok inc et al filed state court wyandotte county kansas september 2005 breckenridge et al v oneok inc et al filed state court denver county colorado may 2006 arandell et al v xcel energy et al filed circuit court dane county wisconsin december 2006 heartland et al v oneok inc et al filed circuit court buchanan county missouri march 2007 leggett case dismissed tennessee state court october 2008 tennessee court appeals reversed dismissal remanding matter trial court decision appealed tennessee supreme court missouri public service case transferred mdl remanded back state court motion dismiss granted dismissal appealed remaining cases transferred mdl proceeding breckenridge case dismissed el paso defendants motion reconsideration decision denied ruling still appealed discovery proceeding mdl cases reached agreement principle settle western states everbloom cases established accruals cases believe adequate settlement documents drafted costs legal exposure related remaining lawsuits claims currently determinable gas measurement cases number subsidiaries named defendants actions generally allege mismeasurement natural gas volumes andor heating content resulting underpayment royalties first set cases filed 1997 individual false claims act consolidated pretrial purposes natural gas royalties qui tam litigation us district court district wyoming complaints allege industrywide conspiracy underreport heating value well volumes natural gas produced federal native american lands october 2006 us district judge issued order dismissing claims defendants appeal filed similar allegations filed set actions initiated 1999 price et al v gas pipelines predecessors et al district court stevens county kansas plaintiffs currently seek certification class royalty owners wells nonfederal nonnative american lands kansas wyoming colorado motions class certification briefed argued proceedings parties awaiting court’s ruling plaintiff seeks unspecified amount monetary damages form additional royalty payments along interest expenses punitive damages injunctive relief regard future gas measurement practices costs legal exposure related lawsuits claims currently determinable mtbe certain subsidiaries used produced sold distributed methyl tertiarybutyl ether mtbe gasoline additive various lawsuits filed throughout us regarding potential impact mtbe water supplies lawsuits brought different parties including state attorney generals water districts individual water companies sought different remedies including remedial activities damages attorneys’ fees costs cases initially consolidated pretrial purposes multidistrict litigation us district court southern district new york several cases later remanded state court recently settled 59 lawsuits payments made october 2008 payments covered insurance payments funded insurers following settlements 27 lawsuits remain damages claimed remaining actions substantial remains significant legal uncertainty regarding validity causes action asserted availability relief sought tender remaining cases insurers likely insurers assert denial coverage six mostrecently filed cases costs legal exposure related remaining lawsuits currently determinable government investigations inquiries reserve revisions march 2004 received subpoena sec requesting documents relating december 31 2003 natural gas oil reserve revisions originally selfreported matter sec cooperated sec investigation july 10 2008 sec approved settlement entered el paso two subsidiaries el paso exploration production el paso cgp formerly known “the coastal corporation” fully resolves previously disclosed sec’s investigation oil gas reserve estimates periods prior 2004 pursuant terms settlement monetary fine penalty imposed upon companies without admitting denying wrongdoing companies consented entry cease desist order respect various provisions securities act 1933 securities exchange act 1934 related sec rules addition proceedings subsidiaries affiliates named defendants numerous lawsuits governmental proceedings claims arise ordinary course business also regulatory rules orders various stages adoption review andor implementation matters evaluate merits case claim exposure matter possible legal settlement strategies likelihood unfavorable outcome determine unfavorable outcome probable estimated establish necessary accruals outcome matters including discussed cannot predicted certainty still uncertainties related costs may incur based upon evaluation experience date believe established appropriate reserves matters possible however new information future developments could require us reassess potential exposure related matters adjust accruals accordingly adjustments could material december 31 2008 approximately 87 million accrued reduced 14 million related insurance receivables outstanding legal governmental proceedings rates regulatory matters epng rate case june 2008 epng filed rate case ferc required settlement previous rate case filing proposed increase epng’s base tariff rates august 2008 ferc issued order accepting proposed rates effective january 1 2009 subject refund outcome hearing technical conference ferc issued order december 2008 generally accepted epng’s proposals technical conference proceeding ferc appointed administrative law judge decide remaining issues epng unable reach settlement customers upcoming negotiations notice proposed rulemaking october 3 2007 minerals management service mms issued notice proposed rulemaking oil gas sulphur operations outer continental shelf ocs pipelines pipeline rightsofway adopted proposed rules would substantially revise mms ocs pipeline rightsofway regulations proposed rules would effect 1 increasing financial obligations entities like us pipelines pipeline rightsofway ocs 2 increasing regulatory requirements imposed operation maintenance existing pipelines rightsofway ocs 3 increasing requirements preconditions obtaining new rightsofway ocs matter navajo nation approximately 900 looped pipeline miles north mainline epng pipeline system located lands held trust united states benefit navajo nation rightsofway lands crossing navajo nation subject pending renewal application filed 2005 department interior’s bureau indian affairs bia subject final reviews approvals navajo nation epng reached agreement principle terms tribal consent bia’s rightofway grant 2025 epng made payment navajo nation october 2008 covering twelvemonth period october 2009 continue make annual payments per terms definitive agreement filed ferc recovery amounts recent rate case environmental matters subject federal state local laws regulations governing environmental quality pollution control laws regulations require us remove remedy effect environment disposal release specified substances current former operating sites december 31 2008 accrued approximately 204 million environmental matters reduced 22 million amounts paid directly government sponsored programs accrual includes approximately 198 million expected remediation costs associated onsite offsite groundwater technical studies approximately 6 million related environmental legal costs 204 million accrual 17 million reserved facilities currently operate 187 million reserved nonoperating sites facilities shut sold superfund sites estimates potential liability range approximately 204 million approximately 388 million accrual represents combination two estimation methodologies first likely outcome reasonably estimated cost accrued 12 million second likely outcome cannot estimated range costs established 192 million 376 million one amount range likely lower end expected range accrued environmental remediation projects various stages completion recorded liabilities reflect current estimates amounts expend remediate sites however depending stage completion assessment ultimate extent contamination remediation required may known additional assessments occur remediation efforts continue may incur additional liabilities type site reserves based following estimates reasonably possible outcomes reconciliation accrued liability january 1 2008 december 31 2008 millions cercla matters part environmental remediation projects received notice could designated asked information determine whether could designated potentially responsible party prp respect 33 active sites comprehensive environmental response compensation liability act cercla state equivalents sought resolve liability prp sites indemnification third parties settlements provide payment allocable share remediation costs cleanup costs estimates subject revision information becomes available extent remediation required cases asserted defense liability estimates could change moreover liability federal cercla statute joint several meaning could required pay excess pro rata share remediation costs understanding financial strength prps considered appropriate estimating liabilities accruals issues included previously indicated estimates superfund sites 2009 estimate total remediation expenditures approximately 67 million expended government directed cleanup plans addition expect make capital expenditures environmental matters approximately 9 million aggregate years 2009 2013 expenditures primarily relate compliance clean air regulations possible new information future developments could require us reassess potential exposure related environmental matters may incur significant costs liabilities order comply existing environmental laws regulations also possible developments increasingly strict environmental laws regulations orders regulatory agencies well claims damages property environment injuries employees persons resulting current past operations could result substantial costs liabilities future information becomes available relevant developments occur adjust accrual amounts accordingly still uncertainties related ultimate costs may incur based upon evaluation experience date believe reserves adequate greenhouse gas ghg emissions legislative regulatory measures address ghg emissions various phases discussions implementation international national regional state levels measures include kyoto protocol ratified international countries operations mexico brazil egypt united states likely federal legislation requiring ghg controls enacted next years addition epa considering initiating rulemaking regulate ghgs clean air act legislation regulation also various stages discussions implementation many states operate measures include recommendations released western climate initiative regarding capandtrade program targeted emission reductions several states operate western united states well recent legislation enacted california imposes ghg emission reduction targets additionally lawsuits filed seeking force federal government regulate ghg emissions individual companies reduce ghg emissions operations lawsuits may result decisions state federal courts agencies could impact operations ability obtain certifications permits construct future projects costs legal exposure related ghg regulations currently determinable commitments purchase obligations matters operating leases maintain operating leases ordinary course business activities leases include office space operating facilities equipment terms agreements vary 2009 2053 future minimum annual rental commitments operating leases net minimum sublease rentals december 31 2008 follows rental expense lease obligations years ended december 31 2008 2007 2006 39 million 40 million 43 million guarantees indemnifications involved various joint ventures ownership arrangements sometimes require financial performance guarantees financial guarantee obligated make payments guaranteed party fails make payments violates terms financial arrangement performance guarantee provide assurance guaranteed party execute terms contract required perform behalf also periodically provide indemnification arrangements related assets businesses sold arrangements include limited indemnifications income taxes resolution existing disputes environmental matters potential exposure guarantee indemnification agreements range specified amount unlimited dollar amount depending nature claim particular transaction many agreements may specify maximum potential exposure specified duration indemnification obligation circumstances amount duration unlimited arrangements specified dollar amount maximum stated value approximately 797 million primarily relates indemnification arrangements associated sale anr macae power facility brazil legacy assets amounts exclude guarantees issued related letters credit discussed note 12 included maximum stated value certain indemnification agreements expired however claims made prior expiration related claim periods unable estimate maximum exposure guarantee indemnification agreements provide limits amount future payments due uncertainty exposures december 31 2008 recorded obligations 62 million related indemnification arrangements liability consists primarily indemnification one subsidiaries provided related sale ammonia facility reflected financial statements estimated fair value provided partial parental guarantee subsidiary’s obligations indemnification believe guarantee indemnification agreements recorded liability probable resulting future losses based assessment nature guarantee financial condition guaranteed party period time guarantee outstanding among considerations purchase obligations 2008 entered contracts purchase pipe primarily associated ruby pipeline project tgp’s 300 line expansion anticipated placed service 2010 2011 estimated obligations agreements approximately 816 million 2009 837 million 2010 105 million 2011 commercial commitments various commercial commitments purchase obligations recorded balance sheet december 31 2008 firm commitments transportation storage capacity contracts 295 million due various times purchase capital commitments including maintenance engineering procurement construction contracts approximately 392 million substantial majority due less one year also hold cancelable easements rightofway arrangements landowners permitting use land construction operation pipeline systems currently obligation easements material results operations however currently negotiating longterm rightofway agreement navajo nation could result significant commitment us see navajo nation 14 retirement benefits overview retirement benefits pension benefits primary pension plan defined benefit plan covers substantially us employees provides benefits cash balance formula certain employees participated prior pension plans el paso sonat inc coastal corporation receive greater cash balance benefits transition benefits prior plan formulas prior december 31 2008 maintained two frozen pension plans provide benefits former employees previously discontinued coal convenience store operations effective december 31 2008 frozen plans merged cash balance plan anticipate making contributions cash balance pension plan 2009 addition primary pension plan maintain supplemental executive retirement plan serp provides additional benefits selected officers key management serp provides benefits excess certain irs limits essentially mirror primary pension plan expect contribute 4 million serp 2009 retirement savings plan maintain defined contribution plan covering us employees match 75 percent participant basic contributions six percent eligible compensation make additional discretionary matching contributions depending performance relative peers amounts expensed plan approximately 20 million 16 million 30 million years ended december 31 2008 2007 2006 postretirement benefits provide postretirement benefits opeb including medical benefits closed groups retired employees limited postretirement life insurance benefits current retired employees medical benefits closed groups retirees may subject deductibles copayment provisions limitations dollar caps amount employer costs reserve right change benefits opeb regulated pipeline companies prefunded extent costs recoverable rates extent opeb costs regulated pipeline companies differ amounts recovered rates regulatory asset liability recorded expect contribute 50 million postretirement benefit plans 2009 matters various court rulings prior march 2008 required indemnify case corporation certain benefits paid closed group case retirees discussed note 13 conjunction rulings recorded liability estimated amounts due indemnification using actuarial methods similar used estimating postretirement benefit plan obligations liability however included postretirement benefit obligations disclosures 2007 first quarter 2008 received summary judgment trial court matter thus became primary party obligated pay benefit payments result judgment adjusted obligation using current actuarial assumptions recording 65 million reduction current noncurrent liabilities operation maintenance expense also reclassified obligation indemnification liability postretirement benefit obligation increased overall postretirement benefit obligations 280 million pension postretirement benefits effective december 31 2006 began accounting pension postretirement benefit plans recognition provisions sfas 158 sfas 158 record asset liability pension postretirement benefit plans based funded status deferred amounts related unrecognized gains losses changes actuarial assumptions recorded either regulatory asset liability regulated operations accumulated comprehensive income loss component stockholders’ equity nonregulated operations gains losses recognized income statement effective january 1 2008 adopted measurement date provisions sfas 158 changed measurement date pension postretirement benefit plans september 30 december 31 recorded 4 million decrease net income taxes 2 million january 1 2008 accumulated deficit 3 million decrease net income taxes 2 million january 1 2008 accumulated comprehensive loss upon adoption measurement date provisions standard reflect additional three months net periodic benefit cost based september 30 2007 measurement benefit obligationplan assets funded status table provides information pension postretirement benefit opeb plans 2008 adopted measurement date provisions sfas 158 information 2008 presented computed fifteen months ended december 31 2008 2007 information presented computed twelve months ended september 30 2007 1 benefit obligation pension plans represents projected benefit obligation benefit obligation postretirement benefit plans represents accumulated postretirement benefit obligation 2 amounts postretirement benefits shown net subsidy related medicare prescription drug improvement modernization act 2003 3 defer difference actual return plan assets expected return three year period considered inclusion net benefit expense income deferred actuarial gains losses amortized extent remaining unrecognized actual gains losses exceed greater 10 percent benefit obligations market related value plan assets following table details amounts recognized balance sheet december 31 2008 2007 related pension postretirement benefit plans accumulated comprehensive loss december 31 2008 includes approximately 4 million unamortized prior service costs net tax anticipate approximately 27 million accumulated comprehensive loss net tax recognized part net periodic benefit cost 2009 accumulated benefit obligation defined benefit pension plans 20 billion december 31 2008 2007 accumulated benefit obligation defined benefit pension plans whose accumulated benefit obligations exceeded fair value plan assets 20 billion 37 million december 31 2008 2007 accumulated postretirement benefit obligation postretirement benefit plans whose accumulated postretirement benefit obligations exceeded fair value plan assets 552 million 222 million december 31 2008 2007 plan assets primary investment objective plans ensure longterm life plans adequate pool sufficiently liquid assets exists meet benefit obligations participants retirees beneficiaries investment objectives longterm nature covering typical market cycles shortfall investment performance compared investment objectives result general economic capital market conditions result general decline markets debt equity securities fair value plans’ assets funded status pension postretirement benefit plans declined significantly 2008 resulted significant decrease pension assets comprehensive income plans’ assets obligations remeasured december 31 2008 expect make contributions cash balance pension plan 2009 following table provides target actual asset allocations pension postretirement benefit plans december 31 2008 september 30 2007 1 actual allocations different target due market declines discussed expected payment future benefits december 31 2008 expect following payments plans 1 includes reduction years presented participant contributions expected subsidy related medicare prescription drug improvement modernization act 2003 actuarial assumptions sensitivity analysis benefit obligations net benefit cost based actuarial estimates assumptions following table details weightedaverage actuarial assumptions used determining benefit obligation net benefit costs pension postretirement plans 2008 2007 2006 1 expected return plan assets pretax rate return based targeted portfolio investments postretirement benefit plans’ investment earnings subject unrelated business income tax rate 35 expected return plan assets postretirement benefit plans calculated using aftertax rate return actuarial estimates postretirement benefit plans assumed weightedaverage annual rate increase per capita costs covered health care benefits 86 percent gradually decreasing 50 percent year 2015 assumed health care cost trends significant effect amounts reported postretirement benefit plans onepercentage point change assumed health care cost trends would following effects december 31 2008 2007 components net benefit cost income years ended december 31 components net benefit cost income follows 1 permitted amortization prior service cost determined using straightline amortization cost average remaining service period employees expected receive benefits plan case retired participants average remaining life 15 stockholders’ equity share repurchase program 2008 board approved 300 million share repurchase program repurchased approximately 77 million common stock program stated expiration date convertible perpetual preferred stock 2005 issued 750 million convertible perpetual preferred stock dividends preferred stock declared quarterly rate 499 per annum approved board directors dividends accumulate paid share preferred stock convertible holder’s option time subject adjustment 769367 shares common stock certain conditions conversion rate represents equivalent conversion price approximately 1300 per share conversion rate subject adjustment based certain events include limited fundamental changes business mergers business combinations well distributions common stock payment dividends common stock excess specified rate able cause preferred stock converted common stock five years issuance common stock trading premium 130 percent conversion price common preferred stock dividends table shows amount dividends paid declared dollars millions dividends common stock preferred stock treated reduction additional paidincapital since currently accumulated deficit expect dividends paid common preferred stock 2008 taxable stockholders anticipate dividends paid current accumulated earnings profits tax purposes 2008 board directors declared dividends common shareholders 004 per share february march 005 per share july october terms 750000 outstanding shares 499 convertible preferred stock provide conversion ratio preferred stock increase pay quarterly dividends common shareholders excess 004 per share october 2008 january 2009 terms preferred shares also prohibit payment dividends common stock unless paid set aside payment accumulated unpaid dividends preferred stock preceding dividend periods addition although credit facilities contain direct restriction payment dividends included fixed charge calculation fixed charge coverage ratio credit facilities unable comply fixed charge ratio ability pay additional dividends would restricted accumulated comprehensive income following table provides components accumulated comprehensive income loss december 31 16 stockbased compensation overview stockbased compensation plans may issue employees incentive stock options common stock intended qualify section 422 internal revenue code nonqualified stock options restricted stock restricted stock units stock appreciation rights performance shares performance units stockbased awards authorized grant awards approximately 425 million shares common stock current plans includes 35 million shares omnibus plan 25 million shares nonemployee director plan 5 million shares employee stock purchase plan december 31 2008 approximately 22 million shares remain available grant current plans includes approximately 176 million shares omnibus plan 2 million shares nonemployee director plan 24 million shares employee stock purchase plan also approximately 14 million shares stock option awards outstanding granted terminated plans obligate us issue additional shares common stock exercised stock option exercises restricted stock funded primarily issuance new common shares record stockbased compensation expense excluding amounts capitalized operation maintenance expense requisite service period separately vesting portion award net estimates forfeitures actual forfeitures differ estimates additional adjustments compensation expense required future periods nonqualified stock options grant nonqualified stock options employees exercise price equal market value stock grant date stock option awards contractual terms 10 years generally vest equal amounts three years grant date pay dividends unexercised options summary stock option transactions year ended december 31 2008 presented 2008 2007 2006 recognized 21 million 16 million 11 million pretax compensation expense stock options capitalized approximately 4 million 4 million 2 million expense respective year part fixed assets recorded 7 million 6 million 4 million income tax benefits total compensation cost related nonvested option awards yet recognized december 31 2008 approximately 19 million expected recognized weighted average period 10 months options exercised year ended december 31 2008 2007 2006 total intrinsic value approximately 10 million 6 million 5 million generated 11 million 7 million 6 million cash proceeds generate significant associated income tax benefit fair value assumptions fair value stock option granted estimated date grant using blackscholes optionpricing model based several assumptions based management’s best estimate time grant years ended december 31 2008 2007 2006 weighted average grant date fair value per share options granted 573 553 489 listed weighted average assumption based grants fiscal year estimate expected volatility based analysis implied volatilities traded options common stock historical stock price volatility expected term adjusted certain time periods believe representative future stock performance prior january 1 2006 estimated expected volatility based primarily adjusted historical stock price volatility effective january 1 2006 adopted provisions sec staff accounting bulletin sab 107 estimate expected term option awards based vesting period average remaining contractual term continue use approach stock option contracts consistent sec sab 110 share based payment allows us continue use “simplified method” estimating expected term consistent manner determined expected term sab 107 use method provide reasonable basis estimating expected term based lack sufficient historical data due significant changes composition employees receiving stockbased compensation awards prior 2006 restricted stock may grant shares restricted common stock carry voting dividend rights officers employees sale transfer shares restricted vest currently outstanding grant timebased restricted stock fair value timebased restricted shares determined grant date shares generally vest equal amounts three years date grant summary changes nonvested restricted shares fiscal years presented weighted average grant date fair value per share restricted stock granted 2008 2007 2006 1546 1473 1309 total fair value shares vested 2008 2007 2006 29 million 31 million 24 million 2008 2007 2006 recognized approximately 29 million 25 million 17 million pretax compensation expense restricted share awards capitalized approximately 7 million 2008 7 million 2007 2 million 2006 part fixed assets recorded 10 million 9 million 6 million income tax benefits related restricted stock arrangements total unrecognized compensation cost related arrangements december 31 2008 approximately 25 million expected recognized weighted average period 10 months employee stock purchase plan employee stock purchase plan allows participating employees right purchase common stock 95 percent market price last trading day month plan noncompensatory provisions sfas 123r shares issued plan insignificant 2008 2007 2006 17 business segment information december 31 2008 business consists two core segments pipelines exploration production also marketing power segments strategic business units provide variety energy products services managed separately segment requires different technology marketing strategies corporate activities include general administrative functions well miscellaneous businesses various contracts assets immaterial discussion segment follows pipelines provides natural gas transmission storage related services primarily united states december 31 2008 conducted activities primarily seven wholly majority owned interstate pipeline systems equity interests four transmission systems also interests two underground natural gas storage facilities two lng terminalling facilities one construction exploration production engaged exploration acquisition development production natural gas oil ngl united states brazil egypt marketing markets manages price risks associated natural gas oil production well manages remaining legacy trading portfolio power manages risks associated remaining international power assets investments located primarily south america asia continue pursue sale assets customers whose revenues exceeded 10 percent total revenues 2008 2007 2006 management uses earnings interest expense income taxes ebit measure assess operating results effectiveness business segments consist consolidated businesses investments unconsolidated affiliates believe ebit useful investors allows evaluate effectively operating performance using performance measure analyzed internally management define ebit net income loss adjusted items impact income loss continuing operations discontinued operationsii interest debt expense iii income taxes exclude interest debt expense investors may evaluate operating results without regard financing methods capital structure ebit may comparable measures used companies additionally ebit considered conjunction net income performance measures operating income operating cash flow reconciliation ebit income continuing operations periods ended december 31 following tables reflect segment results three years ended december 31 1 includes eliminations intercompany transactions intersegment revenues along intersegment operating expenses incurred normal course business operating segments recorded intersegment revenue elimination 19 million 2 revenues external customers include gains losses related price risk management activities associated natural gas oil production intersegment revenues represent sales marketing segment responsible marketing significant portion production third parties 3 total foreign assets approximately 03 billion relates property plant equipment approximately 05 billion relates investments advances unconsolidated affiliates 4 amounts net third party reimbursements capital expenditures returns invested capital 1 includes eliminations intercompany transactions intersegment revenues along intersegment operating expenses incurred normal course business operating segments recorded intersegment revenue elimination 19 million operation maintenance expense elimination 1 million included “corporate” column remove intersegment transactions 2 revenues external customers include gains losses related price risk management activities associated natural gas oil production intersegment revenues represent sales marketing segment responsible marketing significant portion production third parties 3 total foreign assets approximately 06 billion relates property plan equipment approximately 06 billion relates investments advances unconsolidated affiliates 4 amounts net third party reimbursements capital expenditures returns invested capital 5 includes debt extinguishment costs 86 million related refinancing epep’s 12 billion notes also includes 77 million income related reversal liability related legacy crude oil marketing trading business matter 1 includes eliminations intercompany transactions intersegment revenues along intersegment operating expenses incurred normal course business operating segments recorded intersegment revenue elimination 37 million operation maintenance expense elimination 13 million included “corporate” column remove intersegment transactions 2 revenues external customers include gains losses related price risk management activities associated natural gas oil production intersegment revenues represent sales marketing segment responsible marketing significant portion production third parties 3 excludes assets discontinued operations 4133 million 4 approximately 04 billion total foreign assets relates property plant equipment approximately 07 billion relates investments advances unconsolidated affiliates 5 amounts net third party reimbursements capital expenditures returns invested capital 18 investments earnings transactions unconsolidated affiliates hold investments unconsolidated affiliates accounted using equity method accounting earnings unconsolidated affiliates reflected income statement include share net earnings directly attributable unconsolidated affiliates ii impairments adjustments recorded us investment balance differs underlying net equity investments due primarily purchase price adjustments impairment charges recorded us december 31 2008 2007 investment balance exceeded net equity underlying net assets investments 481 million 377 million due items majority purchase price adjustments related investment four star acquired 2005 generally amortize assess recoverability amount based development production underlying estimated proved natural gas oil reserves four star information related unconsolidated affiliates includes net investment earnings losses recorded investments ii summarized financial information proportionate share investments iii revenues charges unconsolidated affiliates net ownership interest investments earnings losses unconsolidated affiliates follows years ended december 31 received cash distributions dividends unconsolidated affiliates 182 million 223 million years ended december 31 2008 2007 included amounts returns capital 2 million 34 million impairment charges gains losses sales equity investments included earnings losses unconsolidated affiliates 2008 impaired investment four star based decrease fair value resulted declining commodity prices 2007 impaired investments porto velho manaus rio negro based assessment value would receive sale investments due developments power markets brazil gains losses consisted following summarized financial information proportionate share operating results financial position unconsolidated affiliates including hold greater 50 percent interest following table shows revenues charges resulting transactions unconsolidated affiliates accounts receivable sales program several pipeline subsidiaries agreements sell certain accounts receivable qualifying special purpose entities qspes sfas 140 accounting transfers servicing financial assets extinguishments liabilities whose purpose solely invest pipeline receivables december 31 2008 2007 sold approximately 174 million 189 million receivables received cash approximately 82 million 79 million received subordinated beneficial interests approximately 89 million 107 million recognized loss approximately 3 million years conjunction sale qspes also issued senior beneficial interests receivables sold third party financial institution totaled 85 million 80 million december 31 2008 2007 reflect subordinated beneficial interest receivables sold fair value date issued amounts adjusted subsequent collections recorded accounts receivable affiliates balance sheet ability recover carrying value subordinated beneficial interests based collectibility underlying receivables sold qspe’s reflect accounts receivable sold program changes subordinated beneficial interests operating cash flows statement cash flows agreements earn fee servicing accounts receivable performing administrative duties qspes reflected reduction operation maintenance expense income statement fair value servicing administrative agreements well fees earned material financial statements years ended december 31 2008 2007 matters could impact investments listed significant remaining international power investments assets december 31 2008 porto velho december 31 2008 equity investment note receivable porto velho project brazil totaling 178 million february 2009 completed sale interests porto velho partner project 100 million cash 78 million notes receivable buyer’s ability repay notes partially dependent upon profitability porto velho facility may adversely impacted developments brazilian power market developments include potential interconnection facility integrated power grid brazil potential construction new hydroelectric plants northern brazil could impact amount power porto velho would able sell power purchase agreements adverse developments brazilian power market occur ability recover amounts due notes receivable could affected manaus rio negro january 2008 transferred ownership manaus rio negro facilities plants’ power purchaser required power purchase agreements december 31 2008 approximately 49 million brazilian reaisdenominated accounts receivable owed us projects’ terminated power purchase agreements guaranteed purchaser’s parent purchaser withheld payment receivables light brazilian reaisdenominated claims approximately 48 million related plant maintenance purchaser claims performed plants prior transfer inventory levels items process finalizing agreements purchaser would settle outstanding claims allow us recover accounts receivable agreements finalized purchaser agree payment receivables initiate legal action purchaser collect receivables defend claims ultimately seek legal action enforce parental guarantee related receivables reviewed obligations power purchase agreement relation claims accrued obligation uncontested claims believe remaining contested claims without merit ultimate resolution matters unknown time adverse developments related either ability collect amounts due us related dispute could require us record additional losses future fourth quarter 2008 administrative level brazilian tax courts issued ruling manaus rio negro projects 47 million taxes allegedly due capacity payments received plants’ power purchaser 1999 2001 power purchase agreements plants’ power purchaser must reimburse manaus rio negro projects icms taxes capacity payments anticipate settlement agreements described finalized power purchaser confirm responsible amounts related ruling manaus rio negro projects investment bolivia 8 percent interest bolivia brazil pipeline december 31 2008 total investment guarantees related pipeline project approximately 131 million bolivian portion 3 million 2006 bolivian government announced decree significantly increasing interest control bolivia’s oil gas assets second quarter 2008 bolivian government took control majority owner bolivian portion pipeline taken action regard two percent interest portion pipeline continue monitor evaluate potential commercial impact political events bolivia could investment new information becomes available future material developments arise may required record impairment investment argentina approximate 22 percent interest argentina chile pipeline december 31 2008 total investment pipeline project approximately 27 million government argentina issued decrees significantly increasing export taxes natural gas transported argentinatochile pipeline continue monitor evaluate together partners potential impact events argentina could investment discussions group partners regarding sale interest pipeline progressed expect complete sale first half 2009 supplemental selected quarterly financial information unaudited financial information quarter summarized unusual infrequently occurring items respective quarters 2008 2007 december 31 2008 items include total 27 billion domestic international ceiling test charges ii 125 million impairment investment four star iii 201 million marktomarket gains related changes fair value exploration production derivatives designated hedges september 30 2008 items include 214 million marktomarket gains related changes fair value exploration production derivatives designated hedges ii 63 million marktomarket gains pjm power contracts june 30 2008 items include 105 million marktomarket losses pjm power contracts ii 75 million marktomarket losses related changes fair value exploration production derivatives designated hedges march 31 2008 items include 43 million marktomarket losses associated sale legacy ammonia facility september 30 2007 items include 77 million gain income related reversal liability related legacy crude oil marketing trading business matter ii losses 64 million 72 million year ended december 31 2007 related porto velho manaus rio negro projects june 30 2007 items include 86 million loss debt extinguishment relating repurchasing notes el paso exploration production company ii 35 million loss 100 million year ended december 31 2007 pjm power contracts primarily resulting increases installed capacity prices march 31 2007 items include gain 651 million net taxes 356 million sale anr related assets recorded discontinued operations ii loss extinguishment debt 201 million conjunction repurchase 35 billion debt obligations supplemental natural gas oil operations unaudited exploration production segment engaged exploration acquisition development production natural gas oil ngl united states brazil egypt capitalized costs capitalized costs relating natural gas oil producing activities related accumulated depreciation depletion amortization follows december 31 millions total costs incurred costs incurred natural gas oil producing activities whether capitalized expensed follows year ended december 31 millions pursuant full cost method accounting capitalize certain general administrative expenses directly related property acquisition exploration development activities interest costs incurred attributable unproved oil gas properties major development projects oil gas properties table includes capitalized internal general administrative costs incurred connection acquisition development exploration natural gas oil reserves 85 million 69 million 50 million years ended december 31 2008 2007 2006 also capitalized interest 29 million 35 million 30 million years ended december 31 2008 2007 2006 january 1 2009 reserve report amounts estimated spent 2009 2010 2011 develop consolidated worldwide proved undeveloped reserves 245 million 207 million 191 million unevaluated capitalized costs exclude capitalized costs natural gas oil properties amortization various stages evaluation expect majority costs included amortization calculation within three years presented analysis capitalized costs natural gas oil properties year expenditures amortized december 31 2008 pending determination proved reserves millions natural gas oil reserves net quantities proved developed undeveloped reserves natural gas ngl oil condensate changes reserves december 31 2008 presented tables based internal reserve report net proved reserves exclude royalties interests owned others reflect contractual arrangements royalty obligations effect time estimate consolidated reserves consistent estimates reserves filed federal agencies except differences less five percent resulting actual production acquisitions property sales necessary reserve revisions additions reflect actual experience ryder scott independent reservoir engineering firm reports audit committee board directors conducted audit estimates 80 percent consolidated natural gas oil reserves december 31 2008 scope audit performed ryder scott included preparation independent estimate proved natural gas oil reserves estimates fields comprising approximately 80 percent total worldwide present value future cash flows pretax specific fields included ryder scott’s audit represented largest fields based value ryder scott also conducted audit estimates 84 percent proved reserves four star unconsolidated affiliate estimates four star’s proved natural gas oil reserves prepared internal reservoir engineers reflect prepared engineers four star based amount proved reserves determined ryder scott believe reported reserve amounts reasonable ryder scott’s reports included exhibits annual report form 10k 2008 577 bcfe extensions discoveries 201 bcfe related raton area northern new mexico 132 bcfe related rockies however approximately 130 bcfe 132 bcfe related rockies also recorded pricing revision due unfavorable commodity prices december 31 2008 also 99 bcfe extensions discoveries related arklatex area 38 bcfe related mccook area 31 bcfe related zapata area south texas area 22 bcfe related high island gulf mexico 2007 341 bcfe extensions discoveries 80 bcfe related raton area northern new mexico 43 bcfe related mccook area south texas 34 bcfe related zapata area south texas 26 bcfe related success niobrara johnson counties wyoming 22 bcfe related mustang island 739740 block gulf mexico 20 bcfe related victoria area south texas 2006 299 bcfe extensions discoveries 45 bcfe related coal bed methane projects central alabama 37 bcfe related house creek parkman county line areas northeast wyoming 35 bcfe related mccook area south texas 27 bcfe related raton area northern new mexico 18 bcfe related victoria area south texas 18 bcfe related bear creek area northern louisiana 16 bcfe related minden area east texas numerous uncertainties inherent estimating quantities proved reserves projecting future rates production projecting timing development expenditures including many factors beyond control reserve data represents estimates reservoir engineering subjective process estimating underground accumulations natural gas oil cannot measured exact manner accuracy reserve estimate function quality available data engineering geological interpretations judgment estimates proved reserves determined according rules prescribed sec rules indicate standard “reasonable certainty” applied proved reserve estimates concept reasonable certainty implies technical data becomes available positive upward revision likely negative downward revision estimates subject revision based upon number factors including reservoir performance prices economic conditions government restrictions addition results drilling testing production subsequent date estimate may justify revision estimate reserve estimates often different quantities natural gas oil ultimately recovered meaningfulness reserve estimates highly dependent accuracy assumptions based general volume production natural gas oil properties declines reserves depleted except extent conduct successful exploration development activities acquire additional properties containing proved reserves proved reserves decline reserves produced subsequent december 31 2008 major discoveries favorable events affect proved reserves however commodity prices continued decline sustained lower commodity prices could result reduced estimated proved reserves future periods december 2008 securities exchange commission issued final rule adopting revisions oil gas reporting requirements revisions impact determination disclosure oil gas reserves information among things new rules revise definition proved reserves require companies use twelve month average commodity price determining estimated proved reserves rather period end price currently required changes along proposed changes may impact supplemental natural gas oil operations disclosures future provisions final rule effective december 31 2009 cannot applied earlier date results operations results operations producing activities fiscal year follows december 31 millions standardized measure discounted future net cash flows standardized measure discounted future net cash flows relating consolidated proved natural gas oil reserves december 31 follows millions calculations preceding table estimated future cash inflows estimated future production proved reserves computed using yearend prices 571 680 564 per mmbtu natural gas 4460 9598 6105 per barrel oil december 31 2008 2007 2006 united states adjustments transportation charges net prices 512 per mcf gas 3567 per barrel oil 2708 per barrel ngl december 31 2008 may receive amounts different standardized measure discounted cash flow number reasons including price cost changes standardized measure discounted future net cash flows following principal sources change consolidated worldwide standardized measure discounted future net cash flows millions 1 disclosure reflects changes standardized measure calculation excluding effects hedging activities schedule ii el paso corporation valuation qualifying accounts years ended december 31 2008 2007 2006 millions 1 amounts reflect valuation allowances associated brazil net operating losses ceiling test charges 2 amounts net related insurance receivables 3 included settlement shareholder litigation lawsuits 4 amount reclassified sfas 106 liability see note 14 5 2006 2007 recorded reserves rate refunds epng’s rate case settled 2007 refunds paid customers 6 relates primarily sale accounts receivable accounts receivable sales program item 9item 8 financial statements supplementary data index items contained part ii item 8 financial statements supplementary data management’s annual report internal control financial reporting management responsible establishing maintaining adequate internal control financial reporting defined sec rules adopted securities exchange act 1934 amended internal control financial reporting designed provide reasonable assurance regarding reliability financial reporting preparation financial statements external purposes accordance generally accepted accounting principles consists policies procedures • pertain maintenance records reasonable detail accurately fairly reflect transactions dispositions assets • provide reasonable assurance transactions recorded necessary permit preparation financial statements accordance generally accepted accounting principles receipts expenditures made accordance authorizations management directors • provide reasonable assurance regarding prevention timely detection unauthorized acquisition use disposition assets could material effect financial statements supervision participation management including chief executive officer ceo chief financial officer cfo made assessment effectiveness internal control financial reporting december 31 2009 making assessment used criteria established internal control integrated framework issued committee sponsoring organizations treadway commission coso based evaluation concluded internal control financial reporting effective december 31 2009 effectiveness internal control financial reporting december 31 2009 audited ernst young llp independent registered public accounting firm stated report included herein report independent registered public accounting firm board directors stockholders el paso corporation audited accompanying consolidated balance sheets el paso corporation december 31 2009 2008 related consolidated statements income comprehensive income equity cash flows three years period ended december 31 2009 audits also included financial statement schedule listed index item 15a financial statements schedule responsibility company’s management responsibility express opinion financial statements schedule based audits financial statements citrus corp subsidiaries corporation company 50 interest december 31 2009 2008 three years period ended december 31 2009 four star oil gas company corporation company approximately 49 interest december 31 2008 two years period ended december 31 2008 audited auditors whose reports furnished us opinion consolidated financial statements insofar relates amounts included citrus corp subsidiaries four star oil gas company based solely reports auditors consolidated financial statements company’s investments unconsolidated affiliates includes approximately 674 million citrus corp subsidiaries december 31 2009 approximately 744 million citrus corp subsidiaries four star oil gas company combined december 31 2008 company’s earnings unconsolidated affiliates includes approximately 65 million year ended december 31 2009 citrus corp approximately 147 million 149 million years ended december 31 2008 2007 respectively citrus corp subsidiaries four star oil gas company combined audited auditors conducted audits accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements audit also includes assessing accounting principles used significant estimates made management well evaluating overall financial statement presentation believe audits reports auditors provide reasonable basis opinion based audits reports auditors financial statements referred present fairly material respects consolidated financial position el paso corporation december 31 2009 2008 consolidated results operations cash flows three years period ended december 31 2009 conformity us generally accepted accounting principles also opinion related financial statement schedule considered relation basic financial statements taken whole presents fairly material respects information set forth therein discussed note 1 consolidated financial statements effective december 31 2009 company changed reserve estimates related disclosures result adopting new oil gas reserve estimation disclosure requirements effective january 1 2009 company adopted accounting standards presentation disclosure noncontrolling interests financial statements effective january 1 2008 company adopted measurement provisions accounting standards retirement benefits effective january 1 2007 company adopted accounting standards related income tax contingencies also audited accordance standards public company accounting oversight board united states el paso corporation’s internal control financial reporting december 31 2009 based criteria established internal controlintegrated framework issued committee sponsoring organizations treadway commission report dated march 1 2010 expressed unqualified opinion thereon ernst young llp houston texas march 1 2010 report independent registered public accounting firm board directors stockholders el paso corporation audited el paso corporation’s internal control financial reporting december 31 2009 based criteria established internal control integrated framework issued committee sponsoring organizations treadway commission coso criteria el paso corporation’s management responsible maintaining effective internal control financial reporting assessment effectiveness internal control financial reporting included accompanying management’s annual report internal control financial reporting responsibility express opinion company’s internal control financial reporting based audit conducted audit accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether effective internal control financial reporting maintained material respects audit included obtaining understanding internal control financial reporting assessing risk material weakness exists testing evaluating design operating effectiveness internal control based assessed risk performing procedures considered necessary circumstances believe audit provides reasonable basis opinion company’s internal control financial reporting process designed provide reasonable assurance regarding reliability financial reporting preparation financial statements external purposes accordance generally accepted accounting principles company’s internal control financial reporting includes policies procedures 1 pertain maintenance records reasonable detail accurately fairly reflect transactions dispositions assets company 2 provide reasonable assurance transactions recorded necessary permit preparation financial statements accordance generally accepted accounting principles receipts expenditures company made accordance authorizations management directors company 3 provide reasonable assurance regarding prevention timely detection unauthorized acquisition use disposition company’s assets could material effect financial statements inherent limitations internal control financial reporting may prevent detect misstatements also projections evaluation effectiveness future periods subject risk controls may become inadequate changes conditions degree compliance policies procedures may deteriorate opinion el paso corporation maintained material respects effective internal control financial reporting december 31 2009 based coso criteria also audited accordance standards public company accounting oversight board united states 2009 consolidated financial statements el paso corporation report dated march 1 2010 expressed unqualified opinion thereon ernst young llp houston texas march 1 2010 report independent auditors board directors stockholders citrus corp opinion consolidated balance sheets related consolidated statements income comprehensive income stockholders’ equity cash flows presented separately herein present fairly material respects financial position citrus corp subsidiaries “company” december 31 2009 2008 results operations cash flows three years period ended december 31 2009 conformity accounting principles generally accepted united states america financial statements responsibility company’s management responsibility express opinion financial statements based audits conducted audits statements accordance auditing standards generally accepted united states america standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements assessing accounting principles used significant estimates made management evaluating overall financial statement presentation believe audits provide reasonable basis opinion spricewaterhousecoopers llp houston texas february 25 2010 report independent registered public accounting firm stockholders four star oil gas company opinion consolidated balance sheets related consolidated statements income stockholders’ equity cash flows presented separately herein present fairly material respects financial position four star oil gas company “company” subsidiary december 31 2008 2007 results operations cash flows three years period ended december 31 2008 conformity accounting principles generally accepted united states america financial statements responsibility company’s management responsibility express opinion financial statements based audits conducted audits statements accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements assessing accounting principles used significant estimates made management evaluating overall financial statement presentation believe audits provide reasonable basis opinion described notes 3 4 financial statements company significant transactions affiliated companies relationships possible terms transactions would result transactions among wholly unrelated parties pricewaterhousecoopers llp houston texas february 20 2009 el paso corporation consolidated statements income millions except per common share amounts see accompanying notes el paso corporation consolidated balance sheets millions except share per share amounts see accompanying notes el paso corporation consolidated balance sheets millions except share per share amounts see accompanying notes el paso corporation consolidated statements cash flows millions see accompanying notes el paso corporation consolidated statements equity millions except per share amounts see accompanying notes el paso corporation consolidated statements comprehensive income millions see accompanying notes el paso corporation notes consolidated financial statements 1 basis presentation significant accounting policies basis presentation principles consolidation consolidated financial statements prepared accordance united states us generally accepted accounting principles gaap include accounts consolidated subsidiaries elimination significant intercompany accounts transactions certain amounts related noncontrolling interests retrospectively adjusted within consolidated financial statements reflect january 1 2009 adoption new presentation disclosure requirements noncontrolling interests financial statements prior periods also include reclassifications made conform current year presentation none impacted reported net income loss stockholders’ equity consolidate entities either ability control operating financial decisions policies entity ii allocated majority entity’s losses andor returns interests entity determination ability control exert significant influence entity whether allocated majority entity’s losses andor returns involves use judgment apply equity method accounting exert significant influence control policies decisions entity allocated majority entity’s losses andor returns use cost method accounting unable exert significant influence entity use estimates preparation financial statements requires use estimates assumptions affect amounts report assets liabilities revenues expenses disclosures financial statements actual results often differ estimates regulated operations interstate natural gas pipelines storage operations subject jurisdiction federal energy regulatory commission ferc natural gas act 1938 natural gas policy act 1978 energy policy act 2005 pipelines follow financial accounting standards board’s fasb accounting standards regulated operations standards record regulatory assets liabilities would recorded gaap nonregulated entities regulatory assets liabilities represent probable future revenues expenses associated certain charges credits expected recovered refunded customers rate making process items apply regulatory accounting requirements include certain postretirement employee benefit plan costs equity return component regulated capital projects certain costs related gas used operations costs included expected included future rates cash equivalents consider shortterm investments original maturity less three months cash equivalents maintain cash deposit banks insurance companies pledged particular use restricted support potential liability classify balances restricted cash current noncurrent assets balance sheet based expect restrictions cash removed 2 million restricted cash current assets december 31 2009 2008 8 million 57 million noncurrent assets december 31 2009 2008 allowance doubtful accounts establish provisions losses accounts notes receivable natural gas imbalances due shippers operators determine collect part outstanding balance regularly review collectability establish adjust allowance necessary using specific identification method property plant equipment pipelines excluding natural gas oil properties property plant equipment recorded original cost construction upon acquisition fair value assets acquired assets construct capitalize direct costs labor materials indirect costs overhead interest equity return component regulated businesses capitalize major units property replacements improvements expense minor items description methods use depreciate regulated property plant equipment see note 11 included pipeline property balances additional acquisition costs represent excess purchase costs associated purchase business combinations allocated regulated interstate systems’ property plant equipment costs amortized straightline basis recover excess costs rates retire property plant equipment regulated operations charge accumulated depreciation amortization original cost assets addition cost remove sell dispose assets less salvage value recognize gain loss unless sell entire operating unit defined ferc include gains losses dispositions operating units operations maintenance expense income statements natural gas oil properties use full cost method account natural gas oil properties full cost method substantially costs incurred connection acquisition development exploration natural gas oil reserves capitalized countrybycountry basis capitalized amounts include costs unproved properties internal costs directly related acquisition development exploration activities asset retirement costs capitalized interest full cost method dry hole costs geological geophysical costs capitalized full cost pool subject amortization periodically assessed impairment ceiling test calculation discussed capitalized costs associated proved reserves amortized life reserves using unit production method conversely capitalized costs associated unproved properties excluded amortizable base properties evaluated occurs quarterly transfer unproved property costs amortizable base properties determined proved reserves addition countries natural gas oil reserve base exists transfer unproved property costs amortizable base completed evaluation unproved properties determined impaired exploratory wells determined unsuccessful additionally amortizable base includes future development costs dismantlement restoration abandonment costs net estimated salvage values geological geophysical costs incurred cannot associated specific unevaluated properties prospects direct interest capitalized costs country net related deferred income taxes limited ceiling based present value future net revenues proved reserves discounted 10 percent plus cost unproved natural gas oil properties amortized plus lower cost fair value unproved natural gas oil properties included amortizable base less related income tax effects perform ceiling test calculation quarter prior december 31 2009 utilized endofperiod spot prices determine future net revenues result adoption sec’s final rule modernization oil gas reporting effective december 31 2009 required use 12month average price calculated unweighted arithmetic average price first day month within 12month period prior end reporting period calculate ceiling test total capitalized costs exceed ceiling required writedown capitalized costs ceiling required writedown included ceiling test charge income statement increase accumulated depreciation depletion amortization balance sheet prior december 31 2008 ceiling test calculations included effects derivative instruments designated qualified cash flow hedges anticipated future natural gas oil production date calculation fourth quarter 2008 removed hedging designation commoditybased derivative contracts related hedged natural gas oil production volumes ceiling test calculations exclude estimated future cash outflows associated asset retirement liabilities related proved developed reserves sell convey interests natural gas oil properties reduce natural gas oil reserves amount attributable sold conveyed interest recognize gain loss sales natural gas oil properties unless sales would significantly alter relationship capitalized costs proved reserves treat sales proceeds nonsignificant sales adjustment cost properties asset investment divestituresimpairments evaluate assets investments impairment events circumstances indicate carrying values may recovered events include market declines believed temporary changes manner intend use longlived asset decisions sell asset investment adverse changes legal business environment adverse actions regulators event occurs evaluate recoverability carrying value based either longlived asset’s ability generate future cash flows undiscounted basis ii fair value investment unconsolidated affiliate impairment indicated decide sell longlived asset group assets adjust carrying values asset downward necessary estimated fair value fair value estimates generally based market data obtained sales process analysis expected discounted cash flows magnitude impairment impacted number factors including nature assets sold established time frame completing sale among factors reclassify assets sold financial statements either heldforsale discontinued operations becomes probable dispose assets within next twelve months meet criteria including whether significant longterm continuing involvement assets sold cease depreciating assets period reclassified either held sale discontinued operations reflect results discontinued operations income statement separately continuing operations cash flows discontinued businesses reflected discontinued operating investing financing activities statement cash flows cash provided used discontinued activities operating activities section cash flow statement includes operating cash flows generated discontinued businesses period proceeds sale discontinued operations classified cash provided discontinued activities cash flows investing activities section cash flow statement extent operations participated cash management program reflect transactions related cash management program financing activities cash flow statement cease depreciating assets period reclassified either held sale discontinued operations pension postretirement benefits maintain several pension postretirement benefit plans make contributions plans required fund benefits paid participants retirees contributions invested benefits paid plan participants record net benefit cost related plans income statement net benefit cost function many factors including benefits earned year plan participants function employee’s salary level benefits provided plan actuarial assumptions passage time expected returns plan assets amortization certain deferred gains losses discussion policies respect pension postretirement benefit plans see note 14 accounting pension postretirement benefit plans record asset liability based funded status plan deferred amounts related unrecognized gains losses changes actuarial assumptions recorded either regulatory asset liability regulated operations accumulated comprehensive income loss component stockholders’ equity operations gains losses recognized income statement effective december 31 2009 expanded disclosures postretirement benefit plan assets result new disclosure requirements see note 14 expanded disclosures effective january 1 2008 adopted measurement provisions accounting standards retirement benefits resulted change measurement date pension postretirement benefit plans september 30 december 31 recorded 4 million decrease net income taxes 2 million january 1 2008 accumulated deficit 3 million decrease net income taxes 2 million january 1 2008 accumulated comprehensive loss upon adoption provisions reflect additional three months net periodic benefit income based september 30 2007 measurement revenue recognition business segments provide number services sell variety products record revenues products services include estimates amounts earned unbilled estimate unbilled revenues based contractual data regulatory information commodity prices preliminary throughput allocation measurements among items revenue recognition policies significant operating segments follows pipelines revenues pipelines segment derives revenues primarily transportation storage services revenues services generally based thermal quantity gas delivered subscribed price specified contract transportation storage services recognize reservation revenues firm contracted capacity ratably contract period regardless amount natural gas transported stored interruptible volumetric based services record revenues physical deliveries natural gas made agreed upon delivery point gas injected withdrawn storage facility gas used operations based volumes allowed retain relative amounts gas use operating purposes recognize revenue gas used operations shippers ferc allows us retain volumes market prices required tariffs subject ferc regulations result revenues collect rate proceedings may subject refund establish reserves potential refunds exploration production revenues exploration production segment derives revenues primarily physical sale natural gas oil condensate natural gas liquids revenues sales products recorded upon delivery passage title using sales method net royalty interests profit interests produced product actual sales volumes exceed entitled share sales volumes overproduced imbalance occurs extent overproduced imbalance exceeds share remaining estimated proved reserves given property record liability costs associated transportation delivery production included cost products services marketing revenues marketing segment derives revenues physical natural gas power transactions management derivative contracts derivative transactions recorded fair value changes fair value reflected net operating revenues discussion income recognition policies derivatives see price risk management activities impact nonderivative transactions including transportation contracts recognized net operating revenues based contractual market price related volumes time commodity delivered contracts terminated environmental costs contingencies environmental costs record liabilities undiscounted amounts balance sheet current longterm liabilities environmental assessments indicate remediation efforts probable costs reasonably estimated estimates liabilities based currently available facts existing technology presently enacted laws regulations taking consideration likely effects societal economic factors include estimates associated legal costs amounts also consider prior experience remediating contaminated sites companies’ cleanup experience data released environmental protection agency organizations estimates subject revision future periods based actual costs new circumstances capitalize costs benefit future periods recognize current period charge operation maintenance expense cleanup efforts benefit future periods evaluate amounts paid directly reimbursed government sponsored programs potential recoveries reimbursements remediation costs third parties including insurance coverage separately liability recovery evaluated based creditworthiness solvency third party among factors recovery assured record report asset separately associated liability balance sheet contingencies recognize liabilities contingencies exposure fully analyzed indicates probable liability incurred amount loss reasonably estimated likely outcome contingency reasonably estimated accrue liability amount likely outcome cannot estimated range potential losses established one amount range likely low end range accrued price risk management activities price risk management activities relate primarily derivatives entered hedge otherwise reduce commodity exposure natural gas oil production interest rate foreign currency exposure longterm debt also hold derivatives intended hedge exposures including related legacy trading activities derivatives reflected balance sheet fair value assets liabilities price risk management activities cash collateral associated derivatives significant financial statements classify derivatives either current noncurrent assets liabilities based anticipated settlement date net derivative assets liabilities counterparties legal right offset see note 8 discussion price risk management activities derivatives designated accounting hedges impact revenues expenses based nature timing transactions hedge derivatives designated hedges markedtomarket period changes fair value well realized amounts generally reflected operating revenues exploration production segment marketing segment cash flow statement cash inflows outflows associated settlement derivative instruments recognized operating cash flows derivatives intended hedge principal amounts foreign currency denominated debt balance sheet receivables payables resulting settlement derivative instruments reported trade receivables payables income taxes record current income taxes based current taxable income provide deferred income taxes reflect estimated future tax payments receipts deferred taxes represent tax impacts differences financial statement tax bases assets liabilities carryovers year end account tax credits flowthrough method reduces provision income taxes year tax credits first become available reduce deferred tax assets valuation allowance based estimates likely portion assets realized future period estimates utilized recognition deferred tax assets subject revision either future periods based new facts circumstances 2007 adopted new accounting standards required us evaluate tax positions jurisdictions years statute limitations expired required meet “morelikelythannot” threshold ie greater 50 percent likelihood tax position sustained examination prior recording tax benefit additionally tax positions meeting “morelikelythannot” threshold amount benefit limited largest benefit greater 50 percent probability realized upon effective settlement accounting asset retirement obligations record liability legal obligations associated replacement removal retirement longlived assets period obligation incurred asset retirement liabilities initially recorded estimated fair value corresponding increase property plant equipment increase property plant equipment depreciated useful life asset liability relates ongoing expense also recognized changes value liability result passage time record depreciation depletion amortization expense income statement regulated pipelines ability recover certain costs customers recorded asset rather expense associated accretion liabilities described accounting stockbased compensation measure employee stockbased compensation awards fair value date awards granted employees recognize compensation cost financial statements requisite service period additional information stockbased compensation awards see note 16 new accounting pronouncements issued yet adopted december 31 2009 following accounting standards yet adopted us transfers financial assets june 2009 fasb updated accounting standards financial asset transfers among items update eliminated concept qualifying specialpurpose entity qspe purposes evaluating whether entity consolidated changes effective existing qspes january 1 2010 transactions entered january 1 2010 adoption accounting standard january 2010 material impact financial statements amended existing accounts receivable sales programs january 2010 information see note 18 variable interest entities june 2009 fasb updated accounting standards variable interest entities revise companies determine primary beneficiary entities among changes companies required use qualitative approach based responsibilities power entities’ operations rather quantitative approach determining primary beneficiary previously required adoption accounting standard january 2010 material impact financial statements 2 acquisitions divestitures acquisitions gulf lng february 2008 paid approximately 295 million complete acquisition 50 percent interest gulf lng clean energy project lng terminal currently construction pascagoula mississippi terminal expected placed service late 2011 addition commitment loan gulf lng 150 million advanced approximately 56 million 26 million december 31 2009 2008 partner project commitment loan 64 million account investment gulf lng using equity method exploration production properties 2009 acquired domestic natural gas oil properties approximately 92 million including producing properties approximately 87 million located primarily altamontbluebellcedar rim field utah 2008 acquired interests domestic natural gas oil properties 61 million including producing properties 51 million 2007 acquired operated natural gas oil producing properties undeveloped acreage south texas 254 million also acquired peoples energy production company peoples 887 million peoples exploration production company natural gas oil properties located primarily arklatex texas gulf coast mississippi areas san juan arkoma basins divestitures 2009 2008 2007 sold number assets investments proceeds follows exploration production assets sold 2009 consisted natural gas producing properties central western divisions assets sold 2008 consisted primarily natural gas oil properties gulf coast division power assets sold 2009 consisted investment argentinatochile pipeline interest porto velho power generation facility brazil assets sold 2008 consist power investments central america asia pipelines assets sold consisted primarily certain facilities pipeline laterals assets sold consisted primarily fuel oil terminal 2008 noncore investment 2007 discontinued operations assets held sale february 2007 sold anr michigan storage assets 50 percent interest great lakes gas transmission approximately 37 billion recorded gain sale 648 million net taxes 354 million summarized operating results anr related operations follows 1 includes loss approximately 19 million associated extinguishment certain debt obligations 3 ceiling test charges required conduct quarterly impairment tests capitalized costs full cost pools years ended december 31 2009 2008 recorded following ceiling test charges third quarter 2009 quarterly impairment tests based spot commodity prices end period result sec’s final rule modernization oil gas reporting effective december 31 2009 required use 12month average price calculated unweighted arithmetic average price first day month within 12month period prior end reporting period performing ceiling tests calculating ceiling test charges also required hold prices constant life reserves even though actual prices natural gas oil volatile change period 4 income expenses following components income expenses three years ended december 31 5 income taxes pretax income loss income tax expense benefit tables show pretax income loss continuing operations components income tax expense benefit years ended december 31 effective tax rate reconciliation income taxes included income continuing operations differs amount computed applying statutory federal income tax rate 35 percent following reasons three years ended december 31 2009 effective tax rate higher statutory rate primarily due recording 88 million income tax benefit relating us tax loss liquidation certain foreign entities following 2009 sale remaining significant noncore international power projects entities liquidating value entities tax basis liquidation resulted tax loss 2008 overall effective tax rate differed statutory rate due primarily 05 billion ceiling test charge brazilian full cost pool corresponding us brazilian tax benefit impact ceiling test charge effective tax rate included foreign income loss taxed different rates valuation allowances table believe certain unconsolidated affiliates’ undistributed earnings ultimately distributed us dividends would eligible dividends received deduction joint venture partners intent ability recover cumulative undistributed earnings time dividends structured sale would result additional deferred tax liabilities december 31 2009 undistributed earnings unconsolidated affiliates expect receive dividends received deduction approximately 360 million deferred tax assets liabilities following components net deferred tax liability december 31 cumulative undistributed earnings substantially foreign subsidiaries foreign corporate joint ventures intended indefinitely reinvested foreign operations therefore provision made us taxes foreign withholding taxes may applicable upon actual deemed repatriation estimate taxes earnings repatriated practical december 31 2009 portion cumulative undistributed earnings investments recorded us income taxes approximately 85 million unrecognized tax benefits liabilities uncertain tax matters subject taxation us various states foreign jurisdictions exceptions longer subject state local foreign income tax examinations tax authorities years prior 1999 us income tax examinations years prior 2007 november 2009 internal revenue service’s irs examination el paso’s us income tax returns 2005 2006 settled appellate level settlement issues raised examination 12 million positive impact results operations materially impact financial condition liquidity years returns still subject review unrecognized tax benefits liabilities uncertain tax matters could increase decrease income tax expense effective income tax rates matters finalized currently unable estimate range potential impacts resolution contested matters could financial statements following table shows change unrecognized tax benefits december 31 2009 2008 approximately 258 million 169 million net federal tax benefits unrecognized tax benefits would affect income tax expense effective income tax rate recognized future periods significant increase primarily pertains uncertainties related us tax loss liquidation certain foreign entities amount unrecognized tax benefits could change next twelve months expect change significant impact results operations financial position recognize accrued interest related unrecognized tax benefits penalties income tax expense 2009 2008 2007 recognized 3 million 4 million 6 million interest penalties related unrecognized tax benefits noted 52 million 49 million accrued payment interest penalties december 31 2009 2008 tax credit net operating loss carryovers december 31 2009 us federal alternative minimum tax credits 295 million carryover indefinitely table presents details federal state net operating loss carryover periods december 31 2009 also 512 million foreign net operating loss carryovers 71 million foreign capital loss carryovers carryover indefinitely usage us federal carryovers subject limitations provided sections 382 383 internal revenue code well separate return limitation year rules irs regulations valuation allowances deferred tax assets recorded net operating losses temporary differences book tax basis assets liabilities expected produce tax deductions future periods realization assets depends recognition sufficient future taxable income specific tax jurisdictions periods temporary differences net operating losses deductible assessing need valuation allowance deferred tax assets consider whether likely portion realized part assessment consider future reversals existing taxable temporary differences primarily related depreciation december 31 2009 valuation allowance primarily relates deferred tax assets recorded state foreign net operating losses temporary differences 2009 increased valuation allowance 93 million deferred tax assets associated brazil egypt net operating losses reduced valuation allowance 46 million deferred tax assets associated expiring state net operating losses 2008 provided valuation allowance 202 million deferred tax assets associated brazil net operating losses ceiling test charges valuation allowance established primarily result changes worldwide economic conditions creating uncertainty outlook future taxable income particular tax jurisdiction believe likely realize benefit deferred tax assets net existing valuation allowances 6 earnings per share calculated basic diluted earnings per common share follows three years ended december 31 exclude potentially dilutive securities determination diluted earnings per share well related income statement impacts impact net income attributable el paso corporation per common share antidilutive potentially dilutive securities consist employee stock options restricted stock convertible preferred stock trust preferred securities years ended december 31 2009 2008 incurred losses attributable el paso corporation accordingly excluded potentially dilutive securities determination diluted earnings per share impact loss per common share antidilutive year ended december 31 2007 certain employee stock options trust preferred securities convertible preferred stock antidilutive discussion capital stock activity stockbased compensation arrangements instruments noted see notes 15 16 7 fair value financial instruments january 1 2008 adopted new fair value accounting reporting standards expanded disclosure requirements financial instruments derivatives recorded fair value also required company’s credit risk considered determining fair value instruments adoption standards resulted 6 million increase operating revenues 4 million pretax increase comprehensive income 10 million reduction liabilities reflect consideration credit risk liabilities recorded fair value considering collateral related positions january 1 2009 adopted new accounting reporting standards nonfinancial assets liabilities measured fair value nonrecurring basis primarily relates impairment longlived assets investments year ended december 31 2009 nonfinancial assets liabilities recorded fair value subsequent initial measurement january 1 2009 also adopted accounting standard updates regarding companies consider credit determining fair value liabilities third party credit enhancements related substantially derivative liabilities marketing segment supported letters credit accounting standard updates noncash credit enhancements letters credit considered determining fair value liabilities including derivative liabilities accordingly recorded 34 million gain net 18 million taxes 005 per share 2009 result adopting new accounting updates use various methods determine fair values financial instruments derivatives measured fair value recurring basis depend number factors including availability observable market data contractual term underlying instrument instruments fair value calculated based directly observable market data available similar instruments similar markets instruments fair value may calculated based inputs well assumptions related estimates future settlements instruments separate financial instruments derivatives three levels 1 2 3 based assessment availability observable market data significance nonobservable data used determine fair value instruments assessment instrument change time based maturity liquidity instrument could result change classification instruments levels corresponding instruments classified level described • level 1 instruments’ fair values based quoted prices instruments actively traded markets included level marketable securities invested nonqualified compensation plans whose fair value determined using quoted prices • level 2 instruments’ fair values primarily based pricing data representative quoted prices similar assets liabilities active markets identical assets liabilities less active markets included level interest rate swaps productionrelated natural gas oil derivatives certain natural gas derivatives natural gas supply arrangements whose fair values based commodity pricing data obtained third party pricing sources fair values also consider creditworthiness counterparties adjusted collateral related asset positions • level 3 instruments’ fair values partially calculated using pricing data similar level 2 fair value also reflects adjustments less liquid markets longer contractual terms instruments obtain pricing data third party pricing sources adjust data based liquidity underlying forward markets contractual terms use adjusted pricing data develop estimate forward price curves market participants would use curves used estimate value settlements future periods based contractual settlement quantities dates valuation instruments considers specific contractual terms statistical simulation analysis present value concepts internal assumptions related contract maturities extend beyond periods quoted market prices available ii uniqueness contract terms iii limited availability forward pricing information markets lack viable participants pennsylvanianew jerseymaryland pjm forward power market forward market ammonia iv creditworthiness counterparties adjusted collateral related asset positions since significant portion fair value powerrelated derivatives certain remaining natural gas derivatives longer terms less liquid markets similar level 2 derivatives rely techniques discussed classify instruments level 3 instruments listed fair values financial instruments recorded fair value classified level december 31 2009 2008 millions following table presents changes financial assets liabilities included level 3 year ended december 31 2009 millions certain derivative contracts recorded assets table exposed risk counterparties may perform post required collateral us assessed counterparty risk light collateral counterparties posted us based assessment determined exposure primarily related productionrelated derivatives limited eight financial institutions current standard poor’s credit rating better following table reflects carrying value fair value financial instruments december 31 2009 2008 carrying amounts cash equivalents shortterm borrowings trade receivables payables represented fair value shortterm nature instruments carrying amounts restricted cash noncurrent receivables approximate fair value based interest rates assessment ability recover amounts estimated fair value debt based quoted market prices similar issues including consideration credit risk related instruments 8 price risk management activities price risk management activities relate primarily derivatives entered hedge otherwise reduce commodity price exposure natural gas oil production ii interest rate exposure longterm debt iii foreign currency exposure eurodenominated debt also hold derivatives intended hedge exposures including related legacy trading activities enter derivative contracts may designate derivative either cash flow hedge fair value hedge time document intent hedges cash flow exposure designed hedge forecasted sales transactions limit variability cash flows received paid related recognized asset liability hedges fair value exposure entered protect fair value recognized asset liability firm commitment productionrelated derivatives attempt mitigate commodity price risk stabilize cash flows associated forecasted sales natural gas oil production use derivative natural gas oil swaps basis swaps option contracts derivatives mitigate commodity price risks sales natural gas oil production result subject commodity price risks remaining forecasted production prior removing accounting hedge designation productionrelated derivatives 2008 certain derivatives designated cash flow hedges december 31 2009 2008 productionrelated derivatives 313 tbtu 187 tbtu natural gas 4016 mbbl 3431 mbbl oil commoditybased derivatives marketing segment longterm natural gas power derivative contracts primarily related legacy trading activities contracts include forwards swaps options either intend manage expiration liquidate extent economical prudent none derivatives designated accounting hedges december 31 2009 2008 commodity based derivative contracts include natural gas contracts obligate us sell natural gas power plants various expiration dates ranging 2012 2019 expected obligations individual contracts third parties ranging 12550 mmbtud 104750 mmbtud ii derivative power contracts require us swap locational differences power prices three power plants pjm eastern region pjm west hub approximately 3700 gwh 2010 2012 2400 gwh 2013 1700 gwh 2014 april 2016 contracts also require us provide approximately 1700 gwh power per year approximately 71 gw installed capacity per year pjm power pool april 2016 natural gas power contracts entered contracts previous years economically mitigate exposure commodity price changes substantially volumes although continue exposure changes locational price differences pjm regions interest rate derivatives longterm debt variable interest rates exposes us changes marketbased interest rates use interest rate swaps convert variable rates certain debt instruments fixed interest rate december 31 2009 2008 interest rate swaps designated cash flow hedges converted interest rate approximately 169 million debt liborbased variable rate fixed rate 456 also longterm debt fixed interest rates exposes us paying higher market rates interest rates decline use interest rate swaps protect value certain debt instruments converting fixed amounts interest due debt agreements variable interest payments record changes fair value derivatives interest expense december 31 2009 2008 interest rate swaps designated fair value hedges convert interest rate approximately 218 million debt fixed rate variable rate libor plus 418 addition december 31 2009 2008 interest rate swaps designated hedges notional amount 222 million changes fair value swaps substantially eliminated offsetting swaps contracts crosscurrency derivatives 2009 eurodenominated debt matured settled related crosscurrency swaps crosscurrency swaps designated fair value hedges debt year ended december 31 2009 swaps increased interest expense approximately 3 million decreased income approximately 26 million result changing interest foreign currency rates 2009 balance sheet presentation derivatives reflected fair value balance sheet assets liabilities price risk management activities net derivative assets liabilities counterparties legal right offset classify derivatives either current noncurrent assets liabilities based anticipated settlement date following table presents fair value derivatives gross basis contract type netted contracts counterparties legal right offset cash collateral associated derivatives december 31 2009 cash collateral held material 1 includes adjustments net assets liabilities reflect master netting arrangements counterparties 2 included current noncurrent liabilities balance sheets statements income comprehensive income cash flow presentation derivatives designated accounting hedges impact revenues expenses based nature timing transactions hedge changes fair value derivatives designated cash flow hedges deferred accumulated comprehensive income loss extent effective recognized earnings hedged transactions occur ineffectiveness related cash flow hedges recognized earnings occurs changes fair value derivatives designated fair value hedges recognized earnings offsets changes fair value related hedged assets liabilities firm commitments interest rate derivatives significant impact interest expense comprehensive income loss 2009 record ineffectiveness derivatives 2009 fair value interest rate derivatives designated cash flow hedges liability approximately 16 million december 31 2009 anticipate accumulated comprehensive loss associated derivatives reclassified interest expense next twelve months significant financial statements derivatives designated accounting hedges markedtomarket period changes fair value generally reflected operating revenues cash flow statement cash inflows outflows associated settlement derivative instruments recognized operating cash flows derivatives intended hedge principal amounts foreign currency denominated debt recorded financing activities listed impacts commoditybased derivatives income statement comprehensive income year ended december 31 2009 1 included operating revenues year ended december 31 2009 406 million representing amount accumulated comprehensive income reclassified income related commoditybased derivatives removed hedging designation fourth quarter 2008 anticipate approximately 13 million accumulated comprehensive loss reclassified operating revenues next twelve months 2 also approximately 21 million gains year ended december 31 2009 recognized operating expenses related derivative instruments associated price risk management activities credit risk subject credit risk related financial instrument assets credit risk relates risk loss would incur result nonperformance counterparties pursuant terms contractual obligations exposures offset legally enforceable right setoff maintain credit policies regard counterparties price risk management activities minimize overall credit risk policies require evaluation potential counterparties’ financial condition including credit rating ii collateral certain circumstances including cash advance letters credit guarantees iii use margining provisions standard contracts iv use master netting agreements allow netting positive negative exposures various contracts associated single counterparty use daily margining provisions financial contracts physical power agreements master netting agreements require counterparty post cash letters credit fair value contract exceeds daily contractual threshold amount typically tied published credit rating counterparty margining collateral provisions also allow us terminate contract liquidate positions counterparty unable provide required collateral margining provisions required return collateral amount posted collateral exceeds amount collateral required collateral received returned vary significantly day based changes market values counterparty’s credit ratings furthermore amount collateral hold may less fair value derivative contracts counterparty given period following table presents summary exposure derivative contracts net collateral liabilities right offset exists presented type derivative counterparty net asset exposure december 31 2009 2008 1 “investment grade” “below investment grade” determined using publicly available credit ratings “investment grade” includes counterparties minimum standard poor’s rating bbb moody’s investor service rating baa3 “below investment grade” includes counterparties public credit rating meet criteria “investment grade” “not rated” includes counterparties rated public rating service approximately 44 counterparties december 31 2009 one counterparties fails perform may recognize immediate loss earnings well additional financial impacts future delivery periods extent replacement contract prices andor quantities cannot established december 31 2009 three counterparties williams gas marketing citibank rri energy services comprise 31 percent 13 percent 11 percent respectively net financial instrument exposure december 31 2008 three counterparties j aron merrill lynch societe generale comprised 30 percent 37 percent 12 percent respectively net financial instrument asset exposure concentration counterparties may impact overall exposure credit risk either positively negatively counterparties may similarly affected changes economic regulatory conditions 9 regulatory assets liabilities regulatory assets liabilities relate interstate pipeline operations included current noncurrent assets liabilities balance sheets balances recoverable reimbursable various periods details regulatory assets liabilities december 31 significant regulatory assets liabilities include difference gas retained gas consumed operations amounts reflect value volumetric difference gas retained customers gas consumed operations amounts included rate base expected recoveredrefunded subsequent fuel filing periods taxes capitalized funds used construction regulatory asset balance established offset deferred tax equity component allowance funds used construction longlived assets taxes capitalized funds used construction offsetting deferred income taxes included rate base recovered depreciable lives long lived asset relate postretirement benefits represents deferred amounts related unrecognized gains losses changes actuarial assumptions related postretirement benefit plan differences postretirement benefit related amounts expensed amounts recovered rates postretirement benefit amounts included rate base computations certain pipelines recoverable periods benefits funded unamortized net loss reacquired debt amount represents deferred amortized portion gains losses reacquired debt included rate base recovered original life debt issue authorized rate return gas retained used operations regulatory liabilities related gas retained used operations included rate base given current pipeline tariffs expected returned subsequent fuel filing periods environmental liability includes amounts collected substantially excess certain pcb environmental remediation costs date surcharge tgp’s customers settlement approved ferc november 1995 time environmental liability deducted rate base tgp allowed earn current return property plant depreciation amounts represent 1 deferral customerfunded amounts costs future asset retirements 2 excess ratemaking depreciation expense depreciation expense recorded financial statements amounts included rate base computations depreciationrelated amounts refunded lives longlived assets relate 10 assets liabilities detail current noncurrent assets liabilities balance sheets december 31 11 property plant equipment depreciable lives table presents depreciation method depreciable lives property plant equipment 1 composite group method assets similar useful lives characteristics grouped depreciated one asset apply depreciation rate approved rate settlements total cost group net book value equals salvage value reevaluate depreciation rates time redevelop transportation rates file ferc increase decrease rates 2 capitalized costs associated proved reserves amortized life reserves using unit production method conversely capitalized costs associated unproved properties excluded amortizable base properties evaluated impaired excess purchase costs december 31 2009 2008 tgp epng excess purchase costs associated historical acquisition total excess costs pipelines approximately 25 billion accumulated depreciation approximately 05 billion december 31 2009 2008 excess costs depreciated estimated life pipeline assets costs assigned related depreciation expense year ended december 31 2009 2008 2007 approximately 42 million excess costs recoverable rates current ferc policies capitalized costs construction capitalize carrying cost funds related construction longlived assets reflect increases cost asset balance sheet carrying cost consists interest cost debt could attributed assets constructed ii regulated transmission business return equity could attributed assets constructed debt portion calculated based average cost debt interest costs capitalized included reduction interest expense income statements 48 million 45 million 50 million years ended december 31 2009 2008 2007 equity portion calculated using recent ferc approved equity rate return equity amounts capitalized included nonoperating income statement 61 million 37 million 32 million years ended december 31 2009 2008 2007 construction workin progress december 31 2009 2008 approximately 36 billion 26 billion construction workinprogress included property plant equipment asset retirement obligations legal obligations associated retirement natural gas oil wells related infrastructure natural gas pipelines transmission facilities storage wells obligations related corporate headquarters building exploration production operations obligations plug wells abandoned production exhausted longer plan use wells pipeline operations legal obligations primarily involve purging sealing pipelines abandoned also obligations remove hazardous materials associated natural gas transmission facilities corporate headquarters facilities ever demolished replaced renovated continue evaluate asset retirement obligations future developments could impact amounts record reasonably estimate asset retirement obligation accrue liability based estimate timing amount settlement estimating asset retirement obligations utilize several assumptions including projected inflation rate 25 percent creditadjusted discount rates currently range 6 12 percent based liabilities recorded record changes estimates based changes expected amount timing payments settle obligations typically changes result obtaining new information exploration production segment timing obligations plug abandon natural gas oil wells costs certain events accelerate timing asset retirements eg impact hurricanes exploration production segment pipelines segment pipelines operations intend operating maintaining natural gas pipeline storage systems long supply demand natural gas exists expect foreseeable future therefore believe cannot reasonably estimate asset retirement obligation substantial majority natural gas pipeline storage system assets indeterminate lives net asset retirement obligation december 31 reported balance sheet current noncurrent liabilities changes net liability years ended december 31 follows 12 debt financing obligations credit facilities following provides additional detail longterm financing obligations 1 amounts drawn commitment convertible preferred equity interest ruby pipeline holding company llc ruby subject satisfaction certain conditions information see note 18 changes longterm financing obligations 2009 following changes longterm financing obligations millions 1 principal amount notes 500 million el paso corporation 250 million tgp 2 amount reflect 83 million received conjunction settlement fair value hedges related euro denominated notes debt maturities aggregate maturities principal amounts longterm financing obligations december 31 2009 next 5 years total thereafter follows millions 1 amount includes approximately 217 million ruby debt convertible preferred equity interest ruby subject satisfaction certain conditions information see note 18 credit facilitiesletters credit december 31 2009 subject terms various agreements total available capacity credit agreements including capacity available epb’s 750 million revolving credit facility approximately 13 billion description existing credit facilities december 31 2009 15 billion revolving credit agreement 15 billion revolving credit facility matures november 2012 el paso certain subsidiaries guaranteed facility collateralized stock ownership epng tgp also eligible borrowers 15 billion revolving credit facility borrow funds libor plus 125 based current applicable margin issue letters credit 1375 amount issued pay annual commitment fee 025 based current applicable margin unused capacity revolving credit facility credit agreement applicable margin used calculate interest borrowings letters credit commitment fees determined variable pricing grid tied credit ratings senior secured debt december 31 2009 approximately 02 billion letters credit issued 04 billion debt outstanding facility december 31 2009 remaining capacity facility approximately 08 billion unsecured revolving credit facility 500 million unsecured revolving credit facility matures july 2011 third party third party trust provides borrowings issuing letters credit required pay fixed facility fees rate 234 total committed amount facility addition pay interest borrowings rate comprised either libor base rate substantially capacity facility used issue letters credit december 31 2009 remaining capacity facility approximately 24 million unsecured credit facilities 2009 500 million letter credit facilities entered 2007 matured december 31 2009 total 325 million letter credit facilities otherwise discussed weighted average fixed facility fee 67 maturities ranging december 2013 september 2014 december 31 2009 remaining capacity facilities approximately 35 million epep 10 billion revolving credit agreement december 31 2009 08 billion outstanding epep’s 10 billion revolving credit facility 02 billion available capacity based current borrowing levels pay interest libor plus 15 borrowings commitment fee 035 unused capacity facility collateralized certain natural gas oil properties subject revaluation semiannual basis november 2009 existing borrowing base approved banks december 31 2009 recent determination sufficient fully support facility matures 2012 epep 300 million revolving credit agreement december 31 2009 300 million available capacity epep’s 300 million 364day secured revolving credit facility matures december 2010 pay libor plus 35 borrowed money 075 commitment fee facility originally entered december 2008 facility collateralized certain natural gas oil properties epb’s 750 million revolving credit facility 2007 epb wic epb’s subsidiary entered unsecured 5year revolving credit facility initial aggregate borrowing capacity 750 million expandable 125 billion certain expansion projects acquisitions facility available epb subsidiaries borrowings guaranteed epb subsidiaries amounts borrowed nonrecourse el paso approximately 520 million outstanding credit facility epb remaining capacity approximately 215 million december 31 2009 credit facility two pricing grids one based credit ratings based leverage currently leverage pricing grid effect epb’s cost borrowings libor plus 0425 based epb’s current leverage epb also pays 0125 facility fee 010 commitment utilization fee annually facility letters credit enter letters credit ordinary course operating activities well periodically conjunction sales assets businesses 2008 entered new letter credit facility bank support purchase commitments pipe related ruby pipeline project issued two letters credit facility total approximately 450 million december 31 2009 approximately 183 million remained outstanding pay 100 annually letters credit mature september 2010 december 31 2009 total outstanding letters credit issued facilities approximately 13 billion included amount 07 billion letters credit securing recorded obligations related price risk management activities restrictive covenants 15 billion revolving credit agreement covenants 15 billion revolving credit facility include restrictions debt levels restrictions liens securing debt guarantees restrictions mergers sales assets dividend restrictions cross default crossacceleration provisions breach covenants could result acceleration debt financial obligations subsidiaries credit agreement restrictive debt covenants cross default provisions ratio debt consolidated earnings interest income taxes depreciation amortization ebitda defined credit agreement shall exceed 525 1 maturity b ratio consolidated ebitda defined credit agreement interest expense plus dividends paid shall less 20 1 maturity c epng tgp cannot incur incremental debt incurrence incremental debt would cause debt consolidated ebitda ratio defined credit agreement particular company exceed 50 1 occurrence event default expiration applicable grace period respect debt aggregate principal amount 200 million epep 10 billion 300 million revolving credit agreements epep’s borrowings facilities subject various conditions financial coverage ratio facilities requires epep’s ebitda defined facility interest expense less 20 1 epep’s debt ebitda defined credit agreement must exceed 40 1 epb’s 750 million revolving credit facility requires epb maintain end fiscal quarter consolidated leverage ratio defined facility less 50 1 four consecutive quarters 55 1 three consecutive quarters subsequent consummation specified permitted acquisitions value greater 25 million restrictions provisions addition restrictions provisions andor subsidiaries subject various financial nonfinancial covenants restrictions covenants restrictions include limitations additional debt subsidiaries limitations use proceeds borrowing subsidiaries limitations cases transactions affiliates limitations incurrence liens potential limitations subsidiaries participate cash management program potential limitations ability subsidiaries declare pay dividends december 31 2009 restricted net assets consolidated subsidiaries approximately 534 million restrictive crossacceleration provision associated indenture one subsidiaries indenture states event default occur resulting acceleration debt obligations subsidiary excess 10 million longterm debt obligation containing provision could accelerated acceleration debt would adversely affect liquidity position turn financial condition also issued various guarantees securing financial obligations subsidiaries affiliates similar covenants facilities financing arrangements capital trusts el paso energy capital trust wholly owned business trust formed march 1998 issued 65 million 475 percent trust convertible preferred securities 325 million trust exists sole purpose issuing preferred securities investing proceeds 475 percent convertible subordinated debentures issued due 2028 trust i’s sole source income interest earned debentures interest income used pay distributions preferred securities also two wholly owned business trusts el paso energy capital trust ii iii trust ii iii issued securities provide full unconditional guarantee trust i’s preferred securities would provide guarantee securities issued trust ii iii trust i’s preferred securities nonvoting except limited circumstances pay quarterly distributions annual rate 475 percent carry liquidation value 50 per security plus accrued unpaid distributions convertible common shares time prior close business march 31 2028 option holder rate 12022 common shares trust preferred security equivalent conversion price 4159 per common share classified securities longterm debt right redeem securities time wyco development llc wyco june 2009 november 2008 totem gas storage facility high plains pipeline placed service constructed storage pipeline facilities joint venture partner affiliate public service company colorado psco wyco funded 50 percent construction costs reflected payments made joint venture partner noncurrent liabilities balance sheet construction upon completion obligations construction advances converted financing obligation wyco accordingly reclassified amounts noncurrent liabilities debt financing obligations principal amount totem gas storage facility high plains pipeline 69 million 106 million respectively december 31 2009 paid monthly installments 2060 2043 respectively december 31 2008 principal amount totem gas storage facility 108 million interest payments obligations based 50 percent operating results facilities’ currently estimated 155 percent rate december 31 2009 nonrecourse project financings several subsidiaries investments debt obligations related costs construction acquisition project financing debt recourse project company assets ie without recourse el paso december 31 2009 one international power project accounted equity investment default debt agreement however material exposure result default 13 commitments contingencies legal proceedings cash balance plan lawsuit december 2004 purported class action lawsuit entitled tomlinson et alv el paso corporation el paso corporation pension plan filed us district court denver colorado lawsuit alleges various violations employee retirement income security act erisa age discrimination employment act result change final average earnings formula pension plan cash balance pension plan trial court dismissed claims plan violated erisa costs legal exposure related lawsuit currently determinable retiree medical benefits matters 2002 lawsuit entitled yolton et al v el paso tennessee pipeline co case corporation filed federal court detroit michigan lawsuit filed behalf group retirees case corporation case alleged entitled retiree medical benefits medical benefits plan serve plan administrator pursuant merger agreement tenneco inc although asserted obligations plan subject cap pursuant agreement union case employees trial court ruled benefits vested subject cap result obligated pay amounts cap adjusted existing indemnification accrual using current actuarial assumptions reclassified liability postretirement benefit obligation see note 14 discussion impact matter intend pursue appellate options following determination trial court damages incurred plaintiffs period premium payments cap paid retirees believe accruals established matter adequate price reporting litigation beginning 2003 several lawsuits filed el paso marketing lp epm alleging el paso epm energy companies conspired manipulate price natural gas providing false price information industry trade publications published gas indices first set cases involving similar allegations behalf commercial residential customers transferred multidistrict litigation proceeding mdl us district court nevada styled western states wholesale natural gas antitrust litigation cases dismissed us court appeals ninth circuit however reversed dismissal ordered cases remanded trial court second set cases also involve similar allegations behalf certain purchasers natural gas include farmland industries v oneok inc et al filed state court wyandotte county kansas july 2005 missouri public service commission v el paso corporation et al filed circuit court jackson county missouri kansas city october 2006 purported class action lawsuits styled leggett et al v duke energy corporation et al filed chancery court tennessee january 2005 everbloom inc et al v aep energy services inc et al filed federal court eastern district california september 2005 learjet inc et al v oneok inc et al filed state court wyandotte county kansas september 2005 breckenridge et al v oneok inc et al filed state court denver county colorado may 2006 arandell et al v xcel energy et al filed circuit court dane county wisconsin december 2006 heartland et al v oneok inc et al filed circuit court buchanan county missouri march 2007 newpage wisconsin system inc et al filed circuit court wood county wisconsin march 2009 leggett case dismissed tennessee state court october 2008 tennessee court appeals reversed dismissal remanding matter trial court decision appealed tennessee supreme court missouri public service case dismissed state court dismissal upheld appellate court appealed missouri supreme court remaining cases transferred mdl proceeding breckenridge case dismissed el paso defendants motion reconsideration decision denied ruling still appealed discovery proceeding mdl cases motions summary judgment based federal preemption filed reached agreement settle western states everbloom cases approved court paid costs legal exposure related remaining lawsuits claims currently determinable gas measurement cases number subsidiaries named defendants actions generally allege mismeasurement natural gas volumes andor heating content resulting underpayment royalties first set cases filed 1997 individual false claims act consolidated pretrial purposes natural gas royalties qui tam litigation us district court district wyoming complaints allege industrywide conspiracy underreport heating value well volumes natural gas produced federal native american lands october 2006 us district judge issued order dismissing claims defendants march 2009 tenth circuit court appeals affirmed dismissals october 2009 plaintiff’s appeal united states supreme court denied similar allegations filed set actions initiated 1999 price et al v gas pipelines predecessors et al district court stevens county kansas plaintiffs seek certification class royalty owners wells nonfederal nonnative american lands kansas wyoming colorado plaintiffs seek unspecified amount monetary damages form additional royalty payments along interest expenses punitive damages injunctive relief regard future gas measurement practices september 2009 court denied motions class certification plaintiffs filed motion reconsideration costs legal exposure related lawsuit claim currently determinable mtbe certain subsidiaries used produced sold distributed methyl tertiarybutyl ether mtbe gasoline additive various lawsuits filed throughout us regarding potential impact mtbe water supplies lawsuits brought different parties including state attorney generals water districts individual water companies sought different remedies including remedial activities damages attorneys’ fees costs cases initially consolidated pretrial purposes multidistrict litigation us district court southern district new york several cases later remanded state court 2008 settled 59 lawsuits settlement payments covered insurance additionally july 2009 settled additional case insurance covered following dismissal settled cases 32 lawsuits remain although settlement discussions plaintiffs discussions unsuccessful date damages claimed remaining actions substantial remains significant legal uncertainty regarding validity causes action asserted availability relief sought tender remaining cases insurers likely insurers assert denial coverage 12 mostrecently filed cases costs legal exposure related remaining lawsuits currently determinable addition proceedings subsidiaries affiliates named defendants numerous lawsuits governmental proceedings claims arise ordinary course business also regulatory rules orders various stages adoption review andor implementation matters evaluate merits case claim exposure matter possible legal settlement strategies likelihood unfavorable outcome determine unfavorable outcome probable estimated establish necessary accruals outcome matters including discussed cannot predicted certainty still uncertainties related costs may incur based upon evaluation experience date believe established appropriate reserves matters possible however new information future developments could require us reassess potential exposure related matters adjust accruals accordingly adjustments could material december 31 2009 approximately 67 million accrued reduced 1 million related insurance receivables outstanding legal governmental proceedings rates regulatory matters sng rate case january 2010 ferc approved sng’s settlement sng increased base tariff rates ii implemented volume tracker gas used operations iii agreed file next general rate case effective august 31 2012 later september 1 2013 iv extended vast majority sng’s firm transportation contracts expiring prior september 1 2013 august 31 2013 epng rate case june 2008 epng filed rate case ferc required settlement previous rate case filing proposed increase epng’s base tariff rates august 2008 ferc issued order accepting proposed rates effective january 1 2009 subject refund outcome hearing technical conference ferc issued order december 2008 generally accepted epng’s proposals technical conference proceeding ferc appointed administrative law judge preside hearing epng unable reach negotiated settlement customers remaining issues settlement negotiations continuing however hearing postponed may 2010 outcome settlement discussions hearing currently determinable notice proposed rulemaking october 3 2007 minerals management service mms issued notice proposed rulemaking applicable pipelines located outer continental shelf ocs adopted proposed rules would substantially revise mms ocs pipeline rightsofway regulations proposed rules would effect increasing financial obligations entities pipelines pipeline rightsofway ocs ii increasing regulatory requirements imposed operation maintenance existing pipelines rightsofway ocs iii increasing requirements preconditions obtaining new rightsofway ocs matter navajo nation march 2009 representatives navajo nation epng executed final agreement setting forth full terms conditions navajo nation’s consent epng’s rightsofway navajo nation epng submitted navajo nation’s consent agreement support epng’s pending application united states department interior department extension department’s current rightofway grant expect submission result department’s final processing application epng filed ferc recovery payments rightsofway recent rate case environmental matters subject federal state local laws regulations governing environmental quality pollution control laws regulations require us remove remedy effect disposal release specified substances current former operating sites december 31 2009 accrued approximately 189 million environmental matters reduced 24 million amounts paid directly government sponsored programs settlement arrangements accrual includes approximately 185 million expected remediation costs associated onsite offsite groundwater technical studies approximately 4 million related environmental legal costs 189 million accrual 14 million reserved facilities currently operate 175 million reserved nonoperating sites facilities shut sold superfund sites estimates potential liability range approximately 189 million approximately 381 million environmental remediation projects various stages completion recorded liabilities reflect current estimates amounts expend remediate sites however depending stage completion assessment ultimate extent contamination remediation required may known additional assessments occur remediation efforts continue may incur additional liabilities type site reserves based following estimates reasonably possible outcomes reconciliation accrued liability january 1 2009 december 31 2009 millions cercla matters part environmental remediation projects received notice could designated asked information determine whether could designated potentially responsible party prp respect 33 active sites comprehensive environmental response compensation liability act cercla state equivalents sought resolve liability prp sites indemnification third parties settlements provide payment allocable share remediation costs cleanup costs estimates subject revision information becomes available extent remediation required cases asserted defense liability estimates could change moreover liability federal cercla statute may joint several meaning could required pay excess pro rata share remediation costs understanding financial strength prps considered appropriate estimating liabilities accruals issues included previously indicated estimates superfund sites 2010 estimate total remediation expenditures net expected recoveries approximately 48 million expended government directed cleanup plans addition expect make capital expenditures environmental matters approximately 5 million aggregate years 2010 2014 expenditures primarily relate compliance clean air regulations possible new information future developments could require us reassess potential exposure related environmental matters may incur significant costs liabilities order comply existing environmental laws regulations also possible developments increasingly strict environmental laws regulations orders regulatory agencies well claims damages property environment injuries employees persons resulting current past operations could result substantial costs liabilities future information becomes available relevant developments occur adjust accrual amounts accordingly still uncertainties related ultimate costs may incur based upon evaluation experience date believe reserves adequate commitments purchase obligations matters operating leases maintain operating leases ordinary course business activities leases include office space operating facilities equipment terms agreements vary 2010 2053 future minimum annual rental commitments operating leases net minimum sublease rentals december 31 2009 follows rental expense lease obligations years ended december 31 2009 2008 2007 39 million 39 million 40 million guarantees indemnifications involved various joint ventures ownership arrangements sometimes require financial performance guarantees financial guarantee obligated make payments guaranteed party fails make payments violates terms financial arrangement performance guarantee provide assurance guaranteed party execute terms contract required perform behalf also periodically provide indemnification arrangements related assets businesses sold arrangements include limited indemnifications income taxes resolution existing disputes environmental matters potential exposure guarantee indemnification agreements range specified amount unlimited dollar amount depending nature claim particular transaction many agreements may specify maximum potential exposure specified duration indemnification obligation circumstances amount duration unlimited arrangements specified dollar amount maximum stated value approximately 08 billion primarily relates indemnification arrangements associated sale anr pipeline company 2007 macae power facility brazil legacy assets amounts exclude guarantees issued related letters credit discussed note 12 included maximum stated value certain indemnification agreements expired however claims made prior expiration related claim periods unable estimate maximum exposure guarantee indemnification agreements provide limits amount future payments due uncertainty exposures december 31 2009 recorded obligations 52 million related guarantee indemnification arrangements liability consists primarily indemnification one subsidiaries provided related sale ammonia facility reflected financial statements estimated fair value provided partial parental guarantee subsidiary’s obligations indemnification believe guarantee indemnification agreements recorded liability probable resulting future losses based assessment nature guarantee financial condition guaranteed party period time guarantee outstanding among considerations purchase obligations 2009 entered contracts purchase pipe primarily associated ruby pipeline project tgp’s 300 line expansion anticipated placed service 2010 2011 estimated obligations agreements approximately 13 billion 2010 approximately 300 million 2011 commercial commitments november 2009 ferc approved amendment 1995 ferc settlement provides interim refunds three year period approximately 157 million amounts collected related certain environmental costs december 2009 tgp refunded approximately 30 million customers refunds recorded current noncurrent liabilities balance sheet expected paid three year period interest various commercial commitments purchase obligations recorded balance sheet december 31 2009 firm commitments transportation storage capacity contracts 643 million due various times purchase capital commitments including maintenance engineering procurement construction contracts approximately 360 million majority due less one year also hold cancelable easements rightofway arrangements landowners permitting use land construction operation pipeline systems currently obligation easements material results operations however executed longterm rightofway agreement navajo nation result significant commitment us upon approval pending application department interior see navajo nation 14 retirement benefits overview retirement benefit plans pension plans primary pension plan defined benefit plan covers substantially us employees provides benefits cash balance formula certain employees participated prior pension plans el paso sonat inc coastal corporation receive greater cash balance benefits transition benefits prior plan formulas prior december 31 2008 maintained two frozen pension plans provide benefits former employees previously discontinued coal convenience store operations effective december 31 2008 frozen plans merged cash balance plan anticipate making contributions cash balance pension plan 2010 addition primary pension plan maintain supplemental executive retirement plan serp provides additional benefits selected officers key management serp provides benefits excess certain irs limits essentially mirror primary pension plan expect contribute 5 million serp 2010 retirement savings plan maintain defined contribution plan covering us employees match 75 percent participant basic contributions six percent eligible compensation make additional discretionary matching contributions depending overall performance company relative peers amounts expensed plan approximately 19 million 20 million 16 million years ended december 31 2009 2008 2007 postretirement benefit plans provide postretirement benefits opeb including medical benefits closed groups retired employees limited postretirement life insurance benefits current retired employees medical benefits closed groups retirees may subject deductibles copayment provisions limitations dollar caps amount employer costs reserve right change benefits opeb regulated pipeline companies prefunded extent costs recoverable rates extent opeb costs regulated pipeline companies differ amounts recovered rates regulatory asset liability recorded expect contribute 48 million postretirement benefit plans 2010 matters various court rulings prior march 2008 required indemnify case corporation case certain benefits paid closed group case retirees discussed note 13 conjunction rulings recorded liability estimated amounts due indemnification using actuarial methods similar used estimating postretirement benefit plan obligations liability however included postretirement benefit obligations disclosures prior 2008 first quarter 2008 received summary judgment trial court matter thus became primary party obligated pay benefit payments result judgment adjusted obligation using current actuarial assumptions recording 65 million reduction current noncurrent liabilities operation maintenance expense also reclassified obligation indemnification liability postretirement benefit obligation increased overall postretirement benefit obligations 280 million benefit obligation plan assets funded status accounting pension postretirement plans record asset liability based funded status plan deferred amounts related unrecognized gains losses changes actuarial assumptions recorded either regulatory asset liability regulated operations accumulated comprehensive income loss component stockholders’ equity operations gains losses recognized income statement table provides information pension opeb plans 2008 adopted revised measurement date provisions accounting retirement benefits information 2008 presented computed fifteen months ended december 31 2008 2009 information presented computed twelve months ended december 31 2009 1 benefit obligation pension plans represents projected benefit obligation benefit obligation postretirement benefit plans represents accumulated postretirement benefit obligation 2 amounts postretirement benefits shown net subsidy approximately 6 million years ended december 31 2009 2008 related medicare prescription drug improvement modernization act 2003 3 defer difference actual return plan assets expected return three year period considered inclusion net benefit expense income deferred actuarial gains losses amortized extent remaining unrecognized actual gains losses exceed greater 10 percent benefit obligations market related value plan assets components funded status following table details amounts recognized balance sheet december 31 2009 2008 related pension postretirement benefit plans components accumulated comprehensive income loss following table details amounts recognized accumulated comprehensive income loss net income taxes december 31 2009 2008 related pension postretirement benefit plans anticipate approximately 48 million accumulated comprehensive loss net tax recognized part net periodic benefit cost 2010 accumulated benefit obligation defined benefit pension plans 21 billion 20 billion december 31 2009 2008 accumulated benefit obligation defined benefit pension plans whose accumulated benefit obligations exceeded fair value plan assets 21 billion 20 billion december 31 2009 2008 fair value plans’ assets approximately 20 billion 18 billion december 31 2009 2008 accumulated postretirement benefit obligation postretirement benefit plans whose accumulated postretirement benefit obligations exceeded fair value plan assets 542 million 552 million december 31 2009 2008 fair value plans’ assets 55 million 48 million december 31 2009 2008 plan assets primary investment objective plans ensure longterm life plans adequate pool sufficiently liquid assets exists meet benefit obligations participants retirees beneficiaries investment objectives longterm nature covering typical market cycles shortfall investment performance compared investment objectives generally result economic capital market conditions plans’ investments include wide diversification asset types fund strategies fund managers although actual allocations vary time targeted allocations target allocations pension plans’ assets 50 percent equity securities 40 percent fixed income securities 10 percent types investments target allocations postretirement plans’ assets 65 percent equity 35 percent fixed income securities equity securities pension plans’ assets may include investments largecap smallcap companies united states well investments foreign companies fixed income securities may include corporate bonds companies diversified industries including international fixed income securities united states treasuries stable income products investment contracts types investments may include investments hedge funds private real estate follow several different strategies postretirement benefit plans may invest assets manner replicates extent feasible russell 3000 index barclays capital aggregate bond index achieve equity fixed income diversification respectively details pension postretirement benefit plans assets classified level description fair values discussion various methods used determine fair value see note 7 • level 1 assets’ fair values based quoted prices actively traded markets included level equity securities fixed income securities exchange traded mutual fund securities whose fair values determined using quoted prices assets • level 2 assets’ fair values primarily based pricing data representative quoted prices similar assets active markets identical assets less active markets included level commoncollective trusts mutual fund commoncollective trusts’ mutual fund fair values primarily based net asset value reported issuer determined based fair value underlying securities valuation date may adjust values necessary factors liquidity risk nonperformance issuer • level 3 assets’ fair values partially calculated using valuation techniques require inputs significant fair value measurement unobservable december 31 2009 level 3 assets listed fair values pension postretirement benefit plans’ assets recorded fair value classified level december 31 2009 millions 1 category includes eight commoncollective trusts invested approximately 54 percent fixed income 43 percent equity 3 percent short term securities 1 category includes four commoncollective trusts invested approximately 65 percent equity 35 percent fixed income securities expected payment future benefits december 31 2009 expect following benefit payments plans actuarial assumptions sensitivity analysis benefit obligations net benefit cost based actuarial estimates assumptions following table details weightedaverage actuarial assumptions used determining benefit obligation net benefit costs pension postretirement plans 2009 2008 2007 1 expected return plan assets pretax rate return based targeted portfolio investments postretirement benefit plans’ investment earnings subject unrelated business income tax rate 35 expected return plan assets postretirement benefit plans calculated using aftertax rate return actuarial estimates postretirement benefit plans assumed weightedaverage annual rate increase per capita costs covered health care benefits 80 percent gradually decreasing 50 percent year 2015 assumed health care cost trends significant effect amounts reported postretirement benefit plans onepercentage point change assumed health care cost trends would following effects december 31 2009 2008 components net benefit cost income years ended december 31 components net benefit cost income follows components comprehensive income loss following table details amounts recognized comprehensive loss net income taxes years ended december 31 2009 2008 related pension postretirement benefit plans 15 equity preferred stock subsidiary discussion components equity noncontrolling interests december 31 2009 december 31 2008 convertible perpetual preferred stock 750 million convertible perpetual preferred stock outstanding dividends preferred stock declared quarterly rate 499 per annum approved board directors dividends accumulate paid share preferred stock convertible holder’s option time subject adjustment 772295 shares common stock certain conditions conversion rate represents equivalent conversion price approximately 1300 per share conversion rate subject adjustment based certain events include limited fundamental changes business mergers business combinations well distributions common stock payment dividends common stock excess specified rate able cause preferred stock converted common stock april 2010 common stock trading premium 130 percent conversion price common preferred stock dividends table shows amount dividends paid declared dollars millions dividends common stock preferred stock treated reduction additional paidincapital since currently accumulated deficit expect dividends paid common preferred stock 2009 taxable stockholders anticipate dividends paid current accumulated earnings profits tax purposes 2009 board directors declared dividends common shareholders 005 per share february may august 001 per share november terms 750000 outstanding shares 499 convertible preferred stock provide conversion ratio preferred stock increase pay quarterly dividends common shareholders excess 004 per share dividends paid 2009 terms preferred shares also prohibit payment dividends common stock unless paid set aside payment accumulated unpaid dividends preferred stock preceding dividend periods addition although credit facilities contain direct restriction payment dividends included fixed charge calculation fixed charge coverage ratio credit facilities unable comply fixed charge ratio ability pay additional dividends would restricted accumulated comprehensive income loss following table provides components accumulated comprehensive income loss december 31 noncontrolling interests 2009 subsidiary epb master limited partnership issued 127 million common units net proceeds 212 million ownership interest epb decreased 74 percent 67 percent result offering january 2010 epb issued public total 99 million common units issued 02 million general partner units us ownership interest epb decreased 62 percent result subsequent offering epb makes quarterly distributions available cash unitholders accordance partnership agreement years ended december 31 2009 2008 2007 recorded 60 million 34 million 6 million reflected net income attributable noncontrolling interest holders income statement july 2009 epb acquired additional 18 percent interest one consolidated subsidiaries cig 215 million result acquisition epb owns 58 percent interest cig 25 percent interest sng 100 percent interest wic preferred stock subsidiary october 2009 gip partner ruby pipeline project contributed 145 million ruby received convertible preferred equity interest ruby simultaneously exchanged convertible preferred equity interest holding company cheyenne plains preferred stock cheyenne plains gas pipeline company llc cheyenne plains classified outside equity balance sheet since events require redemption preferred interest entirely within control preferred dividend associated gip’s preferred interest 5 million paid 2009 reflected net income attributable noncontrolling interests income statement discussion ruby transaction see note 18 16 stockbased compensation overview stockbased compensation plans may issue employees incentive stock options common stock intended qualify section 422 internal revenue code nonqualified stock options restricted stock restricted stock units stock appreciation rights performance shares performance units stockbased awards authorized grant awards approximately 55 million shares common stock current plans includes 475 million shares omnibus plan 25 million shares nonemployee director plan 5 million shares employee stock purchase plan december 31 2009 approximately 244 million shares remain available grant current plans includes approximately 205 million shares omnibus plan 17 million shares nonemployee director plan 22 million shares employee stock purchase plan also approximately 11 million shares stock option awards outstanding granted terminated plans obligate us issue additional shares common stock exercised stock option exercises restricted stock funded primarily issuance new common shares record stockbased compensation expense excluding amounts capitalized operation maintenance expense requisite service period separately vesting portion award net estimates forfeitures actual forfeitures differ estimates additional adjustments compensation expense required future periods nonqualified stock options grant nonqualified stock options employees exercise price equal market value stock grant date stock option awards contractual terms 10 years generally vest equal amounts three years grant date pay dividends unexercised options summary stock option transactions year ended december 31 2009 presented 2009 2008 2007 recognized approximately 23 million 21 million 16 million pretax compensation expense stock options capitalized approximately 5 million 2009 4 million 2008 2007 expense part fixed assets recorded 8 million 7 million 6 million income tax benefits respectively total compensation cost related nonvested option awards yet recognized december 31 2009 approximately 17 million expected recognized weighted average period 10 months options exercised years ended december 31 2009 2008 2007 total intrinsic value less 1 million 10 million 6 million generated 1 million 11 million 7 million cash proceeds generate significant associated income tax benefit fair value assumptions fair value stock option granted estimated date grant using blackscholes optionpricing model based several assumptions based management’s best estimate time grant years ended december 31 2009 2008 2007 weighted average grant date fair value per share options granted 296 573 553 listed weighted average assumption based grants fiscal year estimate expected volatility based analysis implied volatilities traded options common stock historical stock price volatility expected term adjusted certain time periods believe representative future stock performance estimate expected term option awards based vesting period average remaining contractual term referred “simplified method” use method provide reasonable basis estimating expected term based lack sufficient historical data primarily due significant changes composition employees receiving stockbased compensation awards prior 2006 restricted stock may grant shares restricted common stock carry voting dividend rights officers employees sale transfer shares restricted vest currently outstanding grant timebased restricted stock fair value timebased restricted shares determined grant date shares generally vest equal amounts three years date grant summary changes nonvested restricted shares fiscal years presented weighted average grant date fair value per share restricted stock granted 2009 2008 2007 653 1546 1473 total fair value shares vested 2009 2008 2007 13 million 29 million 31 million 2009 2008 2007 recognized approximately 26 million 29 million 25 million pretax compensation expense restricted share awards capitalized approximately 7 million expense year part fixed assets recorded 9 million 10 million 9 million income tax benefits related restricted stock arrangements total unrecognized compensation cost related arrangements december 31 2009 approximately 17 million expected recognized weighted average period 10 months employee stock purchase plan employee stock purchase plan allows participating employees right purchase common stock 95 percent market price last trading day month plan noncompensatory provisions current stock compensation accounting standards shares issued plan insignificant 2009 2008 2007 17 business segment information december 31 2009 business consists two core segments pipelines exploration production also marketing power segments strategic business units provide variety energy products services managed separately segment requires different technology marketing strategies corporate activities include general administrative functions well miscellaneous businesses various contracts assets immaterial discussion segment follows pipelines provides natural gas transmission storage related services primarily united states december 31 2009 conducted activities primarily seven wholly majority owned interstate pipeline systems equity interests four transmission systems addition storage capacity wholly majority owned pipelines systems also interests three underground natural gas storage facilities two lng terminalling facilities one construction exploration production engaged exploration acquisition development production natural gas oil ngl united states brazil egypt marketing markets manages price risks associated natural gas oil production well manages remaining legacy trading portfolio power manages risks associated remaining international power pipeline assets investments located south america asia continue pursue sale assets customers whose revenues exceeded 10 percent total revenues 2009 2008 2007 management uses earnings interest expense income taxes ebit measure assess operating results effectiveness business segments consist consolidated businesses investments unconsolidated affiliates believe ebit useful investors allows evaluate effectively operating performance using performance measure analyzed internally management define ebit net income loss adjusted items interest debt expense ii income taxes iii net income attributable noncontrolling interests investors may evaluate operating results without regard financing methods capital structure ebit may comparable measures used companies additionally ebit considered conjunction net income loss income loss income taxes performance measures operating income operating cash flows reconciliation ebit net income loss periods ended december 31 following tables reflect segment results three years ended december 31 1 includes eliminations intercompany transactions intersegment revenues along intersegment operating expenses incurred normal course business operating segments recorded intersegment revenue elimination 10 million 2 revenues external customers include gains 687 million related financial derivative contracts associated natural gas oil production intersegment revenues represent sales marketing segment responsible marketing production third parties 3 total foreign assets approximately 04 billion relates property plant equipmentand approximately 03 billion relates investments advances unconsolidated affiliates 4 amounts net third party reimbursements capital expenditures returns capital sales investments advances 1 includes eliminations intercompany transactions intersegment revenues along intersegment operating expenses incurred normal course business operating segments recorded intersegment revenue elimination 19 million 2 revenues external customers include gains 196 million related financial derivative contracts associated natural gas oil production intersegment revenues represent sales marketing segment responsible marketing production third parties 3 total foreign assets approximately 03 billion relates property plant equipment approximately 05 billion relates investments advances unconsolidated affiliates 4 amounts net third party reimbursements capital expenditures returns capital sales investments advances 1 includes eliminations intercompany transactions intersegment revenues along intersegment operating expenses incurred normal course business operating segments recorded intersegment revenue elimination 19 million operation maintenance expense elimination 1 million included “corporate” column remove intersegment transactions 2 revenues external customers include gains 192 million related financial derivative contracts associated natural gas oil production intersegment revenues represent sales marketing segment responsible marketing production third parties 3 represents ebit continuing operations also discontinued operations 2007 4 total foreign assets approximately 06 billion relates property plant equipment approximately 06 billion relates investments advances unconsolidated affiliates 5 amounts net third party reimbursements capital expenditures returns capital sales investments advances 6 includes debt extinguishment costs 86 million related refinancing epep’s 12 billion notes also includes 77 million income related reversal liability related legacy crude oil marketing trading business matter 18 variable interest entities qualifying special purpose entities variable interest entities investment ruby pipeline holding company llc ruby variable interest entity owns ruby pipeline project approximately 06 billion net property plant equipment december 31 2009 consolidate ruby primary beneficiary based conditions discussed july 2009 entered agreement several infrastructure funds managed gip whereby invest 700 million acquire 50 percent interest ruby subject certain conditions part agreement gip entered loan commitment provide project funding 405 million ruby converted preferred equity interest ruby upon satisfaction certain conditions december 31 2009 217 million borrowed commitment recorded shortterm financing obligation balance sheet october 2009 gip contributed 145 million ruby received convertible preferred equity interest ruby simultaneously exchanged convertible preferred equity interest holding company cheyenne plains cheyenne plains variable interest entity owns cheyenne plains pipeline approximately 04 billion net property plant equipment 02 billion longterm debt december 31 2009 consolidate cheyenne plains primary beneficiary gip hold interest cheyenne plains certain conditions satisfied including placing ruby pipeline project inservice gip committed contribute additional 150 million preferred equity contributions ruby certain conditions significant ferc approvals construction project obtained third party financing approximately 14 billion secured ruby december 2010 gip right convert preferred equity common equity ruby time however preferred equity subject mandatory conversion common equity ruby upon satisfaction certain conditions including ruby entering additional firm transportation agreements conditions closing satisfied waived time project completion gip would 50 percent equity interest ruby ownership cheyenne plains would transferred back us however gip preferred equity interests ruby cheyenne plains along amounts borrowed gip’s loan commitment ruby must repaid cash gip ferc approvals construction ruby pipeline project obtained december 2010 ii third party financing approximately 14 billion secured ruby december 2010 iii ruby pipeline project placed inservice within 16 months obtaining ferc approvals additionally financings completed gip option convert preferred interest cheyenne plains 50 percent common interest cheyenne plains obligation repay amounts secured equity interests ruby cheyenne plains approximately 50 million common units master limited partnership mlp el paso pipeline partners lp hold interests variable interest entities account investments unconsolidated affiliates entities significant operations accordingly material impact financial statements qualifying special purpose entities accounts receivable sales program several pipeline subsidiaries agreements sell certain accounts receivable qspes whose purpose solely invest pipeline receivables shortterm assets generally settle within 60 days year ended december 31 2009 2008 received net proceeds approximately 19 billion 18 billion related sales receivables qspes changes subordinated beneficial interests recognized losses approximately 2 million 3 million transactions december 31 2009 2008 approximately 170 million 174 million receivables outstanding qspes received cash 89 million 82 million received subordinated beneficial interests approximately 79 million 89 million qspes also issued senior beneficial interests receivables sold third party financial institution totaled 90 million 85 million december 31 2009 2008 reflect subordinated beneficial interest receivables sold fair value date issued amounts adjusted subsequent collections recorded accounts receivable affiliates balance sheet ability recover carrying value subordinated beneficial interests based collectability underlying receivables sold qspes reflect accounts receivable sold program changes subordinated beneficial interests operating cash flows statement cash flows agreements earn fee servicing accounts receivable performing administrative duties qspes reflected reduction operation maintenance expense income statement fair value servicing administrative agreements well fees earned material financial statements years ended december 31 2009 2008 january 2010 ceased selling accounts receivable pipeline subsidiaries qspes began selling receivables directly third party financial institution return third party financial institution pays certain amount cash front receivables pays remaining amount owed time cash collected receivables 19 investments earnings transactions unconsolidated affiliates hold investments unconsolidated affiliates accounted using equity method accounting earnings unconsolidated affiliates reflected income statement include share net earnings directly attributable unconsolidated affiliates ii impairments adjustments recorded us december 31 2009 2008 investment balance exceeded net equity underlying net assets investments 269 million 481 million due primarily purchase price adjustments impairment charges recorded us majority purchase price adjustments related investment four star acquired 2005 generally amortize assess recoverability amount based development production underlying estimated proved natural gas oil reserves four star information related unconsolidated affiliates includes net investment earnings losses recorded investments ii summarized financial information proportionate share investments iii revenues charges unconsolidated affiliates net ownership interest investments earnings losses unconsolidated affiliates follows years ended december 31 december 31 2009 2008 approximately 485 million 433 million equity undistributed earnings 50 percent less owned entities accounted equity method included consolidated accumulated deficit received cash distributions dividends unconsolidated affiliates 90 million 182 million years ended december 31 2009 2008 included amounts returns capital 2 million 2009 2008 impairment charges gains losses sales equity investments included earnings losses unconsolidated affiliates 2008 impaired investment four star based decrease fair value resulted declining commodity prices 2007 impaired investments porto velho manaus rio negro based assessment value would receive sale investments due developments power markets brazil gains losses consisted following summarized financial information proportionate share operating results financial position unconsolidated affiliates including hold greater 50 percent interest revenues charges resulting transactions unconsolidated affiliates material 2009 2008 2007 investmentrelated matters manausrio negro 2008 transferred ownership manaus rio negro facilities plants’ power purchaser required power purchase agreements december 31 2009 approximately 67 million brazilian reaisdenominated noncurrent accounts receivable owed us projects’ terminated power purchase agreements guaranteed purchaser’s parent purchaser withheld payment receivables light brazilian reaisdenominated claims approximately 65 million related plant maintenance purchaser asserts performed plants prior transfer inventory levels items purchaser’s parent also withheld payment receivables guarantee light claims initiated legal action purchaser’s parent failure pay us performance guaranty purchaser’s parent filed motions brazilian courts power purchaser added defendant litigation settlement discussions purchaser parent unsuccessful date currently anticipate resolution matters likely occur legal proceedings brazilian courts reviewed obligations power purchase agreement relation claims accrued obligation uncontested claims believe remaining contested claims without merit ultimate resolution matters unknown time adverse developments related either ability collect amounts due us related dispute could require us record additional losses future 2009 brazilian taxing authorities began legal proceedings manaus rio negro projects 65 million brazilian reaisdenominated icms taxes allegedly due capacity payments received plants’ power purchaser 1999 2001 secured court order prohibiting subsidiaries transferring otherwise disposing assets believe icms tax assessments projects without merit agreement power purchaser must indemnify manaus rio negro projects icms taxes along related interest penalties therefore defending projects lawsuit order continue defense matter power purchaser required provide security potential tax liability court’s satisfaction power purchaser offered pledge certain assets offer rejected tax authorities court power purchaser appealed court’s decision power purchaser unable resolve tax matter potential taxes owed manaus rio negro projects also guaranteed purchaser’s parent boliviatobrazil 8 percent interest boliviatobrazil pipeline december 31 2009 total investment guarantees related pipeline project approximately 117 million continue monitor evaluate potential impact regional political events bolivia could investment pipeline project new information becomes available future material developments arise may required record impairment investment supplemental selected quarterly financial information unaudited financial information quarter summarized unusual infrequently occurring items respective quarters 2009 2008 december 31 2009 items include 151 million gains related changes fair value exploration production financial derivatives ii 88 million tax benefit related liquidation foreign entities iii 22 million related restructuring costs iv 38 million international ceiling test charges september 30 2009 items include 87 million gains related changes fair value exploration production financial derivatives june 30 2009 items include 55 million gains related changes fair value exploration production financial derivatives ii 25 million marktomarket gains associated indemnification conjunction sale legacy ammonia facility iii 22 million loss sale porto velho notes receivables iv 21 million marktomarket gains power contracts march 31 2009 items include total 21 billion domestic international ceiling test charges ii 394 million marktomarket gains related changes fair value exploration production financial derivatives iii 52 million gain related application accounting standard updates certain derivative liabilities december 31 2008 items include total 27 billion domestic international ceiling test charges ii 125 million impairment investment four star iii 201 million marktomarket gains related changes fair value exploration production derivatives designated hedges september 30 2008 items include 214 million marktomarket gains related changes fair value exploration production derivatives designated hedges ii 63 million marktomarket gains pjm power contracts june 30 2008 items include 105 million marktomarket losses pjm power contracts ii 75 million marktomarket losses related changes fair value exploration production derivatives designated hedges march 31 2008 items include 43 million marktomarket losses associated sale legacy ammonia facility supplemental natural gas oil operations unaudited exploration production segment engaged exploration acquisition development production natural gas oil ngl united states us brazil egypt capitalized costs capitalized costs relating natural gas oil producing activities related accumulated depreciation depletion amortization follows december 31 millions total costs incurred costs incurred natural gas oil producing activities whether capitalized expensed follows year ended december 31 millions pursuant full cost method accounting capitalize certain general administrative expenses directly related property acquisition exploration development activities interest costs incurred attributable unproved oil gas properties major development projects oil gas properties table includes capitalized internal general administrative costs incurred connection acquisition development exploration natural gas oil reserves 80 million 85 million 69 million years ended december 31 2009 2008 2007 also capitalized interest 7 million 29 million 35 million years ended december 31 2009 2008 2007 december 31 2009 reserve report amounts estimated spent 2010 2011 2012 develop consolidated worldwide proved undeveloped reserves 316 million 290 million 223 million unevaluated capitalized costs exclude capitalized costs natural gas oil properties amortization various stages evaluation expect majority costs included amortization calculation next three years presented analysis capitalized costs natural gas oil properties year expenditures amortized december 31 2009 pending determination proved reserves millions natural gas oil reserves net quantities proved developed undeveloped reserves natural gas ngl oil condensate changes reserves december 31 2009 presented tables based internal reserve report net proved reserves exclude royalties interests owned others reflect contractual arrangements royalty obligations effect time estimate 2008 consolidated proved reserves consistent estimates proved reserves filed federal agencies 2009 except differences less five percent resulting actual production acquisitions property sales necessary reserve revisions additions reflect actual experience ryder scott company lp ryder scott conducted audit estimates proved reserves prepared us december 31 2009 connection audit ryder scott reviewed 87 percent properties associated proved reserves natural gas equivalent basis representing 90 percent total discounted future net cash flows proved reserves ryder scott also conducted audit estimates prepared proved reserves four star december 31 2009 connection audit proved reserves ryder scott reviewed 83 percent properties associated four star’s total proved reserves natural gas equivalent basis representing 85 percent total discounted future net cash flows based data technical processes interpretations procedures methodologies utilized us determining proved reserves believe reported proved reserve amounts reasonable ryder scott’s report included exhibit annual report form 10k january 2010 financial accounting standards board updated accounting standards extractive activities oil gas align oil gas reserve estimation disclosures requirements sec’s final rule modernization oil gas reserve reporting effective december 31 2009 among things new standard revised definition proved reserves required us use 12month average price estimate proved reserves rather period end spot price required prior periods 12month average price calculated unweighted arithmetic average spot price first day month within 12month period prior end reporting period first day 12month average us price used estimate proved reserves december 31 2009 387 per mmbtu natural gas 6118 per barrel oil spot price december 31 2009 579 per mmbtu natural gas 7936 per barrel oil adoption standard resulted lower natural gas oil prices used estimate proved reserves december 31 2009 would required previous standard used spot price rather first day 12month average price consolidated proved reserves would approximately 227 bcfe higher reported proved reserves december 31 2009 also standardized measure discounted future net cash flows would approximately 2 billion higher amounts reported december 31 2009 would recorded ceiling test charge brazilian full cost pool fourth quarter 2009 first day 12month average price change remaining provisions standard minimal impact company’s proved reserves estimates proved reserves determined according rules prescribed sec rules require standard “reasonable certainty” applied proved reserve estimates defined high degree confidence quantities recovered high degree confidence exists quantity much likely achieved technical economic data becomes available positive upward revision much likely negative downward revision estimates subject revision based upon number factors including many factors beyond control reservoir performance prices economic conditions government restrictions addition result drilling testing production subsequent date estimate may justify revision estimate reserve estimates often different quantities natural gas oil ultimately recovered estimating quantities proved natural gas oil reserves complex process involves significant interpretations assumptions cannot measured exact manner requires interpretations judgment available technical data including evaluation available geological geophysical engineering data accuracy reserve estimate highly dependent quality available data accuracy assumptions based upon economic factors natural gas oil prices production costs severance excise taxes capital expenditures workover remedial costs assumed effects governmental regulation addition due lack substantial production data greater uncertainties estimating proved undeveloped reserves proved developed nonproducing reserves proved developed reserves early production life result reserve estimates inherently imprecise meaningfulness reserve estimates highly dependent accuracy assumptions based general volume production natural gas oil properties declines reserves depleted except extent conduct successful exploration development activities acquire additional properties containing proved reserves proved reserves decline reserves produced subsequent december 31 2009 major discoveries events favorable otherwise may considered caused significant change estimated proved reserves results operations results operations natural gas oil producing activities fiscal year follows december 31 millions standardized measure discounted future net cash flows standardized measure discounted future net cash flows relating consolidated proved natural gas oil reserves december 31 follows millions calculations preceding table estimated future cash inflows estimated future production proved reserves december 31 2009 computed using first day 12month average us price 387 per mmbtu natural gas 6118 per barrel oil 12month average price calculated unweighted arithmetic average price first day month within 12month period prior end reporting period yearend us spot prices 571 680 per mmbtu natural gas 4460 9598 per barrel oil used compute estimated future cash inflows estimate future production proved reserves december 31 2008 2007 required time may receive amounts different standardized measure discounted cash flow number reasons including price cost changes standardized measure discounted future net cash flows following principal sources change consolidated worldwide standardized measure discounted future net cash flows millions 1 disclosure reflects changes standardized measure calculation excluding effects hedging activities schedule ii el paso corporation valuation qualifying accounts years ended december 31 2009 2008 2007 millions 1 amounts net related insurance receivables 2 amounts reflect valuation allowances primarily associated brazil net operating losses ceiling test charges reversal valuation allowances state net operating losses deferred tax assets 3 reflects rate refund settlement activity 4 amounts reflect valuation allowances associated brazil net operating losses ceiling test charges 5 amount reclassified postretirement liability see note 14 6 relates primarily sale accounts receivable accounts receivable sales program 7 included settlement shareholder litigation lawsuits item 9item 8 financial statements supplementary data index items contained part ii item 8 financial statements supplementary data management’s annual report internal control financial reporting management responsible establishing maintaining adequate internal control financial reporting defined sec rules adopted securities exchange act 1934 amended internal control financial reporting designed provide reasonable assurance regarding reliability financial reporting preparation financial statements external purposes accordance generally accepted accounting principles consists policies procedures • pertain maintenance records reasonable detail accurately fairly reflect transactions dispositions assets • provide reasonable assurance transactions recorded necessary permit preparation financial statements accordance generally accepted accounting principles receipts expenditures made accordance authorizations management directors • provide reasonable assurance regarding prevention timely detection unauthorized acquisition use disposition assets could material effect financial statements supervision participation management including chief executive officer ceo chief financial officer cfo made assessment effectiveness internal control financial reporting december 31 2010 making assessment used criteria established internal control integrated framework issued committee sponsoring organizations treadway commission coso based evaluation concluded internal control financial reporting effective december 31 2010 effectiveness internal control financial reporting december 31 2010 audited ernst young llp independent registered public accounting firm stated report included herein report independent registered public accounting firm board directors stockholders el paso corporation audited accompanying consolidated balance sheets el paso corporation company december 31 2010 2009 related consolidated statements income comprehensive income equity cash flows three years period ended december 31 2010 audits also included financial statement schedule listed index item 15a financial statements schedule responsibility company’s management responsibility express opinion financial statements schedule based audits financial statements citrus corp subsidiaries corporation company 50 interest december 31 2010 2009 three years period ended december 31 2010 four star oil gas company corporation company approximately 49 interest year ended december 31 2008 audited auditors whose reports furnished us opinion consolidated financial statements insofar relates amounts included citrus corp subsidiaries four star oil gas company years periods herein referred based solely reports auditors consolidated financial statements company’s investments unconsolidated affiliates includes approximately 866 million 674 million citrus corp subsidiaries december 31 2010 2009 respectively company’s earnings unconsolidated affiliates includes approximately 90 million 65 million years ended december 31 2010 2009 respectively citrus corp subsidiaries approximately 147 million year ended december 31 2008 citrus corp subsidiaries four star oil gas company combined audited auditors conducted audits accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements audit also includes assessing accounting principles used significant estimates made management well evaluating overall financial statement presentation believe audits reports auditors provide reasonable basis opinion based audits reports auditors financial statements referred present fairly material respects consolidated financial position el paso corporation december 31 2010 2009 consolidated results operations cash flows three years period ended december 31 2010 conformity us generally accepted accounting principles also opinion related financial statement schedule considered relation basic financial statements taken whole presents fairly material respects information set forth therein discussed note 1 consolidated financial statements effective december 31 2009 company changed reserve estimates related disclosures result adopting new oil gas reserve estimation disclosure requirements also audited accordance standards public company accounting oversight board united states el paso corporation’s internal control financial reporting december 31 2010 based criteria established internal controlintegrated framework issued committee sponsoring organizations treadway commission report dated february 28 2011 expressed unqualified opinion thereon ernst young llp houston texas february 28 2011 report independent registered public accounting firm board directors stockholders el paso corporation audited el paso corporation’s internal control financial reporting december 31 2010 based criteria established internal control integrated framework issued committee sponsoring organizations treadway commission coso criteria el paso corporation’s management responsible maintaining effective internal control financial reporting assessment effectiveness internal control financial reporting included accompanying management’s annual report internal control financial reporting responsibility express opinion company’s internal control financial reporting based audit conducted audit accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether effective internal control financial reporting maintained material respects audit included obtaining understanding internal control financial reporting assessing risk material weakness exists testing evaluating design operating effectiveness internal control based assessed risk performing procedures considered necessary circumstances believe audit provides reasonable basis opinion company’s internal control financial reporting process designed provide reasonable assurance regarding reliability financial reporting preparation financial statements external purposes accordance generally accepted accounting principles company’s internal control financial reporting includes policies procedures 1 pertain maintenance records reasonable detail accurately fairly reflect transactions dispositions assets company 2 provide reasonable assurance transactions recorded necessary permit preparation financial statements accordance generally accepted accounting principles receipts expenditures company made accordance authorizations management directors company 3 provide reasonable assurance regarding prevention timely detection unauthorized acquisition use disposition company’s assets could material effect financial statements inherent limitations internal control financial reporting may prevent detect misstatements also projections evaluation effectiveness future periods subject risk controls may become inadequate changes conditions degree compliance policies procedures may deteriorate opinion el paso corporation maintained material respects effective internal control financial reporting december 31 2010 based coso criteria also audited accordance standards public company accounting oversight board united states 2010 consolidated financial statements el paso corporation report dated february 28 2011 expressed unqualified opinion thereon ernst young llp houston texas february 28 2011 report independent registered public accounting firm board directors stockholders citrus corp opinion consolidated balance sheets related consolidated statements income comprehensive income stockholders’ equity cash flows presented separately herein present fairly material respects financial position citrus corp subsidiaries “company” december 31 2010 2009 results operations cash flows three years period ended december 31 2010 conformity accounting principles generally accepted united states america financial statements responsibility company’s management responsibility express opinion financial statements based audits conducted audits statements accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements assessing accounting principles used significant estimates made management evaluating overall financial statement presentation believe audits provide reasonable basis opinion pricewaterhousecoopers llp houston texas february 25 2011 report independent registered public accounting firm stockholders four star oil gas company opinion consolidated balance sheet related consolidated statements income stockholders’ equity cash flows presented separately herein present fairly material respects financial position four star oil gas company “company” subsidiary december 31 2008 results operations cash flows year ended conformity accounting principles generally accepted united states america financial statements responsibility company’s management responsibility express opinion financial statements based audit conducted audit statements accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements assessing accounting principles used significant estimates made management evaluating overall financial statement presentation believe audit provides reasonable basis opinion described notes 3 4 financial statements company significant transactions affiliated companies relationships possible terms transactions would result transactions among wholly unrelated parties pricewaterhousecoopers llp houston texas february 20 2009 el paso corporation consolidated statements income millions except per common share amounts see accompanying notes el paso corporation consolidated balance sheets millions except share per share amounts see accompanying notes el paso corporation consolidated balance sheets millions except share per share amounts see accompanying notes el paso corporation consolidated statements cash flows millions see accompanying notes el paso corporation consolidated statements equity millions except per share amounts see accompanying notes el paso corporation consolidated statements comprehensive income millions see accompanying notes el paso corporation notes consolidated financial statements 1 basis presentation significant accounting policies basis presentation principles consolidation consolidated financial statements prepared accordance united states us generally accepted accounting principles gaap include accounts consolidated subsidiaries elimination significant intercompany accounts transactions financial statements prior periods include reclassifications made conform current year presentation none impacted reported net income loss stockholders’ equity consolidate entities ability control direct operating financial decisions entity significant interest entity gives us ability direct activities significant entity determination ability control direct exert significant influence entity involves use judgment apply equity method accounting exert significant influence control direct policies decisions activities entity use cost method accounting unable exert significant influence entity use estimates preparation financial statements requires use estimates assumptions affect amounts report assets liabilities revenues expenses disclosures financial statements actual results often differ estimates regulated operations interstate natural gas pipelines storage operations subject jurisdiction federal energy regulatory commission ferc follow financial accounting standards board’s fasb accounting standards regulated operations standards record regulatory assets liabilities would recorded nonregulated entities regulatory assets liabilities represent probable future revenues expenses associated certain charges credits expected recovered refunded customers rate making process items apply regulatory accounting requirements include certain postretirement employee benefit plan costs equity return component regulated capital projects certain costs related gas used operations costs included expected included future rates cash equivalents consider shortterm investments original maturity less three months cash equivalents maintain cash deposit banks insurance companies pledged particular use restricted support potential liability classify balances restricted cash current noncurrent assets balance sheet based expect restrictions cash removed allowance doubtful accounts establish provisions losses accounts notes receivable natural gas imbalances due shippers operators determine collect part outstanding balance regularly review collectability establish adjust allowance necessary using specific identification method property plant equipment pipelines excluding natural gas oil properties property plant equipment recorded original cost construction upon acquisition fair value assets acquired assets construct capitalize direct costs labor materials indirect costs overhead interest equity return component regulated businesses capitalize major units property replacements improvements expense minor items description methods use depreciate regulated property plant equipment see note 10 included pipeline property balances additional acquisition costs represent excess purchase costs associated purchase business combinations allocated regulated interstate systems’ property plant equipment costs amortized straightline basis recoverable rates current ferc policies retire property plant equipment regulated operations charge accumulated depreciation amortization original cost assets addition cost remove sell dispose assets less salvage value recognize gain loss unless sell entire operating unit defined ferc include gains losses dispositions operating units operations maintenance expense income statements natural gas oil properties use full cost method account natural gas oil properties full cost method substantially costs incurred connection acquisition development exploration natural gas oil reserves capitalized countrybycountry basis capitalized amounts include costs unproved properties internal costs directly related acquisition development exploration activities asset retirement costs capitalized interest full cost method dry hole costs geological geophysical costs capitalized full cost pool subject amortization periodically assessed impairment ceiling test calculation discussed capitalized costs associated proved reserves amortized life reserves using unit production method conversely capitalized costs associated unproved properties excluded amortizable base properties evaluated occurs quarterly transfer unproved property costs amortizable base properties determined proved reserves countries natural gas oil reserve base exists transfer unproved property costs amortizable base completed evaluation unproved properties additionally amortizable base includes future development costs dismantlement restoration abandonment costs net estimated salvage values geological geophysical costs incurred cannot associated specific unevaluated properties prospects direct interest capitalized costs country net related deferred income taxes limited ceiling based present value future net revenues proved reserves discounted 10 percent plus cost unproved natural gas oil properties amortized less related income tax effects perform ceiling test calculation quarter prior december 31 2009 utilized end period spot prices determine future net revenues result adoption sec’s final rule modernization oil gas reporting effective december 31 2009 utilize 12month average price calculated unweighted arithmetic average price first day month within 12month period prior end reporting period performing ceiling test also required hold prices constant life reserves even though actual prices natural gas oil volatile change period total capitalized costs exceed ceiling required writedown capitalized costs ceiling required writedown included ceiling test charge income statement increase accumulated depreciation depletion amortization balance sheet present value future net revenues used ceiling test calculations exclude estimated future cash outflows associated asset retirement liabilities related proved developed reserves sell convey interests natural gas oil properties reduce natural gas oil reserves amount attributable sold conveyed interest recognize gain loss sales natural gas oil properties unless sales would significantly alter relationship capitalized costs proved reserves treat sales proceeds nonsignificant sales adjustment cost properties asset investment divestituresimpairments evaluate assets investments impairment events circumstances indicate carrying values may recovered events include market declines believed temporary changes manner intend use longlived asset decisions sell asset investment adverse changes legal business environment adverse actions regulators event occurs evaluate recoverability carrying value based either longlived asset’s ability generate future cash flows undiscounted basis ii fair value investment unconsolidated affiliate impairment indicated decide sell longlived asset group assets adjust carrying values asset downward necessary estimated fair value fair value estimates generally based market data obtained sales process analysis expected discounted cash flows pension postretirement benefits maintain several pension postretirement benefit plans make contributions plans required fund benefits paid participants retirees contributions invested benefits paid plan participants net benefit cost plans recorded income statement function many factors including benefits earned year plan participants function factors employee’s salary level benefits provided plan actuarial assumptions passage time expected returns plan assets amortization certain deferred gains losses discussion policies respect pension postretirement benefit plans see note 13 accounting pension postretirement benefit plans record asset liability based funded status plan deferred amounts related unrecognized gains losses changes actuarial assumptions recorded either regulatory asset liability regulated operations accumulated comprehensive income loss component stockholders’ equity operations gains losses recognized income statement revenue recognition business segments provide number services sell variety products record revenues products services include estimates amounts earned unbilled estimate unbilled revenues based contractual data regulatory information commodity prices preliminary throughput allocation measurements among items revenue recognition policies significant operating segments follows pipelines revenues pipelines segment derives revenues primarily transportation storage services revenues services generally based thermal quantity gas delivered subscribed price specified contract transportation storage services recognize reservation revenues firm contracted capacity ratably contract period interruptible volumetric based services record revenues physical deliveries natural gas made agreed upon delivery point gas injected withdrawn storage facility contracts stepup stepdown rate provisions related changes levels service recognize reservation revenues ratably contract life gas used operations based volumes allowed retain relative amounts gas use operating purposes recognize revenue gas used operations shippers ferc allows us retain volumes market prices required tariffs subject ferc regulations result revenues collect rate proceedings may subject refund establish reserves potential refunds exploration production revenues exploration production segment derives revenues primarily physical sale natural gas oil condensate natural gas liquids revenues sales products recorded upon delivery passage title using sales method net royalty interests profit interests produced product actual sales volumes exceed entitled share sales volumes overproduced imbalance occurs extent overproduced imbalance exceeds share remaining estimated proved reserves given property record liability costs associated transportation delivery production included cost products services marketing revenues marketing segment derives revenues physical natural gas power transactions management derivative contracts derivative transactions recorded fair value changes fair value reflected net operating revenues discussion income recognition policies derivatives see price risk management activities impact nonderivative transactions including transportation contracts recognized net operating revenues based contractual market price related volumes time commodity delivered contracts terminated environmental costs contingencies environmental costs record liabilities undiscounted amounts balance sheet current longterm liabilities environmental assessments indicate remediation efforts probable costs reasonably estimated estimates liabilities based currently available facts existing technology presently enacted laws regulations taking consideration likely effects societal economic factors include estimates associated legal costs amounts also consider prior experience remediating contaminated sites companies’ cleanup experience data released environmental protection agency organizations estimates subject revision future periods based actual costs new circumstances capitalize costs benefit future periods recognize current period charge operation maintenance expense cleanup efforts benefit future periods evaluate amounts paid directly reimbursed government sponsored programs potential recoveries reimbursements remediation costs third parties including insurance coverage separately liability recovery evaluated based creditworthiness solvency third party among factors recovery assured record report asset separately associated liability balance sheet contingencies recognize liabilities contingencies exposure indicates probable liability incurred amount loss reasonably estimated likely outcome contingency reasonably estimated accrue liability amount likely outcome cannot estimated range potential losses established one amount range likely low end range accrued price risk management activities price risk management activities relate primarily derivatives entered hedge otherwise reduce commodity exposure natural gas oil production interest rate exposure longterm debt also hold derivatives intended hedge exposures derivatives reflected balance sheet fair value assets liabilities price risk management activities cash collateral associated derivatives significant financial statements classify derivatives either current noncurrent assets liabilities based anticipated settlement date net derivative assets liabilities counterparties legal right offset enter derivative contracts related price risk management activities may designate derivative either cash flow hedge fair value hedge cash flow hedges designed hedge forecasted sales transactions limit variability cash flows received paid related recognized asset liability changes fair value hedges deferred accumulated comprehensive income loss extent effective recognized revenues expenses hedged transactions occur ineffectiveness related cash flow hedges recognized earnings occurs fair value hedges entered protect fair value recognized asset liability firm commitment changes fair value hedges recognized earnings offsets changes fair value related hedged assets liabilities firm commitments derivatives designated hedges markedtomarket period changes fair value well realized amounts generally reflected operating revenues exploration production segment marketing segment cash flow statement cash inflows outflows associated settlement derivative instruments recognized operating cash flows balance sheet receivables payables resulting settlement derivative instruments reported trade receivables payables see note 7 discussion price risk management activities income taxes record current income taxes based current taxable income provide deferred income taxes reflect estimated future tax payments receipts deferred taxes represent tax impacts differences financial statement tax bases assets liabilities carryovers year end account tax credits flowthrough method reduces provision income taxes year tax credits first become available reduce deferred tax assets valuation allowance based estimates likely portion assets realized future period estimates utilized recognition deferred tax assets subject revision either future periods based new facts circumstances accounting asset retirement obligations record liability legal obligations associated replacement removal retirement longlived assets period obligation incurred asset retirement liabilities initially recorded estimated fair value corresponding increase property plant equipment increase property plant equipment depreciated useful life asset liability relates ongoing expense recognized changes value liability result passage time record depreciation depletion amortization expense income statement regulated pipelines ability recover certain costs customers recorded asset rather expense associated accretion liabilities described accounting stockbased compensation measure employee stockbased compensation awards fair value date awards granted employees recognize compensation cost financial statements requisite service period additional information stockbased compensation awards see note 15 2 acquisitions divestitures acquisitions 2010 2009 2008 acquired following assets gulf lng february 2008 paid approximately 295 million complete acquisition 50 percent interest gulf lng clean energy project lng terminal currently construction pascagoula mississippi terminal expected placed service late 2011 addition commitment loan gulf lng 150 million advanced approximately 83 million 56 million december 31 2010 2009 partners project commitment loan 64 million account investment gulf lng using equity method divestitures 2010 2009 2008 sold number assets investments proceeds follows 1 years ended december 31 2009 2008 sales proceeds increased 3 million 7 million exclude returns capital investments unconsolidated affiliates cash transferred assets sold amounts also net costs incurred preparing assets disposal 2010 divestitures primarily related sale approximately 300 million cash interests certain mexican pipeline compression assets ii sale 125 million cash 50 percent interest altamont gathering processing assets part new midstream joint venture included corporate conjunction sales recorded pretax gains 2010 approximately 80 million earnings unconsolidated affiliates mexico sale 110 million midstream sale three years ended december 31 2010 2009 2008 also sold natural gas oil properties pipeline assets related facilities legacy international power investments assets 3 ceiling test charges required conduct quarterly impairment tests capitalized costs full cost pools years ended december 31 2010 2009 2008 recorded following ceiling test charges 4 income expenses following components income expenses three years ended december 31 5 income taxes pretax income loss income tax expense benefit tables show pretax income loss components income tax expense benefit three years ended december 31 effective tax rate reconciliation income taxes included net income differs amount computed applying statutory federal income tax rate 35 percent following reasons three years ended december 31 2009 effective tax rate higher statutory rate primarily due recording 88 million income tax benefit relating us tax loss liquidation certain foreign entities following 2009 sale remaining significant international power projects entities liquidating value entities tax basis liquidation resulted tax loss 2008 overall effective tax rate differed statutory rate due primarily 05 billion ceiling test charge brazilian full cost pool corresponding us brazilian tax benefit impact ceiling test charge effective tax rate included foreign income loss taxed different rates valuation allowances table believe certain unconsolidated affiliates’ undistributed earnings ultimately distributed us dividends would eligible dividends received deduction joint venture partners intent ability recover cumulative undistributed earnings time dividends structured sale would result additional deferred tax liabilities december 31 2010 undistributed earnings unconsolidated affiliates expect receive dividends received deduction approximately 451 million deferred tax assets liabilities following components net deferred tax liability december 31 cumulative undistributed earnings substantially foreign subsidiaries foreign corporate joint ventures intended indefinitely reinvested foreign operations therefore provision made us taxes foreign withholding taxes may applicable upon actual deemed repatriation estimate taxes earnings repatriated practical december 31 2010 portion cumulative undistributed earnings investments recorded us income taxes approximately 83 million unrecognized tax benefits subject taxation us various states foreign jurisdictions exceptions longer subject state local foreign income tax examinations tax authorities years prior 1999 us income tax examinations years prior 2007 years returns still subject review unrecognized tax benefits could increase decrease income tax expense effective income tax rates matters finalized currently unable estimate range potential impacts resolution contested matters could financial statements following table shows change unrecognized tax benefits december 31 2010 2009 approximately 275 million 258 million net federal tax benefits unrecognized tax benefits associated interest penalties would affect income tax expense effective income tax rate recognized future periods amount unrecognized tax benefits could change next twelve months expect change significant impact results operations financial position classify interest penalties related unrecognized tax benefits income taxes financial statements 2010 2009 2008 recognized consolidated statements income 1 million 3 million 4 million interest penalties related unrecognized tax benefits december 31 2010 2009 51 million 52 million accrued interest penalties consolidated balance sheets tax credit net operating loss carryovers december 31 2010 us federal alternative minimum tax credits 290 million carryover indefinitely table presents details federal state net operating loss carryover periods december 31 2010 also 556 million foreign net operating loss carryovers 74 million foreign capital loss carryovers majority carryover indefinitely usage us federal carryovers subject limitations provided sections 382 383 internal revenue code well separate return limitation year rules irs regulations valuation allowances deferred tax assets recorded net operating losses temporary differences book tax basis assets liabilities expected produce tax deductions future periods realization assets depends recognition sufficient future taxable income specific tax jurisdictions periods temporary differences net operating losses deductible assessing need valuation allowance deferred tax assets consider whether likely portion realized part assessment consider future reversals existing taxable temporary differences primarily related depreciation december 31 2010 valuation allowance primarily relates deferred tax assets recorded state foreign net operating losses temporary differences valuation allowance related brazilian egyptian net operating losses established prior 2010 primarily result changes worldwide economic conditions created uncertainty outlook future taxable income particular tax jurisdictions 2010 increased valuation allowance 10 million deferred tax assets associated brazil egypt net operating losses reduced valuation allowance 3 million deferred tax assets associated expiring federal state net operating losses believe likely realize benefit deferred tax assets net existing valuation allowances 6 earnings per share basic diluted earnings loss per common share follows three years ended december 31 exclude potentially dilutive securities determination diluted earnings per share well related income statement impacts impact net income attributable el paso corporation per common share antidilutive potentially dilutive securities consist employee stock options restricted stock convertible preferred stock trust preferred securities year ended december 31 2010 trust preferred securities certain employee stock options antidilutive years ended december 31 2009 2008 incurred losses attributable el paso corporation accordingly excluded potentially dilutive securities determination diluted earnings per share discussion capital stock activity stockbased compensation arrangements instruments noted see notes 14 15 7 financial instruments following table reflects carrying value fair value financial instruments december 31 2010 2009 carrying amounts cash equivalents shortterm borrowings accounts receivable accounts payable represent fair value shortterm nature instruments carrying amounts restricted cash noncurrent receivables approximate fair value based nature interest rates assessment ability recover amounts estimated fair value debt based quoted market prices similar issues including consideration credit risk related instruments derivative financial instruments described also longterm debt fixed interest rates exposes us paying higher market rates interest rates decline use interest rate swaps designated fair value hedges protect value certain debt instruments converting fixed amounts interest due debt agreements variable interest payments record changes fair value derivatives interest expense offset changes fair value related hedged items december 31 2010 2009 interest rate swaps converted interest rate approximately 184 million 218 million debt fixed rate variable rate libor plus 418 crosscurrency derivatives 2009 settled crosscurrency swaps designated fair value hedges eurodenominated debt year ended december 31 2009 swaps increased interest expense approximately 3 million decreased income approximately 26 million result changing interest foreign currency rates 2009 fair value measurements use various methods determine fair values financial instruments fair value financial instrument depends number factors including availability observable market data contractual term underlying instrument data available similar instruments similar markets assumptions related estimates future settlements instrument separate fair values financial instruments three levels 1 2 3 based assessment availability observable market data significance nonobservable data used determine fair value assessment classification instrument within level change time based maturity liquidity instrument levels corresponding instruments classified level described • level 1 instruments’ fair values based quoted prices instruments actively traded markets included level marketable securities nonqualified compensation plans • level 2 instruments’ fair values primarily based pricing data representative quoted prices similar assets liabilities active markets identical assets liabilities less active markets included level interest rate swaps productionrelated natural gas oil derivatives certain natural gas derivatives natural gas supply arrangements whose fair values based commodity pricing data obtained third party pricing sources fair values also consider creditworthiness counterparties adjusted collateral related asset positions • level 3 instruments’ fair values partially calculated using pricing data similar level 2 also reflect adjustments less liquid markets longer contractual terms primarily included level powerrelated derivatives certain remaining natural gas derivatives determine fair value instruments obtain pricing data third party pricing sources develop estimate forward prices believe market participants would use based liquidity underlying forward markets contractual terms curves used estimate value settlements future periods based contractual settlement quantities dates valuation instruments considers specific contractual terms statistical simulation analysis present value concepts internal assumptions related contract maturities extend beyond periods quoted market prices available ii uniqueness contract terms iii limited availability forward pricing information markets lack viable participants pjm forward power market forward market ammonia iv creditworthiness counterparties adjusted collateral related asset positions financial statement presentation following table presents fair value financial instruments december 31 2010 2009 millions marketable securities nonqualified compensation plans reflected fair value balance sheets assets current liabilities liabilitieswe net derivative assets liabilities counterparties legal right offset classify derivatives either current noncurrent assets liabilities based anticipated settlement date december 31 2010 2009 cash collateral held material following table presents changes financial assets liabilities included level 3 years ended december 31 2010 2009 millions impacts commoditybased interest rate derivatives income statement comprehensive income loss years ended december 31 2010 2009 credit risk subject risk loss financial instruments would incur result nonperformance counterparties failure post required collateral pursuant terms contractual obligations exposures offset legally enforceable right setoff maintain credit policies regard counterparties minimize overall credit risk policies require evaluation potential counterparties’ financial condition including credit rating ii obtaining collateral certain circumstances including cash advance letters credit guarantees iii use margining provisions standard contracts iv use master netting agreements allow netting positive negative exposures various contracts associated single counterparty one counterparties fails perform may recognize immediate loss earnings well additional financial impacts future delivery periods extent replacement contract prices andor quantities cannot established use daily margining provisions financial contracts physical power agreements master netting agreements require counterparty post cash letters credit fair value contract exceeds daily contractual threshold amount typically tied published credit rating counterparty margining collateral provisions may terminate contract liquidate positions counterparty unable provide required collateral required return collateral amount posted collateral exceeds amount collateral required collateral received returned vary significantly day based changes market values counterparty’s credit ratings furthermore amount collateral hold may less fair value derivative contracts counterparty given period following table presents summary exposure derivative contracts net collateral liabilities right offset exists presented type derivative counterparty net asset exposure december 31 2010 2009 1 “investment grade” “below investment grade” determined using publicly available credit ratings “investment grade” includes counterparties minimum standard poor’s rating bbb moody’s investor service rating baa3 “below investment grade” includes counterparties public credit rating meet criteria “investment grade” “not rated” includes counterparties rated public rating service 2 consists primarily noncash collateral letters credit december 31 2010 approximately 48 counterparties derivative contracts based assessment counterparty risk light collateral counterparties posted us determined exposure primarily related productionrelated derivatives limited ten financial institutions current standard poor’s credit rating better additionally december 31 2010 three counterparties morgan stanley capital group rri energy services citibank comprise 26 percent 23 percent 20 percent respectively net financial instrument exposure december 31 2009 three counterparties williams gas marketing citibank rri energy services comprised 31 percent 13 percent 11 percent respectively net financial instrument asset exposure concentration counterparties may impact overall exposure credit risk either positively negatively counterparties may similarly affected changes economic regulatory conditions part assessment fair value financial liabilities also assess credit risk considering collateral posted related positions january 1 2009 adopted accounting standards update regarding companies consider credit determining fair value liabilities thirdparty credit enhancements related recorded 34 million gain net 18 million taxes 005 per share result adopting new accounting update 8 regulatory assets liabilities regulatory assets liabilities relate interstate pipeline operations included current noncurrent assets liabilities balance sheets see note 9 balances recoverable reimbursable various periods details regulatory assets liabilities december 31 significant regulatory assets liabilities include difference gas retained gas consumed operations amounts reflect value volumetric difference gas retained consumed operations amounts included rate base given tariffs expected recovered customers returned customers subsequent fuel filing periods taxes capitalized funds used construction regulatory asset balance established offset deferred tax equity component allowance funds used construction longlived assets taxes capitalized funds used construction offsetting deferred income taxes included rate base recovered depreciable lives long lived asset relate postretirement benefits represents unrecognized gains losses changes actuarial assumptions related postretirement benefit plans differences postretirement benefit related amounts expensed amounts recovered rates postretirement benefit amounts included rate base computations certain pipelines recoverable periods benefits funded unamortized net loss reacquired debt amount represents deferred unamortized portion losses reacquired debt recovered original life debt issue cost service environmental liability includes amounts collected substantially excess certain polychlorinated biphenyl pcb environmental remediation costs date surcharge tgp’s customers settlement approved ferc november 1995 time environmental liability deducted rate base tgp allowed earn current return property plant depreciation amounts represent deferral customerfunded amounts costs future asset retirements 9 assets liabilities detail current noncurrent assets liabilities balance sheets december 31 10 property plant equipment depreciable lives table presents depreciation methods depreciable lives property plant equipment 1 composite group method assets similar useful lives characteristics grouped depreciated one asset apply depreciation rate approved rate settlements total cost group net book value equals salvage value reevaluate depreciation rates time file ferc increase decrease rates 2 capitalized costs associated proved reserves amortized life reserves using unit production method conversely capitalized costs associated unproved properties excluded amortizable base properties evaluated excess purchase costs december 31 2010 2009 tgp epng excess purchase costs associated historical acquisition total excess costs pipelines approximately 25 billion accumulated depreciation approximately 05 billion december 31 2010 2009 excess costs depreciated estimated life pipeline assets costs assigned related depreciation expense year ended december 31 2010 2009 2008 approximately 42 million capitalized costs construction capitalize carrying cost funds related construction longlived assets reflect amounts increases cost asset balance sheet capitalize allowance funds used construction afudc consists interest cost debt could attributed assets constructed ii regulated pipelines return equity could attributed assets constructed equity portion calculated using recent ferc approved equity rate return interest costs capitalized included reduction interest expense income statements 60 million 48 million 45 million years ended december 31 2010 2009 2008 equity amounts capitalized exclusive taxes ferc regulated business included nonoperating income statement 156 million 61 million 37 million years ended december 31 2010 2009 2008 amounts recovered depreciable lives longlived assets relate noncash investing activities construction workin progress december 31 2010 2009 approximately 48 billion 36 billion construction workinprogress included property plant equipment asset retirement obligations legal obligations associated retirement natural gas oil wells related infrastructure natural gas pipelines transmission facilities storage wells exploration production operations obligations plug wells abandoned production exhausted longer plan use wells pipeline operations legal obligations primarily involve purging sealing pipelines abandoned also obligations remove hazardous materials associated natural gas transmission facilities ever demolished replaced continue evaluate asset retirement obligations future developments could impact amounts record reasonably estimate asset retirement obligation accrue liability based estimate timing amount settlement estimating asset retirement obligations utilize several assumptions including projected inflation rate 25 percent creditadjusted discount rates currently range 5 12 percent based liabilities recorded record changes estimates based changes expected amount timing payments settle obligations typically changes result obtaining new information timing obligations plug abandon natural gas oil wells costs certain events accelerate timing asset retirements eg impact hurricanes pipelines operations intend operating maintaining natural gas pipeline storage systems long supply demand natural gas exists expect foreseeable future therefore believe cannot reasonably estimate asset retirement obligation substantial majority natural gas pipeline storage system assets indeterminate lives net asset retirement obligation december 31 reported balance sheet current noncurrent liabilities changes net liability years ended december 31 follows 1 reflects updated information received hurricane related asset retirement obligations 11 debt financing obligations credit facilities following provides additional detail financing obligations changes financing obligations 2010 following changes longterm financing obligations millions loss debt extinguishment 2010 exchanged approximately 349 million 1200 senior notes due 2013 cash 650 senior notes due 2020 conjunction transaction paid 77 million cash premiums recorded loss debt extinguishment 105 million december 2010 repurchased approximately 709 million senior notes conjunction transaction paid 91 million cash premiums recorded loss debt extinguishment 112 million debt maturities aggregate maturities principal amounts longterm financing obligations december 31 2010 next 5 years total thereafter follows millions credit facilitiesletters credit various credit facilities place allow us borrow funds issue letters credit surety bonds enter letters credit issue surety bonds ordinary course operating activities well periodically conjunction sales assets businesses december 31 2010 total debt outstanding 08 billion approximately 11 billion outstanding letters credit surety bonds issued facilities including approximately 05 billion related price risk management activities listed description credit facilities including remaining capacity facilities december 31 2010 1 based december 31 2010 credit rating applicable margin used calculate interest borrowings letters credit commitment fees determined variable pricing grid tied credit ratings senior secured debt 2 based december 31 2010 borrowing levels 3 facility available epb subsidiaries borrowings guaranteed epb subsidiaries amounts borrowed nonrecourse el paso borrowing capacity expandable 125 billion certain expansion projects acquisitions 4 interest rate based epb’s december 31 2010 credit rating credit facility two pricing grids one based credit ratings based leverage restrictive covenants collateral provisions 15 billion revolving credit agreement el paso certain subsidiaries guaranteed facility collateralized stock ownership epng tgp also eligible borrowers covenants 15 billion revolving credit facility include restrictions debt levels restrictions liens securing debt guarantees restrictions mergers sales assets dividend restrictions cross default crossacceleration provisions breach covenants could result acceleration debt financial obligations subsidiaries credit agreement restrictive debt covenants cross default provisions ratio debt consolidated earnings interest income taxes depreciation amortization ebitda defined credit agreement shall exceed 525 1 maturity b ratio consolidated ebitda defined credit agreement interest expense plus dividends paid shall less 20 1 maturity c epng tgp cannot incur incremental debt incurrence incremental debt would cause debt consolidated ebitda ratio defined credit agreement particular company exceed 50 1 occurrence event default expiration applicable grace period respect debt aggregate principal amount 200 million epep 10 billion 300 million revolving credit agreements facilities collateralized certain natural gas oil properties 10 billion credit agreement subject revaluation semiannual basis november 2010 existing borrowing base approved banks december 31 2010 recent determination sufficient fully support facility epep’s borrowings facilities also subject conditions financial coverage ratio facilities requires epep’s ebitda defined facility interest expense less 20 1 epep’s debt ebitda defined credit agreement must exceed 40 1 eppoc 750 million revolving credit facility requires epb maintain consolidated leverage ratio consolidated indebtedness consolidated ebitda defined credit facility less 50 10 four consecutive quarter periods 55 10 four quarter period three full fiscal quarters subsequent consummation specified acquisitions borrowings facility restricted use epb subsidiaries restrictions provisions addition restrictions provisions andor subsidiaries subject various financial nonfinancial covenants restrictions covenants restrictions include limitations additional debt subsidiaries limitations use proceeds borrowing subsidiaries limitations cases transactions affiliates limitations incurrence liens limitations subsidiaries participate cash management program potential limitations ability subsidiaries declare pay dividends december 31 2010 restricted net assets consolidated subsidiaries approximately 09 billion primarily related restrictions ability receive distributions ruby project placed service restrictive crossacceleration provision associated indenture one subsidiaries indenture states event default occur resulting acceleration debt obligations subsidiary excess 10 million longterm debt obligation containing provision could accelerated acceleration debt would adversely affect liquidity position turn financial condition also issued various guarantees securing financial obligations subsidiaries affiliates similar covenants facilities financing arrangements capital trusts el paso energy capital trust wholly owned business trust issued 65 million 475 percent trust convertible preferred securities 325 million trust exists sole purpose issuing preferred securities investing proceeds 475 percent convertible subordinated debentures issued due 2028 trust i’s sole source income interest earned debentures interest income used pay distributions preferred securities provide full unconditional guarantee trust i’s preferred securities trust i’s preferred securities nonvoting except limited circumstances pay quarterly distributions annual rate 475 percent carry liquidation value 50 per security plus accrued unpaid distributions convertible common shares time prior close business march 31 2028 option holder rate 12022 common shares trust preferred security equivalent conversion price 4159 per common share classified securities longterm debt right redeem securities time wyco development llc wyco conjunction construction totem gas storage facility high plains pipeline joint venture partner wyco funded 50 percent construction costs reflected payments made joint venture partner noncurrent liabilities balance sheet construction project completion advances converted financing obligation wyco december 31 2010 principal amounts totem gas storage facility high plains pipeline facility 75 million 104 million respectively paid monthly installments 2039 extended term related firm service agreements 2060 2043 respectively interest payments obligations based 50 percent operating results facilities’ currently estimated 155 percent rate december 31 2010 ruby pipeline financing may 2010 entered sevenyear amortizing 15 billion credit facility ruby pipeline project requires principal payments various dates june 2017 2010 borrowed approximately 11 billion credit facility 2011 utilized substantially remaining capacity facility initial interest rate amounts borrowed libor plus 3 percent increases libor plus 325 percent years three four libor plus 375 percent years five seven assuming refinance 700 million facility end year four refinance 700 million end year four rate libor plus 425 percent years five seven conjunction entering facility entered interest rate swaps begin july 2011 convert floating libor interest rate fixed interest rates approximately 11 billion total borrowings agreement discussion swaps see note 7 provided contingent completion costoverrun guarantee ruby lenders however upon ruby pipeline project becoming operational making certain permitting representations project financing become nonrecourse us pursuant cost overrun guarantee ruby lenders required post letters credit forecasted cost overruns project approved lender’s independent engineer december 31 2010 posted 304 million letters credit cover anticipated cost overruns additional cost overruns forecasted approved lender’s engineer subsequent months additional letters credit required issued pursuant ruby financing agreements 12 commitments contingencies legal proceedings cash balance plan lawsuit december 2004 purported class action lawsuit entitled tomlinson et alv el paso corporation el paso corporation pension plan filed us district court denver colorado lawsuit alleges various violations employee retirement income security act age discrimination employment act result change final average earnings formula pension plan cash balance pension plan 2010 trial court dismissed claims matter dismissal case appealed retiree medical benefits matters 2002 lawsuit entitled yolton et al v el paso tennessee pipeline co case corporation filed federal court detroit michigan lawsuit filed behalf group retirees case corporation case alleged entitled retiree medical benefits medical benefits plan serve plan administrator pursuant merger agreement tenneco inc although asserted obligations plan subject cap pursuant agreement union case employees trial court ruled benefits vested subject cap result currently obligated pay amounts cap addition obligated pay damages incurred retirees prior court’s ruling benefits subject cap 2008 recorded 65 million reduction operation maintenance expense related remeasurement recorded obligation using actuarial assumptions agreed upon damage calculation methodology plaintiffs methodology approved court believe accruals established matter adequate price reporting litigation beginning 2003 several lawsuits filed el paso marketing lp epm alleging el paso epm energy companies conspired manipulate price natural gas providing false price information industry trade publications published gas indices cases settled dismissed several cases various stages pretrial appellate proceedings seven remaining lawsuits consist six cases pending united states district court district nevada including jp morgan trust company na liquidating trustee v oneok inc et al filed august 2005 breckenridge et al v el paso corporation et al filed may 2006 learjet v el paso corporation et al filed november 2004 arandell corporation et al v el paso corporation et al filed december 2006 heartland regional et al v el paso corporation et al filed april 2007 newpage wisconsin system inc v cms energy resource management company et al filed march 2009 ii one case pending state court montana state montana v williams energy marketing et al filed july 2003 served el paso although damages excess 140 million alleged total defendants one remaining lawsuits damage number provided remains significant uncertainty regarding validity causes action damages asserted level damages may allocated us therefore costs legal exposure related remaining outstanding lawsuits claims currently determinable mtbe certain subsidiaries used produced sold distributed methyl tertiarybutyl ether mtbe gasoline additive various lawsuits filed throughout us regarding potential impact mtbe water supplies lawsuits brought different parties including state attorney generals water districts individual water companies seeking different remedies us many defendants including remedial activities damages attorneys’ fees costs cases initially consolidated pretrial purposes multidistrict litigation us district court southern district new york several cases later remanded state court eightyseven cases settled dismissed settlements substantially funded insurance twelve remaining lawsuits consist ten cases pending mdl including city fresno v chevron usa et al filed october 2003 new jersey dept environmental protection v atlantic richfield et al filed june 2007 city pomona v chevron et al filed december 2008 village roanoke v ashland et al filed april 2009 village bethalto v ashland et al filed april 2010 town kouts v ashland et al filed may 2010 coraopolis water sewer authority v ashland et al filed july 2010 bridgewater water dept v atlantic richfield et al filed september 2010 city kennett v ashland et al filed september 2010 city pattonsburgh v ashland et al filed october 2010 ii two cases pending state courts including state new hampshire v amerada hess et al filed october 2003 state court new hampshire mayor council berlin et al v ashland et al filed april 2010 state court maryland remaining lawsuits likely insurers assert denial coverage nine mostrecently filed lawsuits although damages excess two billion dollars alleged total defendants remaining cases based upon discovery conducted date share relevant markets upon alleged damages historically allocated among individual defendants relatively small addition remains significant uncertainty regarding validity causes action damages asserted level damages may allocated us well availability insurance coverages therefore costs legal exposure related remaining lawsuits currently determinable addition proceedings subsidiaries affiliates named defendants numerous lawsuits governmental proceedings claims arise ordinary course business also regulatory rules orders various stages adoption review andor implementation matters evaluate merits case claim exposure matter possible legal settlement strategies likelihood unfavorable outcome determine unfavorable outcome probable estimated establish necessary accruals outcome matters including discussed cannot predicted certainty still uncertainties related costs may incur based upon evaluation experience date believe established appropriate reserves matters possible however new information future developments could require us reassess potential exposure related matters adjust accruals accordingly adjustments could material december 31 2010 approximately 45 million accrued outstanding legal proceedings rates regulatory matters epng rate case april 2010 ferc approved uncontested partial offer settlement increased epng’s base tariff rates effective january 1 2009 part settlement epng made refunds customers 2010 settlement resolved four issues proceeding january 2011 presiding administrative law judge issued decision part found epng four issues epng appeal decisions ferc may also seek review ferc’s decisions us court appeals although final outcome currently determinable believe accruals established matter adequate based expected final outcome september 2010 epng filed new rate case ferc proposing increase base tariff rates permitted settlement previous rate case october 2010 ferc issued order accepting suspending effective date proposed rates april 1 2011 subject refund outcome hearing proceedings time outcome matter currently determinable tgp rate case november 2010 tgp filed rate case ferc proposing increase base tariff rates including proposed change rate structure expected increase percentage reservation revenues tgp relative revenues derived excess fuel recoveries throughput system december 2010 ferc issued order accepting suspending effective date proposed rates june 1 2011 subject refund outcome hearing proceedings time outcome matter currently determinable cig rate case terms 2006 rate case settlement cig must file new general rate case effective later october 1 2011 late january 2011 cig filed ferc amendment 2006 settlement unopposed cig’s shippers request modification settlement allow effective date required new rate case moved december 1 2011 purpose delay filing date allow cig shippers opportunity reach settlement rate proceeding formally filed ferc time outcome prefiling settlement negotiations outcome upcoming general rate case event prefiling settlement cannot reached uncertain environmental matters subject federal state local laws regulations governing environmental quality pollution control laws regulations require us remove remedy effect disposal release specified substances current former operating sites december 31 2010 accrued approximately 173 million environmental matters reduced 19 million amounts paid directly government sponsored programs settlement arrangements third parties accrual includes approximately 170 million expected remediation costs associated onsite offsite groundwater technical studies approximately 3 million related environmental legal costs estimates potential liability range approximately 173 million approximately 365 million recorded environmental liabilities reflect current estimates amounts expend remediation projects various stages completion however depending stage completion assessment ultimate extent contamination remediation required may known additional assessments occur remediation efforts continue may incur additional liabilities type site reserves based following estimates reasonably possible outcomes superfund matters included recorded environmental liabilities projects received notice designated could designated potentially responsible party prp comprehensive environmental response compensation liability act cercla commonly known superfund state equivalents 31 active sites liability federal cercla statute may joint several meaning could required pay excess pro rata share remediation costs consider financial strength prps estimating liabilities accruals issues included previously indicated estimates superfund sites 2011 estimate total remediation expenditures approximately 48 million expended government directed cleanup plans addition expect make capital expenditures environmental matters approximately 24 million aggregate years 2011 2015 including capital expenditures associated impact environmental protection agency epa rule emissions hazardous air pollutants reciprocating internal combustion engines subject regulations compliance october 2013 possible new information future developments could require us reassess potential exposure related environmental matters may incur significant costs liabilities order comply existing environmental laws regulations also possible developments increasingly strict environmental laws regulations orders regulatory agencies well claims damages property environment injuries employees persons resulting current past operations could result substantial costs liabilities future information becomes available relevant developments occur adjust accrual amounts accordingly still uncertainties related ultimate costs may incur based upon evaluation experience date believe reserves adequate commitments purchase obligations matters operating leases maintain operating leases ordinary course business activities leases include office space operating facilities equipment terms agreements vary 2011 2053 future minimum annual rental commitments operating leases net minimum sublease rentals december 31 2010 follows rental expense 39 million years ended december 31 2010 2009 2008 reflected operation maintenance expense included rental expense approximately 21 million period associated rightofway arrangements principally related longterm commitment extends 2025 guarantees indemnifications involved various joint ventures ownership arrangements sometimes require financial performance guarantees financial guarantee obligated make payments guaranteed party fails make payments violates terms financial arrangement performance guarantee provide assurance guaranteed party execute terms contract required perform behalf also periodically provide indemnification arrangements related assets businesses sold arrangements include limited indemnifications income taxes resolution existing disputes environmental matters potential exposure guarantee indemnification agreements range specified amount unlimited dollar amount depending nature claim specificity duration particular transaction arrangements specified dollar amount maximum stated value approximately 08 billion primarily related indemnification arrangements associated sale anr pipeline company 2007 macae power facility brazil legacy assets amounts exclude guarantees issued related letters credit discussed note 11 included maximum stated value certain indemnification agreements expired however claims made prior expiration related claim periods unable estimate maximum exposure guarantee indemnification agreements provide limits amount future payments due uncertainty exposures december 31 2010 2009 recorded obligations 18 million 52 million related guarantee indemnification arrangements liability consists primarily indemnification one subsidiaries provided related sale ammonia facility reflected financial statements estimated fair value provided partial parental guarantee subsidiary’s obligations indemnification believe guarantee indemnification agreements recorded liability probable resulting future losses based assessment nature guarantee financial condition guaranteed party period time guarantee outstanding among considerations purchase obligations construction contracts purchase pipe primarily associated ruby pipeline project tgp’s 300 line project anticipated placed service 2011 agreements estimate approximately 640 million obligations 2011 commercial commitments 2009 ferc approved amendment 1995 ferc settlement tgp provides interim refunds three year period approximately 157 million amounts collected related certain environmental costs refunds recorded current noncurrent liabilities balance sheet expected paid three year period interest december 31 2010 tgp refunded approximately 58 million customers various commercial commitments purchase obligations recorded balance sheet december 31 2010 firm commitments transportation storage capacity contracts 783 million due various times purchase capital commitments including maintenance engineering procurement construction contracts approximately 420 million majority due less one year also hold cancelable easements rightofway arrangements landowners permitting use land construction operation pipeline systems see operating leases 13 retirement benefits overview retirement benefit plans pension plans primary pension plan defined benefit plan covers substantially us employees provides benefits cash balance formula certain employees participated prior pension plans el paso sonat inc coastal corporation receive greater cash balance benefits transition benefits prior plan formulas anticipate making contributions cash balance pension plan 2011 addition primary pension plan maintain supplemental executive retirement plan serp provides additional benefits selected officers key management serp provides benefits excess certain irs limits essentially mirror primary pension plan expect contribute 4 million serp 2011 retirement savings plan maintain defined contribution plan covering us employees match 75 percent participant basic contributions six percent eligible compensation make additional discretionary matching contributions depending overall performance company relative peers amounts expensed plan approximately 39 million 19 million 20 million years ended december 31 2010 2009 2008 2010 amount expensed includes additional discretionary matching contribution postretirement benefit plans provide postretirement benefits opeb including medical benefits closed groups retired employees certain retirees case described note 12 limited postretirement life insurance benefits current retired employees medical benefits closed groups retirees may subject deductibles copayment provisions limitations dollar caps amount employer costs reserve right change benefits opeb plans regulated pipeline companies prefunded extent costs recoverable rates extent opeb costs regulated pipeline companies differ amounts recovered rates regulatory asset liability recorded information see note 8 expect contribute 46 million postretirement benefit plans 2011 benefit obligation plan assets funded status accounting pension postretirement plans record asset liability based funded status plan deferred amounts related unrecognized gains losses changes actuarial assumptions recorded either regulatory asset liability regulated operations accumulated comprehensive income loss component stockholders’ equity operations gains losses recognized income statement matters various court rulings prior march 2008 required indemnify case corporation case certain benefits paid closed group case retirees discussed note 12 conjunction rulings recorded liability estimated amounts due indemnification using actuarial methods similar used estimating postretirement benefit plan obligations liability however included postretirement benefit obligations disclosures prior 2008 first quarter 2008 received summary judgment trial court matter thus became primary party obligated pay benefit payments result judgment adjusted obligation using current actuarial assumptions recording 65 million reduction operation maintenance expense table provides information pension opeb plans years ended december 31 1 benefit obligation pension plans represents projected benefit obligation benefit obligation postretirement benefit plans represents accumulated postretirement benefit obligation 2 amounts postretirement benefits shown net subsidy approximately 5 million 6 million years ended december 31 2010 2009 related medicare prescription drug improvement modernization act 2003 3 defer difference actual return plan assets expected return three year period considered inclusion net benefit expense income deferred actuarial gains losses amortized extent remaining unrecognized actual gains losses exceed greater 10 percent benefit obligations market related value plan assets components funded status following table details amounts recognized balance sheet december 31 2010 2009 related pension opeb plans components accumulated comprehensive income loss following table details amounts recognized accumulated comprehensive income loss net income taxes december 31 2010 2009 related pension opeb plans anticipate approximately 60 million accumulated comprehensive loss net tax recognized part net periodic benefit cost 2011 accumulated benefit obligation defined benefit pension plans 22 billion 21 billion december 31 2010 2009 accumulated benefit obligation defined benefit pension plans whose accumulated benefit obligations exceeded fair value plan assets 22 billion 21 billion december 31 2010 2009 fair value plans’ assets approximately 20 billion december 31 2010 2009 accumulated postretirement benefit obligation opeb plans whose accumulated postretirement benefit obligations exceeded fair value plan assets 558 million 542 million december 31 2010 2009 fair value plans’ assets 58 million 55 million december 31 2010 2009 plan assets primary investment objective plans ensure longterm life plans adequate pool sufficiently liquid assets exists meet benefit obligations participants retirees beneficiaries investment objectives longterm nature covering typical market cycles shortfall investment performance compared investment objectives generally result economic capital market conditions plans’ investments include wide diversification asset types fund strategies fund managers although actual allocations vary time targeted allocations target allocations pension plans’ assets 50 percent equity securities 40 percent fixed income securities 10 percent types investments target allocations postretirement plans’ assets 65 percent equity 35 percent fixed income securities equity securities pension plans’ assets may include investments largecap midcap smallcap companies united states well investments foreign companies fixed income securities may include corporate bonds companies diversified industries well international fixed income securities united states treasuries stable income products investment contracts types investments may include hedge funds real estate investments follow several different strategies opeb plans may invest plan assets manner replicates extent feasible russell 3000 index barclays capital aggregate bond index achieve equity fixed income diversification respectively details pension opeb plans assets classified level description fair values • level 1 assets’ fair values based quoted prices actively traded markets included level equity securities fixed income securities exchange traded mutual fund securities • level 2 assets’ fair values primarily based pricing data representative quoted prices similar assets active markets identical assets less active markets included level common collective trust funds mutual funds certain fixed income securities common collective trust funds’ mutual funds’ fair values primarily based net asset value reported issuer determined based fair value underlying securities valuation date common collective trust funds mutual funds certain restrictions redemption exist december 31 2010 issuer reserves right temporarily delay withdrawal certain situations market conditions issuer’s discretion fixed income securities fair values primarily based evaluated price based compilation primarily observable market information broker quote nonactive market • level 3 assets’ fair values similar level 2 assets also subject additional restrictions associated timing redemption extend beyond 90 days december 31 2010 included level mutual fund whose fair value primarily based net asset value reported issuer determined based fair value underlying securities valuation date listed fair values pension opeb plans’ assets recorded fair value classified level december 31 2010 2009 millions 1 category includes common collective trust funds invested approximately 65 percent equity 35 percent fixed income securities following table presents changes pension plan asset included level 3 year ended december 31 2010 millions expected payment future benefits december 31 2010 expect following benefit payments plans actuarial assumptions sensitivity analysis benefit obligations net benefit cost based actuarial estimates assumptions following table details weightedaverage actuarial assumptions used determining benefit obligation december 31 2010 2009 2008 net benefit costs pension opeb plans 2010 2009 2008 1 expected return plan assets pretax rate return based targeted portfolio investments postretirement benefit plans’ investment earnings subject unrelated business income tax rate 35 expected return plan assets postretirement benefit plans calculated using aftertax rate return actuarial estimates opeb plans assumed weightedaverage annual rate increase per capita costs covered health care benefits 74 percent gradually decreasing 50 percent year 2016 assumed health care cost trends significant effect amounts reported opeb plans onepercentage point change assumed health care cost trends would following effects december 31 2010 2009 components net benefit cost income years ended december 31 components net benefit cost income follows components comprehensive income loss following table details amounts recognized comprehensive loss net income taxes years ended december 31 2010 2009 2008 related pension opeb plans 14 equity preferred stock subsidiaries convertible perpetual preferred stock 750 million convertible perpetual preferred stock outstanding dividends preferred stock declared approved quarterly accumulate paid share preferred stock convertible holder’s option time subject adjustment 772295 shares common stock certain conditions conversion rate represents equivalent conversion price 1295 per share conversion rate subject adjustment based certain events include limited fundamental changes business mergers business combinations well distributions common stock payment dividends common stock excess specified rate common preferred stock dividends table shows amount dividends declared paid dollars millions dividends common stock preferred stock treated reduction additional paidincapital since currently accumulated deficit expect dividends paid common preferred stock 2010 taxable stockholders anticipate dividends paid current accumulated earnings profits tax purposes terms 750000 outstanding shares 499 convertible preferred stock provide conversion ratio preferred stock increase pay quarterly dividends common shareholders excess 004 per share terms preferred shares also prohibit payment dividends common stock unless paid set aside payment accumulated unpaid dividends preferred stock preceding dividend periods addition although credit facilities contain direct restriction payment dividends included fixed charge calculation fixed charge coverage ratio credit facilities unable comply fixed charge ratio ability pay additional dividends would restricted accumulated comprehensive income loss following table provides components accumulated comprehensive income loss december 31 millions noncontrolling interests general partner epb master limited partnership mlp formed 2007 december 31 2010 hold 2 percent general partner interest 49 percent limited partner interest comprised common subordinated units partnership years ended december 31 2010 2009 2008 issued noncontrolling interests net issuance costs 13 billion 212 million 15 million conjunction contribution epb additional ownership interests cig sng 100 percent ownership interests southern lng company llc slng owns elba island lng receiving terminal el paso elba express company llc elba express owns elba express pipeline extent consideration paid epb us sales pipeline assets epb form additional equity epb interest pipeline assets become diluted time accordance partnership agreement epb obligated make quarterly distributions available cash unitholders receive share cash distributions limited partner ownership interest general partner interest incentive distribution rights idr’s entitled general partner prior february 15 2011 held subordinated units epb upon payment quarterly cash distribution fourth quarter 2010 financial tests required conversion subordinated units common units satisfied result subordinated units converted february 15 2011 common units oneforone basis effective january 3 2011 incentive distribution rights pay increasing percentage interest quarterly distributions cash based level distribution unitholders holder rights elect relinquish right receive incentive distribution payments based initial cash target distribution levels reset higher levels minimum quarterly distribution amount cash target distribution levels upon incentive distribution payments would set currently entitled receive maximum level idrs additional information regarding master limited partnership see net income attributable noncontrolling interests table note 11 preferred stock subsidiaries 2009 global infrastructure partners gip partner ruby pipeline project contributed 145 million subsidiary ruby pipeline holding company llc ruby received convertible preferred equity interest ruby simultaneously exchanged convertible preferred equity interest cheyenne plains investment company llc cheyenne plains gip earns 15 percent dividend preferred interests cheyenne plains addition gip provided 405 million loan ruby project funding 2010 gip’s loan 405 million converted convertible preferred equity interest ruby addition gip provided additional 120 million contribution convertible preferred equity interest ruby gip earn 13 percent return convertible preferred interests ruby beginning earlier date pipeline project placed service august 2011 discussion ruby transaction see note 17 convertible preferred equity interests cheyenne plains ruby classified liabilities equity balance sheet since events require redemption preferred interests entirely within control certain occur paid preferred dividends 21 million gip’s preferred interest cheyenne plains year ended december 31 2010 also year ended december 31 2010 recognized return 27 million gip’s preferred interest ruby preferred dividends return gip’s preferred interests reflected net income attributable noncontrolling interests income statement components net income attributable noncontrolling interests statements income year ended december 31 follows millions 15 stockbased compensation overview stockbased compensation plans may issue employees incentive stock options common stock intended qualify section 422 internal revenue code nonqualified stock options restricted stock restricted stock units stock appreciation rights performance shares performance units stockbased awards authorized grant awards approximately 62 million shares common stock current plans includes 545 million shares omnibus plan 25 million shares nonemployee director plan 5 million shares employee stock purchase plan december 31 2010 approximately 235 million shares remain available grant current plans includes approximately 198 million shares omnibus plan 16 million shares nonemployee director plan 21 million shares employee stock purchase plan also approximately 10 million shares stock option awards outstanding granted terminated plans obligate us issue additional shares common stock exercised stock option exercises restricted stock funded primarily issuance new common shares record stockbased compensation expense excluding amounts capitalized operation maintenance expense requisite service period separately vesting portion award net estimates forfeitures actual forfeitures differ estimates additional adjustments compensation expense required future periods nonqualified stock options grant nonqualified stock options employees exercise price equal market value stock grant date stock option awards contractual terms 10 years generally vested equal amounts three years grant date pay dividends unexercised options summary stock option transactions year ended december 31 2010 presented 2010 2009 2008 recognized approximately 24 million 23 million 21 million pretax compensation expense stock options capitalized approximately 4 million 5 million 4 million expense part fixed assets recorded 8 million 8 million 7 million income tax benefits respectively total compensation cost related nonvested option awards yet recognized december 31 2010 approximately 19 million expected recognized weighted average period 10 months options exercised years ended december 31 2010 2009 2008 total intrinsic value 5 million less 1 million 10 million generated 8 million 1 million 11 million cash proceeds generate significant associated income tax benefit fair value assumptions fair value stock option granted estimated date grant using blackscholes optionpricing model based several assumptions based management’s best estimate time grant years ended december 31 2010 2009 2008 weighted average grant date fair value per share options granted 455 296 573 listed weighted average assumption based grants fiscal year estimate expected volatility based analysis implied volatilities traded options common stock historical stock price volatility expected term adjusted certain time periods believe representative future stock performance estimate expected term option awards based vesting period average remaining contractual term referred “simplified method” use method provide reasonable basis estimating expected term based insufficient historical data prior 2006 primarily due significant changes composition employees receiving stockbased compensation awards restricted stock may grant shares restricted common stock carry voting dividend rights officers employees sale transfer shares restricted vest currently outstanding grant timebased restricted stock fair value timebased restricted shares determined grant date shares generally vested equal amounts three years date grant summary changes nonvested restricted shares fiscal years presented weighted average grant date fair value per share restricted stock granted 2010 2009 2008 1109 653 1546 total fair value shares vested 2010 2009 2008 27 million 13 million 29 million 2010 2009 2008 recognized approximately 25 million 26 million 29 million pretax compensation expense restricted share awards capitalized approximately 4 million 7 million 7 million expense part fixed assets recorded 9 million 9 million 10 million income tax benefits related restricted stock arrangements total unrecognized compensation cost related arrangements december 31 2010 approximately 19 million expected recognized weighted average period 10 months employee stock purchase plan employee stock purchase plan allows participating employees right purchase common stock 95 percent market price last trading day month plan noncompensatory provisions current stock compensation accounting standards shares issued plan insignificant 2010 2009 2008 16 business segment information december 31 2010 business consists two core segments pipelines exploration production also marketing segment segments strategic business units provide variety energy products services managed separately segment requires different technology marketing strategies prior 2010 also power segment combined corporate activities periods presented discussion segment corporate activities follows pipelines segment provides natural gas transmission storage related services primarily united states december 31 2010 conducted activities primarily eight wholly majority owned interstate pipeline systems equity interests two transmission systems addition storage capacity wholly majority owned pipelines systems also interests three underground natural gas storage facilities two lng terminalling facilities one construction exploration production exploration production segment engaged exploration acquisition development production natural gas oil ngl united states brazil egypt marketing segment markets manages price risks associated natural gas oil production well manages remaining legacy trading portfolio corporate activities include general administrative functions emerging midstream business remaining power operations miscellaneous businesses customers whose revenues exceeded 10 percent total revenues 2010 2009 2008 management uses earnings interest expense income taxes ebit measure assess operating results effectiveness business segments consist consolidated businesses investments unconsolidated affiliates believe ebit useful investors allows evaluate effectively operating performance using performance measure analyzed internally management investors may evaluate operating results without regard financing methods capital structure define ebit net income loss adjusted items interest debt expense ii income taxes iii net income attributable noncontrolling interests ebit may comparable measures used companies additionally ebit considered conjunction net income loss income loss income taxes performance measures operating income operating cash flows reconciliation ebit net income loss periods ended december 31 following tables reflect segment results three years ended december 31 1 includes eliminations intercompany transactions intersegment revenues along intersegment operating expenses incurred normal course business operating segments recorded intersegment revenue elimination 24 million operation maintenance expense elimination 1 million “corporate other” column remove intersegment transactions 2 revenues external customers include gains 390 million related financial derivative contracts associated natural gas oil production intersegment revenues represent sales marketing segment responsible marketing production third parties 3 includes 110 million gain corporate related sale midstream assets newly formed joint venture 21 million noncash asset write pipelines based ferc order related sale compressor station gas processing plant 2009 4 includes gain approximately 80 million related sale interests certain mexican pipeline compression assets 5 total foreign assets approximately 04 billion relates property plant equipment approximately 01 billion relates investments advances unconsolidated affiliates 6 amounts net third party reimbursements capital expenditures returns capital sales investments advances 1 includes eliminations intercompany transactions intersegment revenues along intersegment operating expenses incurred normal course business operating segments recorded intersegment revenue elimination 10 million 2 revenues external customers include gains 687 million related financial derivative contracts associated natural gas oil production intersegment revenues represent sales marketing segment responsible marketing production third parties 3 total foreign assets approximately 04 billion relates property plant equipment approximately 03 billion relates investments advances unconsolidated affiliates 4 amounts net third party reimbursements capital expenditures returns capital sales investments advances 1 includes eliminations intercompany transactions intersegment revenues along intersegment operating expenses incurred normal course business operating segments recorded intersegment revenue elimination 19 million 2 revenues external customers include gains 196 million related financial derivative contracts associated natural gas oil production intersegment revenues represent sales marketing segment responsible marketing production third parties 3 total foreign assets approximately 03 billion relates property plant equipment approximately 05 billion relates investments advances unconsolidated affiliates 4 amounts net third party reimbursements capital expenditures returns capital sales investments advances 17 variable interest entities accounts receivable sales programs ruby consolidate investment ruby variable interest entity owns ruby pipeline project primary beneficiary july 2009 entered agreement gip whereby agreed invest 700 million acquire 50 percent equity interest ruby subject certain conditions part agreement gip contributed 145 million exchange convertible preferred equity interest ruby simultaneously exchanged convertible preferred equity interest cheyenne plains variable interest entity also consolidate primary beneficiary ii provided 405 million loan ruby project funding 2010 entered 15 billion third party project financing facility received blm rightofway grant received final approval ferc began construction ruby pipeline several groups filed appeals certain approvals actions blm us fish wildlife service related project currently unable predict action courts take response appeals subsequent filings may made one groups 2010 gip’s loan 405 million converted convertible preferred equity interest ruby gip provided additional 120 million contribution convertible preferred equity interest ruby borrowed approximately 11 billion 15 billion facility gip hold interest cheyenne plains certain conditions satisfied including placing ruby pipeline project service gip right convert preferred equity ruby common equity ruby time however preferred equity subject mandatory conversion ruby common equity upon satisfaction certain conditions including ruby entering certain additional firm transportation agreements conditions closing satisfied waived gip would 50 percent equity interest ruby ownership cheyenne plains would transferred back us however certain conditions satisfied including placing ruby pipeline project service november 2011 gip option convert cheyenne plains preferred interest common interest andor repaid cash remaining investments cheyenne plains ruby including 15 percent return investments cheyenne plains ruby obligation repay amounts secured equity interests ruby cheyenne plains 50 million common units epb additional information ruby project financing see note 11 also hold interests variable interest entities account investments unconsolidated affiliates entities significant operations accordingly material impact financial statements accounts receivable sales program 2009 several pipeline subsidiaries agreements sell senior interests certain accounts receivable shortterm assets generally settle within 60 days third party financial institution whollyowned special purpose entities retained subordinated interests receivables sale senior interests qualified sale accounting conducted accelerate cash receivables proceeds used increase liquidity lower overall cost capital years ended december 31 2009 2008 received 987 million 862 million cash related sale senior interests collected 869 million 977 million subordinated interests retained receivables recognized loss approximately 2 million 3 million transactions december 31 2009 third party financial institution held 90 million senior interests held 79 million subordinated interests subordinated interests reflected accounts receivable balance sheet january 2010 terminated accounts receivable sales programs paid 90 million acquire senior interests reflected cash flows related accounts receivable sold program changes retained subordinated interests cash paid terminate programs operating cash flows statement cash flows first quarter 2010 entered new accounts receivable sales programs continue sell accounts receivable third party financial institution qualify sale accounting updated accounting standards related financial asset transfers include additional pipeline subsidiary’s accounts receivable program programs several pipeline subsidiaries sell receivables entirety thirdparty financial institution whollyowned special purpose entities december 31 2010 thirdparty financial institution held 210 million accounts receivable sold program connection accounts receivable sales receive portion sales proceeds front receive additional amount upon collection underlying receivables refer deferred purchase price ability recover deferred purchase price based solely collection underlying receivables year ended december 31 2010 sold approximately 25 billion accounts receivable thirdparty financial institution received approximately 15 billion cash front deferred purchase price approximately 10 billion received approximately 967 million cash related deferred purchase price underlying receivables collected 2010 december 31 2010 collected approximately 89 million deferred purchase price related accounts receivable sales reflected accounts receivable balance sheet initially recorded amount approximates fair value level 2 measurement recognized loss approximately 2 million accounts receivable sales year ended december 31 2010 cash received front deferred purchase price relate sale ultimate collection underlying receivables subject significant risks given short term nature reflect cash flows new accounts receivable sales programs operating cash flows statement cash flows prior current accounts receivable sales programs serviced underlying receivables fee fair value servicing agreements well fees earned material financial statements periods ended december 31 2010 2009 2008 third party financial institution involved accounts receivable sales programs acquires interests various financial assets issues commercial paper fund acquisitions consolidate third party financial institution power control direct exert significant influence overall activities since receivables comprise significant portion operations 18 investments earnings transactions unconsolidated affiliates hold investments unconsolidated affiliates accounted using equity method accounting earnings unconsolidated affiliates reflected income statement include share net earnings directly attributable unconsolidated affiliates ii impairments gains losses divestitures adjustments recorded us december 31 2010 2009 investment balance exceeded net equity underlying net assets investments 98 million 269 million due primarily purchase price adjustments net impairment charges recorded us majority purchase price adjustments related investment four star amortize generally assess recoverability amount based development production underlying estimated proved natural gas oil reserves four star information related unconsolidated affiliates includes net investment earnings losses recorded investments ii summarized financial information proportionate share investments iii revenues charges unconsolidated affiliates net ownership interest investments earnings losses unconsolidated affiliates follows years ended december 31 december 31 2010 approximately 06 billion equity undistributed earnings 50 percent less owned entities accounted equity method included consolidated accumulated deficit received distributions dividends unconsolidated affiliates 64 million 90 million 182 million years ended december 31 2010 2009 2008 included amounts returns capital less 1 million 2010 2 million 2009 2008 2010 made capital contribution 100 million citrus one unconsolidated affiliates summarized financial information proportionate share operating results financial position unconsolidated affiliates transactions unconsolidated affiliates material 2010 2009 2008 investmentrelated matters currently outstanding disputes matters related investment two brazilian power plant facilities manausrio negro formerly owned us filed lawsuits collect amounts due us approximately 70 million brazilian reaisdenominated accounts receivable plant’s power purchaser also guaranteed purchaser’s parent eletrobras brazil’s stateowned utility power utility purchased power facilities parent asserted counterclaims would largely offset accounts receivable project companies previously owned manaus rio negro power plants also assessed approximately 78 million brazilian reaisdenominated icms taxes brazilian taxing authorities payments received companies plants’ power purchaser 1999 2001 agreement power purchaser must indemnify project companies icms taxes along related interest penalties therefore defending projects lawsuit order prevent collection efforts tax authorities matter security must provided potential tax liability court’s satisfaction tax authorities court rejected assets pledged power purchaser date 2010 tax courts blocked certain el paso’s bank accounts associated rio negro power plant order obtain security power purchaser appealed court’s decision power purchaser unable resolve tax matter ability collect amounts due us power purchaser could impacted potential taxes owed manaus rio negro project companies also guaranteed purchaser’s parent ultimate resolution matters discussed unknown time adverse developments related either ability collect amounts due us related disputes claims could require us record additional losses future supplemental selected quarterly financial information unaudited financial information quarter summarized items affecting comparability amounts reported respective quarters 2010 2009 december 31 2010 recorded 113 million loss debt extinguishment ii 110 million gain sale midstream assets joint venture iii 78 million losses related changes fair value exploration production financial derivatives september 30 2010 recorded 184 million gains related changes fair value exploration production financial derivatives ii 104 million loss debt extinguishment june 30 2010 recorded 80 million gain sale interests certain mexican pipeline compression assets ii 31 million gains related changes fair value exploration production financial derivatives march 31 2010 recorded 253 million gains related changes fair value exploration production financial derivatives december 31 2009 recorded 151 million gains related changes fair value exploration production financial derivatives ii 88 million tax benefit related liquidation foreign entities iii 22 million charge related restructuring costs iv 38 million international ceiling test charges september 30 2009 recorded 87 million gains related changes fair value exploration production financial derivatives june 30 2009 recorded 55 million gains related changes fair value exploration production financial derivatives ii 25 million marktomarket gain associated indemnification conjunction sale legacy ammonia facility iii 22 million loss sale porto velho notes receivables iv 21 million marktomarket gains power contracts march 31 2009 recorded total 21 billion domestic international ceiling test charges ii 394 million marktomarket gains related changes fair value exploration production financial derivatives iii 52 million gain related application accounting standard updates certain derivative liabilities supplemental natural gas oil operations unaudited exploration production segment engaged exploration acquisition development production natural gas oil ngl united states us brazil egypt capitalized costs capitalized costs relating natural gas oil producing activities related accumulated depreciation depletion amortization follows december 31 millions total costs incurred costs incurred natural gas oil producing activities whether capitalized expensed follows year ended december 31 millions pursuant full cost method accounting capitalize certain general administrative expenses directly related property acquisition exploration development activities interest costs incurred attributable unproved oil gas properties major development projects oil gas properties table includes capitalized internal general administrative costs incurred connection acquisition development exploration natural gas oil reserves 81 million 80 million 85 million years ended december 31 2010 2009 2008 also capitalized interest 9 million 7 million 29 million years ended december 31 2010 2009 2008 december 31 2010 reserve report amounts estimated spent 2011 2012 2013 develop consolidated worldwide proved undeveloped reserves 597 million 616 million 512 million unevaluated capitalized costs exclude capitalized costs natural gas oil properties amortization various stages evaluation part major development project expect costs included amortization calculation next three five years presented analysis capitalized costs natural gas oil properties year expenditures amortized december 31 2010 pending determination proved reserves millions unevaluated costs brazil include approximately 94 million related major development project pinauna field costs relate exploratory drilling 2007 led discovery hydrocarbons used fuel development pinauna project currently working obtain environmental permits develop project experienced delays obtaining permits due number factors including changes government additional regulatory inquiries resulting indirectly gulf mexico spill 2010 currently anticipate receive decision preliminary license request late 2011 allowing us proceed development activities additionally expect begin including unevaluated pinauna project costs amortizable base 2014 project evaluated however could experience additional delays development activities prior completion evaluation expect unevaluated pinauna project costs continue held outside amortizable base brazilian full cost pool unevaluated costs including related pinauna project assessed periodically impairment natural gas oil reserves net quantities proved developed undeveloped reserves natural gas ngl oil condensate changes reserves december 31 2010 presented tables based internal reserve report net proved reserves exclude royalties interests owned others reflect contractual arrangements royalty obligations effect time estimate 2009 consolidated proved reserves consistent estimates proved reserves filed federal agencies 2010 except differences less five percent resulting actual production acquisitions property sales necessary reserve revisions additions reflect actual experience ryder scott company lp ryder scott conducted audit estimates proved reserves prepared us december 31 2010 connection audit ryder scott reviewed 86 percent properties associated proved reserves natural gas equivalent basis representing 88 percent total discounted future net cash flows proved reserves ryder scott also conducted audit estimates prepared proved reserves four star december 31 2010 connection audit proved reserves ryder scott reviewed 86 percent properties associated four star’s total proved reserves natural gas equivalent basis representing 86 percent total discounted future net cash flows reviewed properties overall proved reserves estimates within 10 percent ryder scott’s estimates ryder scott’s report included exhibit annual report form 10k january 2010 financial accounting standards board updated accounting standards extractive activities oil gas align oil gas reserve estimation disclosures requirements sec’s final rule modernization oil gas reserve reporting effective december 31 2009 among things new standard revised definition proved reserves required us use 12month average price estimate proved reserves rather period end spot price required prior periods 12month average price calculated unweighted arithmetic average spot price first day month within 12month period prior end reporting period first day 12month average us price used estimate proved reserves december 31 2010 438 per mmbtu natural gas 7943 per barrel oil estimates proved reserves determined according rules prescribed sec existence time estimates made rules require standard “reasonable certainty” applied proved reserve estimates defined high degree confidence quantities recovered high degree confidence exists quantity much likely achieved technical economic data becomes available positive upward revision much likely negative downward revision estimates subject revision based upon number factors including many factors beyond control reservoir performance prices economic conditions government restrictions addition result drilling testing production subsequent date estimate may justify revision estimate reserve estimates often different quantities natural gas oil ultimately recovered estimating quantities proved natural gas oil reserves complex process involves significant interpretations assumptions cannot measured exact manner requires interpretations judgment available technical data including evaluation available geological geophysical engineering data accuracy reserve estimate highly dependent quality available data accuracy assumptions based upon economic factors natural gas oil prices production costs severance excise taxes capital expenditures workover remedial costs assumed effects governmental regulation addition due lack substantial production data greater uncertainties estimating proved undeveloped reserves proved developed nonproducing reserves proved developed reserves early production life result reserve estimates inherently imprecise meaningfulness reserve estimates highly dependent accuracy assumptions based general volume production natural gas oil properties declines reserves depleted except extent conduct successful exploration development activities acquire additional properties containing proved reserves proved reserves decline reserves produced subsequent december 31 2010 major discoveries events favorable otherwise may considered caused significant change estimated proved reserves results operations results operations natural gas oil producing activities fiscal year follows december 31 millions standardized measure discounted future net cash flows standardized measure discounted future net cash flows relating consolidated proved natural gas oil reserves december 31 follows millions calculations preceding table estimated future cash inflows estimated future production proved reserves december 31 2010 computed using first day 12month average us price 438 per mmbtu natural gas 7943 per barrel oil 12month average price calculated unweighted arithmetic average price first day month within 12month period prior end reporting period changes standardized measure discounted future net cash flows following principal sources change consolidated worldwide standardized measure discounted future net cash flows millions 1 disclosure reflects changes standardized measure calculation excluding effects hedging activities schedule ii el paso corporation valuation qualifying accounts years ended december 31 2010 2009 2008 millions 1 amounts net related insurance receivables 2 amounts reflect valuation allowances primarily associated brazil egypt net operating losses reversal valuation allowances federal state net operating losses state deferred tax assets 3 reflects rate refund settlement activity 4 amounts reflect valuation allowances associated brazil net operating losses ceiling test charges 5 amount reclassified postretirement liability 6 amounts reflect valuation allowances primarily associated brazil net operating losses ceiling test charges reversal valuation allowances state net operating losses deferred tax assets item 9item 8 financial statements supplementary data index items contained part ii item 8 financial statements supplementary data management’s annual report internal control financial reporting management responsible establishing maintaining adequate internal control financial reporting defined sec rules adopted securities exchange act 1934 amended internal control financial reporting designed provide reasonable assurance regarding reliability financial reporting preparation financial statements external purposes accordance generally accepted accounting principles consists policies procedures • pertain maintenance records reasonable detail accurately fairly reflect transactions dispositions assets • provide reasonable assurance transactions recorded necessary permit preparation financial statements accordance generally accepted accounting principles receipts expenditures made accordance authorizations management directors • provide reasonable assurance regarding prevention timely detection unauthorized acquisition use disposition assets could material effect financial statements supervision participation management including chief executive officer ceo chief financial officer cfo made assessment effectiveness internal control financial reporting december 31 2011 making assessment used criteria established internal control integrated framework issued committee sponsoring organizations treadway commission coso based evaluation concluded internal control financial reporting effective december 31 2011 effectiveness internal control financial reporting december 31 2011 audited ernst young llp independent registered public accounting firm stated report included herein report independent registered public accounting firm board directors stockholders el paso corporation audited accompanying consolidated balance sheets el paso corporation company december 31 2011 2010 related consolidated statements income comprehensive income equity cash flows three years period ended december 31 2011 audits also included financial statement schedule listed index item 15a financial statements schedule responsibility company’s management responsibility express opinion financial statements schedule based audits financial statements citrus corp subsidiaries corporation company 50 percent interest audited auditors whose report furnished us opinion consolidated financial statements insofar relates amounts included citrus corp subsidiaries based solely report auditors consolidated financial statements company’s investments unconsolidated affiliates includes approximately 959 million 866 million citrus corp subsidiaries december 31 2011 2010 respectively company’s earnings unconsolidated affiliates includes approximately 93 million 90 million 65 million years ended december 31 2011 2010 2009 respectively citrus corp subsidiaries conducted audits accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements audit also includes assessing accounting principles used significant estimates made management well evaluating overall financial statement presentation believe audits report auditors provide reasonable basis opinion based audits report auditors financial statements referred present fairly material respects consolidated financial position el paso corporation december 31 2011 2010 consolidated results operations cash flows three years period ended december 31 2011 conformity us generally accepted accounting principles also opinion related financial statement schedule considered relation basic financial statements taken whole presents fairly material respects information set forth therein discussed note 1 consolidated financial statements effective december 31 2009 company changed reserves estimates related disclosures result adopting new oil gas reserve estimation disclosure requirements also audited accordance standards public company accounting oversight board united states el paso corporation’s internal control financial reporting december 31 2011 based criteria established internal controlintegrated framework issued committee sponsoring organizations treadway commission report dated february 27 2012 expressed unqualified opinion thereon houston texas february 27 2012 report independent registered public accounting firm board directors stockholders el paso corporation audited el paso corporation’s internal control financial reporting december 31 2011 based criteria established internal control integrated framework issued committee sponsoring organizations treadway commission coso criteria el paso corporation’s management responsible maintaining effective internal control financial reporting assessment effectiveness internal control financial reporting included accompanying management’s annual report internal control financial reporting responsibility express opinion company’s internal control financial reporting based audit conducted audit accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether effective internal control financial reporting maintained material respects audit included obtaining understanding internal control financial reporting assessing risk material weakness exists testing evaluating design operating effectiveness internal control based assessed risk performing procedures considered necessary circumstances believe audit provides reasonable basis opinion company’s internal control financial reporting process designed provide reasonable assurance regarding reliability financial reporting preparation financial statements external purposes accordance generally accepted accounting principles company’s internal control financial reporting includes policies procedures 1 pertain maintenance records reasonable detail accurately fairly reflect transactions dispositions assets company 2 provide reasonable assurance transactions recorded necessary permit preparation financial statements accordance generally accepted accounting principles receipts expenditures company made accordance authorizations management directors company 3 provide reasonable assurance regarding prevention timely detection unauthorized acquisition use disposition company’s assets could material effect financial statements inherent limitations internal control financial reporting may prevent detect misstatements also projections evaluation effectiveness future periods subject risk controls may become inadequate changes conditions degree compliance policies procedures may deteriorate opinion el paso corporation maintained material respects effective internal control financial reporting december 31 2011 based coso criteria also audited accordance standards public company accounting oversight board united states 2011 consolidated financial statements el paso corporation report dated february 27 2012 expressed unqualified opinion thereon ernst young llp houston texas february 27 2012 el paso corporation consolidated statements income millions except per common share amounts see accompanying notes el paso corporation consolidated statements comprehensive income millions see accompanying notes el paso corporation consolidated balance sheets millions except share per share amounts see accompanying notes el paso corporation consolidated balance sheets millions except share per share amounts see accompanying notes el paso corporation consolidated statements cash flows millions see accompanying notes el paso corporation consolidated statements equity millions except per share amounts see accompanying notes el paso corporation notes consolidated financial statements 1 basis presentation significant accounting policies basis presentation consolidated financial statements prepared accordance united states us generally accepted accounting principles gaap include accounts consolidated subsidiaries elimination significant intercompany accounts transactions financial statements prior periods include reclassifications made conform current year presentation none impacted reported net income loss stockholders’ equity proposed merger kinder morgan inc october 16 2011 announced definitive merger agreement kinder morgan inc kmi whereby kmi acquire el paso corporation el paso transaction valued el paso approximately 38 billion based kmi stock price date including assumption debt merger agreement approved kmi’s board directors completion merger subject satisfaction waiver certain closing conditions including among others customary regulatory approvals approval stockholders approval issuance kmi stock warrants kmi’s stockholders voting agreement executed certain stockholders kmi holding approximately 75 percent voting power kmi stockholders agreed vote favor merger issuance kmi stock warrants completion merger constitute change control el paso may trigger provisions certain agreements including related debt financing agreements ii severance agreements iii incentive compensation plan agreements result immediate acceleration unvested stock based compensation awards upon closing merger debt financing agreements containing covenants related change control events terminated pursuant merger either amended agreements obtained waivers covenants however downgrade credit ratings upon completion merger kmi could trigger certain change control provisions certain agreements party upon merger el paso shareholders receive combination class p shares common stock kmi common stock purchase warrants kmi cash share el paso common stock excluding shares held kmi subsidiaries el paso dissenting shares accordance delaware law effective time merger converted right receive election holder subject proration respect stock cash portion approximately 57 percent aggregate merger consideration excluding warrants paid cash approximately 43 percent excluding warrants paid class p common stock kmi par value 001 per share “kmi class p common stock” 09635 share kmi class p common stock 0640 common stock purchase warrant kmi “kmi warrant” ii 2591 cash without interest 0640 kmi warrant iii 04187 share kmi class p common stock 1465 cash without interest 0640 kmi warrant kmi warrant entitle holder purchase one share kmi class p common stock exercise price 4000 per share subject certain adjustments time fiveyear period following closing merger agreement includes customary representations warranties covenants specific agreements relating conduct el paso’s kmi’s respective businesses date signing merger agreement closing merger transactions ii efforts parties cause merger transactions completed addition certain covenants agreed encourage solicit initiate facilitate takeover proposal third party enter agreement arrangement understanding requiring us abandon terminate fail consummate merger related transactions merger agreement contains certain termination rights el paso kmi provides upon termination merger agreement certain circumstances el paso may required pay kmi termination fee equal 650 million certain circumstances el paso may required reimburse kmi expenses 20 million certain financing related expenses terms merger agreement agreed conduct business ordinary course material respects substantially manner conducted prior date merger agreement subject certain conditions restrictions thresholds including limited ability commit capital expenditures current capital budgets ii acquire invest dispose material properties assets equity interests defined merger agreement iii incur new debt refinance guarantee debt borrowed money iv enter terminate amend certain material contracts v issue grant sell redeem new el paso capital stock stockbased compensation awards andor pay dividends excess 001share among limitations conjunction merger kmi announced intend sell exploration production assets february 24 2012 entered purchase sale agreement sell exploration production assets affiliate apollo global management llc “apollo” certain parties 715 billion subject certain adjustments items contributions distributions incurrence debt title defects sale contemplated merger agreement kmi closing sale conditioned upon closing transactions contemplated merger agreement kmi transactions expected completed second quarter 2012 purchase sale agreement contains customary representations warranties relating exploration production assets operations additionally el paso entered performance guarantee favor apollo guarantee performance seller subsidiaries’ obligations purchase sale agreement pursuant merger agreement kmi required indemnify us cost incurred us arising relating sale exploration production assets upon completion sale exploration production business reflected discontinued operation financial statements use estimates preparation financial statements requires use estimates assumptions affect amounts report assets liabilities revenues expenses disclosures financial statements actual results often differ estimates principles consolidation consolidate entities ability control direct operating financial decisions entity significant interest entity gives us ability direct activities significant entity determination ability control direct exert significant influence entity involves use judgment apply equity method accounting exert significant influence control direct policies decisions activities entity use cost method accounting unable exert significant influence entity regulated operations interstate natural gas pipelines storage operations subject jurisdiction federal energy regulatory commission ferc follow financial accounting standards board’s accounting standards regulated operations standards record regulatory assets liabilities would recorded nonregulated entities regulatory assets liabilities represent probable future revenues expenses associated certain charges credits expected recovered refunded customers rate making process items may record regulatory asset liability include certain postretirement employee benefit plan costs taxes related equity return component regulated capital projects certain costs related gas used operations costs included expected included future rates details regulatory assets liabilities see note 8 cash equivalents consider shortterm investments original maturity less three months cash equivalents maintain cash deposit banks insurance companies pledged particular use restricted support potential liability classify balances restricted cash current noncurrent assets balance sheet based expect restrictions cash removed allowance doubtful accounts establish provisions losses accounts notes receivable natural gas imbalances due shippers operators determine collect part outstanding balance regularly review collectability establish adjust allowance necessary using specific identification method property plant equipment pipelines excluding oil natural gas properties property plant equipment recorded original cost construction upon acquisition fair value assets acquired assets construct capitalize direct costs labor materials indirect costs overhead interest equity return component regulated businesses capitalize major units property replacements improvements expense minor items description methods use depreciate regulated property plant equipment see note 10 included pipeline property balances additional acquisition costs represent excess purchase costs associated purchase business combinations allocated regulated interstate systems’ property plant equipment costs amortized straightline basis recoverable rates current ferc policies retire property plant equipment regulated operations charge accumulated depreciation amortization original cost assets addition cost remove sell dispose assets less salvage value recognize gain loss unless sell entire operating unit determined ferc include gains losses dispositions operating units operations maintenance expense income statements oil natural gas properties use full cost method account oil natural gas properties full cost method substantially costs incurred connection acquisition development exploration oil natural gas reserves capitalized countrybycountry basis capitalized amounts include costs unproved properties internal costs directly related acquisition development exploration activities asset retirement costs capitalized interest full cost method dry hole costs geological geophysical costs capitalized full cost pool subject amortization periodically assessed impairment ceiling test calculation discussed capitalized costs associated proved reserves amortized life reserves using unit production method conversely capitalized costs associated unproved properties excluded amortizable base properties evaluated determined costs impaired quarterly basis transfer unproved property costs amortizable base properties determined proved reserves costs determined impaired amount impairment transferred full cost pool oil natural gas reserve base exists expensed reserve base yet created amortizable base includes future development costs dismantlement restoration abandonment costs net estimated salvage values geological geophysical costs incurred cannot associated specific unevaluated properties prospects direct interest capitalized costs country net related deferred income taxes limited ceiling based present value future net revenues proved reserves less estimated future capital expenditures discounted 10 percent plus cost unproved oil natural gas properties amortized less related income tax effects perform ceiling test calculation quarter prior december 31 2009 utilized end period spot prices determine future net revenues result adoption securities exchange commission sec’s final rule modernization oil gas reporting effective december 31 2009 utilize 12month average price calculated unweighted arithmetic average price first day month within 12month period prior end reporting period performing ceiling test also required hold prices constant life reserves even though actual prices oil natural gas volatile change period total capitalized costs exceed ceiling required writedown capitalized costs ceiling required writedown included ceiling test charge income statement increase accumulated depreciation depletion amortization balance sheet present value future net revenues used ceiling test calculations excludes impact derivatives estimated future cash outflows associated asset retirement liabilities related proved developed reserves sell convey interests oil natural gas properties reduce oil natural gas reserves amount attributable sold conveyed interest recognize gain loss sales oil natural gas properties unless sales would significantly alter relationship capitalized costs proved reserves treat sales proceeds nonsignificant sales adjustment cost properties asset investment divestituresimpairments evaluate assets investments impairment events circumstances indicate carrying values may recovered events include market declines believed temporary changes manner intend use longlived asset decisions sell asset investment adverse changes legal business environment adverse actions regulators event occurs evaluate recoverability carrying value based either longlived asset’s ability generate future cash flows undiscounted basis ii fair value investment unconsolidated affiliate impairment indicated decide sell longlived asset group assets adjust carrying values asset downward necessary estimated fair value fair value estimates generally based assumptions market participants would use including market data obtained sales process analysis expected discounted cash flows pension postretirement benefits maintain several pension postretirement benefit plans make contributions plans required fund benefits paid participants retirees contributions invested benefits paid plan participants net benefit cost plans recorded income statement function many factors including benefits earned year plan participants function factors employee’s salary level benefits provided plan actuarial assumptions passage time expected returns plan assets amortization certain deferred gains losses discussion policies respect pension postretirement benefit plans see note 13 accounting pension postretirement benefit plans record asset liability based funded status plan deferred amounts related unrecognized gains losses changes actuarial assumptions recorded either regulatory asset liability certain regulated operations accumulated comprehensive income loss component stockholders’ equity operations gains losses recognized income statement revenue recognition business segments provide number services sell variety products record revenues products services include estimates amounts earned unbilled estimate unbilled revenues based contractual data regulatory information commodity prices preliminary throughput allocation measurements among items revenue recognition policies significant operating segments follows pipelines revenues pipelines segment derives revenues primarily transportation storage services lng terminal operations revenues services generally based thermal quantity gas delivered subscribed price specified contract transportation storage services recognize reservation revenues firm contracted capacity ratably contract period interruptible volumetric based services record revenues physical deliveries natural gas made agreed upon delivery point gas injected withdrawn storage facility contracts stepup stepdown rate provisions related changes levels service recognize reservation revenues ratably contract life revenues gas used operations based volumes allowed retain relative amounts gas use operating purposes prior implementation fuel volume tracker tennessee gas pipeline tgp system recognized revenue gas used operations shippers ferc allowed us retain volumes market prices required tariffs subject ferc regulations result revenues collect rate proceedings may subject refund establish reserves potential refunds exploration production revenues exploration production segment derives revenues primarily physical sale oil natural gas condensate natural gas liquids revenues sales products recorded upon delivery passage title using sales method net royalty interests profit interests produced product actual sales volumes exceed entitled share sales volumes overproduced imbalance occurs extent overproduced imbalance exceeds share remaining estimated proved reserves given property record liability costs associated transportation delivery production included cost products services marketing revenues marketing segment derives revenues physical natural gas power transactions management derivative contracts derivative transactions recorded fair value changes fair value reflected net operating revenues discussion income recognition policies derivatives see price risk management activities impact nonderivative transactions including transportation contracts recognized net operating revenues based contractual market price related volumes time commodity delivered contracts terminated environmental costs contingencies environmental costs record liabilities undiscounted amounts balance sheet current longterm liabilities environmental assessments indicate remediation efforts probable costs reasonably estimated estimates liabilities based currently available facts existing technology presently enacted laws regulations taking consideration likely effects societal economic factors include estimates associated legal costs amounts also consider prior experience remediating contaminated sites companies’ cleanup experience data released environmental protection agency epa organizations estimates subject revision future periods based actual costs new circumstances capitalize costs benefit future periods recognize current period charge operation maintenance expense cleanup efforts benefit future periods evaluate amounts paid directly reimbursed government sponsored programs potential recoveries reimbursements remediation costs third parties including insurance coverage separately liability recovery evaluated based creditworthiness solvency third party among factors recovery assured record report asset separately associated liability balance sheet contingencies recognize liabilities contingencies exposure indicates probable liability incurred amount loss reasonably estimated likely outcome contingency reasonably estimated accrue liability amount likely outcome cannot estimated range potential losses established one amount range likely low end range accrued price risk management activities price risk management activities relate primarily derivatives entered hedge otherwise reduce commodity exposure oil natural gas production interest rate exposure longterm debt also hold derivatives intended hedge exposures derivatives reflected balance sheet fair value assets liabilities price risk management activities cash collateral associated derivatives significant financial statements classify derivatives either current noncurrent assets liabilities based anticipated settlement date net derivative assets liabilities counterparties legal right offset enter derivative contracts related price risk management activities may designate derivative either cash flow hedge fair value hedge cash flow hedges designed hedge forecasted sales transactions limit variability cash flows received paid related recognized asset liability changes fair value hedges deferred accumulated comprehensive income loss extent effective recognized revenues expenses hedged transactions occur ineffectiveness related cash flow hedges recognized earnings occurs fair value hedges entered protect fair value recognized asset liability firm commitment changes fair value hedges recognized earnings offsets changes fair value related hedged assets liabilities firm commitments derivatives designated accounting hedges markedtomarket period changes fair value well realized amounts generally reflected operating revenues exploration production segment marketing segment cash flow statement cash inflows outflows associated settlement derivative instruments recognized operating cash flows balance sheet receivables payables resulting settlement derivative instruments reported trade receivables payables see note 7 discussion price risk management activities income taxes record current income taxes based current taxable income provide deferred income taxes reflect estimated future tax payments receipts deferred taxes represent tax impacts differences financial statement tax bases assets liabilities carryovers year end account tax credits flowthrough method reduces provision income taxes year tax credits first become available reduce deferred tax assets valuation allowance based estimates likely portion assets realized future period estimates utilized recognition deferred tax assets subject revision either future periods based new facts circumstances accounting asset retirement obligations record liability legal obligations associated replacement removal retirement longlived assets period obligation incurred estimable asset retirement liabilities initially recorded estimated fair value corresponding increase property plant equipment increase property plant equipment depreciated useful life asset liability relates ongoing expense recognized changes value liability result passage time record depreciation depletion amortization expense income statement regulated pipelines ability recover certain costs customers recorded asset rather expense associated accretion liabilities described accounting stockbased compensation measure employee stockbased compensation awards fair value date awards granted employees recognize compensation cost financial statements requisite service period additional information stockbased compensation awards see note 15 2 acquisitions divestitures acquisitions 2011 2010 2009 acquired following assets divestitures 2011 2010 2009 sold number assets investments receiving proceeds follows 2011 sold noncore oil natural gas properties located central western southern divisions several transactions gain loss recorded sales also 2011 completed sale remaining interest telecommunications equity investment recorded 16 million gain earnings unconsolidated affiliates year ended 2010 completed sale certain mexican pipeline compression assets approximately 300 million recorded pretax gain approximately 80 million earnings unconsolidated affiliates ii sold 50 percent interest altamont gathering processing assets part midstream joint venture 125 million cash included recording pretax gain longlived assets approximately 110 million iii sold noncore natural gas producing properties located southern division approximately 22 million without recording gain loss 2009 also sold oil natural gas properties pipeline assets related facilities legacy international power investments assets february 2012 executed agreement midstream joint venture transfer wholly owned investment eagle ford gathering systems joint venture approximately 85 million cash 3 ceiling test charges required conduct quarterly impairment tests capitalized costs full cost pools years ended december 31 2011 2010 2009 recorded following ceiling test charges 2011 charge driven part release certain unevaluated costs brazilian full cost pool primarily result denial necessary environmental permit completion evaluation two exploratory wells drilled 2009 2010 without additions proved reserves see note 10 discussion may incur additional ceiling test charges brazil future depending value proved reserves subject change result factors prices costs well performance future may incur ceiling test charges egypt depending results activities political unrest country continue evaluate commerciality areas current natural gas prices significantly 12month average price used determine domestic proved reserves december 31 2011 sustained period low domestic natural gas prices time result downward revision proved reserves corresponding reduction discounted future net cash flows proved reserves could result ceiling test charges domestic full cost pool 4 income expenses following components income expenses three years ended december 31 5 income taxes pretax income loss income tax benefit expense tables show pretax income loss components income tax benefit expense three years ended december 31 effective tax rate reconciliation income taxes included net income differs amount computed applying statutory federal income tax rate 35 percent following reasons three years ended december 31 negative effective tax rate year ended december 31 2011 reflects impact low level pretax income ii deferred state tax benefit valuation allowance recorded upon conversion subsidiary limited liability company reduced state effective tax rates iii favorable resolution certain tax matters partially offsetting items 53 million tax impact brazilian ceiling test charge without corresponding us brazilian tax benefit deferred brazilian tax benefits offset equal valuation allowance 2009 effective tax rate higher statutory rate primarily due recording 88 million income tax benefit relating us tax loss liquidation certain foreign entities following 2009 sale remaining significant international power projects entities liquidating value entities tax basis liquidation resulted tax loss believe certain unconsolidated affiliates’ undistributed earnings ultimately distributed us dividends would eligible dividends received deduction joint venture partners intent ability recover cumulative undistributed earnings time dividends structured sale would result additional deferred tax liabilities december 31 2011 undistributed earnings unconsolidated affiliates expect receive dividends received deduction approximately 543 million deferred tax assets liabilities following components net deferred tax liability december 31 deferred tax assets net operating loss carryovers well deferred tax liabilities property plant equipment investments affiliates increased 2010 2011 primarily result accelerated tax depreciation 2011 capital expenditures cumulative undistributed earnings substantially foreign subsidiaries foreign corporate joint ventures intended indefinitely reinvested foreign operations therefore provision made us taxes foreign withholding taxes may applicable upon actual deemed repatriation estimate taxes earnings repatriated practicable december 31 2011 portion cumulative undistributed earnings investments recorded us income taxes approximately 89 million unrecognized tax benefits subject taxation us various states foreign jurisdictions exceptions longer subject state local foreign income tax examinations tax authorities years prior 2001 us income tax examinations years prior 2007 years returns still subject review unrecognized tax benefits could increase decrease income tax expense effective income tax rates matters finalized currently unable estimate range potential impacts resolution contested matters could financial statements following table shows change unrecognized tax benefits december 31 2011 2010 approximately 260 million 275 million net federal tax benefits unrecognized tax benefits associated interest penalties would affect income tax expense effective income tax rate recognized future periods believe reasonably possible total amount unrecognized tax benefits including interest penalty decrease much 80 million next 12 months result anticipated favorable resolution certain tax matters classify interest penalties related unrecognized tax benefits income taxes financial statements 2011 2010 2009 recognized consolidated statements income 15 million 1 million 3 million associated interest penalties related unrecognized tax benefits december 31 2011 2010 36 million 51 million accrued interest penalties consolidated balance sheets tax credit net operating loss carryovers december 31 2011 us federal alternative minimum tax credits 290 million carryover indefinitely table presents details federal state net operating loss carryover periods december 31 2011 increased substantially 2010 related depreciation elections taken capital expenditures also 510 million foreign net operating loss carryovers 89 million foreign capital loss carryovers majority carryover indefinitely usage us federal carryovers subject limitations provided sections 382 383 internal revenue code well separate return limitation year rules irs regulations valuation allowances deferred tax assets recorded net operating losses temporary differences book tax bases assets liabilities expected produce tax deductions future periods realization assets depends recognition sufficient future taxable income specific tax jurisdictions periods temporary differences net operating losses deductible assessing need valuation allowance deferred tax assets consider whether likely portion realized part assessment consider future reversals existing taxable temporary differences primarily related depreciation december 31 2011 valuation allowance primarily relates deferred tax assets recorded state foreign net operating losses temporary differences valuation allowance related brazilian egyptian net operating losses initially established primarily result changes worldwide economic conditions created uncertainty outlook future taxable income jurisdictions given nature current international operations cannot reasonably forecast future taxable income thus continue maintain full valuation allowance 2011 increased valuation allowance 18 million deferred tax assets associated brazil egypt net operating losses temporary differences 3 million deferred tax assets associated federal state net operating losses believe likely realize benefit deferred tax assets net existing valuation allowances 6 earnings per share basic diluted earnings loss per common share follows three years ended december 31 exclude potentially dilutive securities determination diluted earnings per share well related income statement impacts impact net income attributable el paso corporation per common share antidilutive potentially dilutive securities consist stock based awards employee stock options restricted stock performance shares convertible preferred stock trust preferred securities march 2011 converted preferred stock common stock described note 14 years ended december 31 2011 2010 trust preferred securities certain employee stock options antidilutive year ended december 31 2009 incurred losses attributable el paso corporation accordingly excluded potentially dilutive securities determination diluted earnings per share discussion capital stock activity stockbased compensation arrangements instruments noted see notes 14 15 7 financial instruments following table reflects carrying value fair value financial instruments december 31 2011 2010 carrying amounts cash equivalents accounts receivable accounts payable shortterm financing obligations represent fair value shortterm nature instruments carrying amounts restricted cash noncurrent receivables approximate fair value based nature interest rates assessment ability recover amounts estimated fair value longterm financing obligations primarily based quoted market prices similar issuances including consideration credit risk related instruments derivative financial instruments described • productionrelated commodity based derivatives december 31 2011 2010 productionrelated derivatives oil natural gas swaps basis swaps option contracts mitigate portion commodity price risk stabilize cash flows associated forecasted sales oil natural gas production 14530 mbbl 12240 mbbl oil 105 tbtu 283 tbtu natural gas none contracts designated accounting hedges • commoditybased derivatives december 31 2011 2010 marketing segment forwards swaps option contracts related longterm natural gas power contracts longest extends 2019 include obligations sell natural gas power plants ranging 12550 mmbtud 95000 mmbtud ii obligation swap locational differences power prices three power plants pennsylvanianew jerseymaryland pjm eastern region pjm west hub approximately 1700 gwh 3700 gwh provide annually approximately 1700 gwh power approximately 71 gw installed capacity pjm power pool entered offsetting positions eliminate price risks associated pjm power contracts substantially offset fixed price exposure related natural gas supply contracts none derivatives designated accounting hedges • interest rate derivatives longterm debt variable interest rates exposes us changes marketbased interest rates december 31 2011 2010 interest rate swaps designated cash flow hedges effectively convert interest rate approximately 01 billion 13 billion debt floating libor interest rate fixed interest rate majority balance december 31 2010 related interest rate swaps 11 billion debt related construction ruby pipeline hedges began accruing interest june 30 2011 termination dates ranging june 2013 june 2017 correspond estimated principal outstanding debt term swaps connection deconsolidation ruby pipeline holding company llc ruby interest rate swaps related accumulated comprehensive loss longer reflected balance sheet discussion ruby see note 18 also longterm debt fixed interest rates exposes us paying higher market rates interest rates decline use interest rate swaps designated fair value hedges protect value certain debt instruments converting fixed amounts interest due debt agreements variable interest payments record changes fair value derivatives interest expense offset changes fair value related hedged items december 31 2011 2010 interest rate swaps converted interest rate approximately 162 million 184 million debt fixed rate variable rate libor plus 418 percent fair value measurements use various methods determine fair values financial instruments fair value financial instrument depends number factors including availability observable market data contractual term underlying instrument data available similar instruments similar markets assumptions market participant would use related estimates future settlements instrument separate fair values financial instruments three levels 1 2 3 based assessment availability observable market data significance nonobservable data used determine fair value assessment classification instrument within level change time based maturity liquidity instrument would reflected end period change occurs levels corresponding instruments classified level described • level 1 instruments’ fair values based quoted prices instruments actively traded markets included level marketable securities nonqualified compensation plans • level 2 instruments’ fair values primarily based pricing data representative quoted prices similar assets liabilities active markets identical assets liabilities less active markets included level interest rate swaps productionrelated oil natural gas derivatives certain natural gas derivatives natural gas supply arrangements whose fair values based commodity pricing data obtained third party pricing sources fair values also consider creditworthiness counterparties adjusted collateral related asset positions • level 3 instruments’ fair values partially calculated using pricing data similar level 2 also reflect adjustments less liquid markets longer contractual terms primarily included level powerrelated derivatives certain remaining natural gas derivatives determine fair value instruments obtain pricing data third party pricing sources develop estimate forward prices believe market participants would use based liquidity underlying forward markets contractual terms curves used estimate value settlements future periods based contractual settlement quantities dates valuation instruments considers specific contractual terms statistical simulation analysis present value concepts internal assumptions related contract maturities extend beyond periods quoted market prices available ii uniqueness contract terms iii limited availability forward pricing information markets lack viable participants pjm forward power market forward market ammonia iv creditworthiness counterparties adjusted collateral related asset positions financial statement presentation marketable securities nonqualified compensation plans included table reflected fair value balance sheets longterm assets current liabilities net derivative assets liabilities counterparties legal right offset classify derivatives either current noncurrent assets liabilities based anticipated settlement date december 31 2011 2010 cash collateral held material following table presents fair value financial instruments december 31 2011 2010 millions following table presents changes financial assets liabilities included level 3 years ended december 31 2011 2010 1 includes approximately 7 million 41 million net losses realized settlements year ended december 31 2011 2010 2 includes approximately 4 million 2 million net losses realized settlements year ended december 31 2011 2010 3 2011 reclassified certain natural gas derivatives level 3 level 2 maturities contracts longer extended beyond periods quoted market prices available impacts commoditybased interest rate derivatives statements income statements comprehensive income years ended december 31 2011 2010 1 ineffectiveness recognized interest rate hedges years ended december 31 2011 2010 2009 2 includes 125 million related recognition accumulated comprehensive loss associated interest rate swaps ruby’s debt conjunction deconsolidation see note 18 included loss deconsolidation subsidiary consolidated statements income credit risk subject risk loss financial instruments would incur result nonperformance counterparties failure post required collateral pursuant terms contractual obligations exposures offset legally enforceable right setoff maintain credit policies regard counterparties minimize overall credit risk policies require evaluation potential counterparties’ financial condition including credit rating ii obtaining collateral certain circumstances including cash advance letters credit guarantees iii use margining provisions standard contracts iv use master netting agreements allow netting positive negative exposures various contracts associated single counterparty one counterparties fails perform may recognize immediate loss earnings well additional financial impacts future delivery periods extent replacement contract prices andor quantities cannot established use daily margining provisions financial contracts physical power agreements master netting agreements require counterparty post cash letters credit fair value contract exceeds daily contractual threshold amount typically tied published credit rating counterparty margining collateral provisions may terminate contract liquidate positions counterparty unable provide required collateral required return collateral amount posted collateral exceeds amount collateral required collateral received returned vary significantly day based changes market values counterparty’s credit ratings furthermore amount collateral hold may less fair value derivative contracts counterparty given period following table presents summary exposure derivative contracts net collateral liabilities right offset exists presented type derivative counterparty net asset exposure december 31 2011 2010 1 “investment grade” “below investment grade” determined using publicly available credit ratings “investment grade” includes counterparties minimum standard poor’s rating bbb moody’s investor service rating baa3 “below investment grade” includes counterparties public credit rating meet criteria “investment grade” “not rated” includes counterparties rated public rating service 2 consists primarily noncash collateral letters credit december 31 2011 approximately 34 counterparties derivative contracts based assessment counterparty risk light collateral counterparties posted us primarily form letters credit determined exposure primarily related productionrelated derivatives limited eight financial institutions current standard poor’s credit rating better additionally december 31 2011 three counterparties credit suisse energy llc societe general bank nova scotia comprise 22 percent 18 percent 15 percent respectively net financial instrument exposure december 31 2010 three counterparties morgan stanley capital group citibank j aron comprised 27 percent 21 percent 10 percent respectively net financial instrument asset exposure concentration counterparties may impact overall exposure credit risk either positively negatively counterparties may similarly affected changes economic regulatory conditions part assessment fair value financial liabilities also assess credit risk considering collateral posted related positions january 1 2009 adopted accounting standards regarding companies consider credit determining fair value liabilities thirdparty credit enhancements related recorded 34 million gain net 18 million taxes 005 per share result adopting new accounting standard update 8 regulatory assets liabilities regulatory assets liabilities relate interstate pipeline operations included current noncurrent assets liabilities balance sheets see note 9 balances recoverable reimbursable various periods details regulatory assets liabilities december 31 significant regulatory assets liabilities include difference gas retained gas consumed operations amounts reflect value volumetric difference gas retained consumed operations amounts included rate base given tariffs expected recovered customers returned customers subsequent fuel filing periods taxes capitalized funds used construction represents regulatory asset balance established offset deferred tax equity component allowance funds used construction afudc longlived assets taxes capitalized funds used construction offsetting deferred income taxes included rate base recovered depreciable lives long lived asset relate result deconsolidation investment ruby september 2011 longer include amounts related ruby pipeline balance sheet december 31 2011 discussion deconsolidation ruby see note 18 postretirement benefits represents unrecognized gains losses changes actuarial assumptions related postretirement benefit plans differences postretirement benefit related amounts expensed amounts recovered rates postretirement benefit amounts included rate base computations certain pipelines recoverable periods benefits funded 2011 part rate case settlements certain pipelines required reduce portion balances reclassified 19 million net taxes 6 million accumulated comprehensive income recorded increase approximately 29 million operating revenues unamortized net loss reacquired debt amount represents deferred unamortized portion losses reacquired debt recovered original life debt issuance cost service unamortized loss assets held sale september 2011 entered agreement sell certain southern natural gas sng offshore onshore assets located gulf mexico louisiana recorded deferred unamortized portion losses assets held sale noncurrent regulatory assets recovery amount expected occur fixed monthly rate sng’s next rate case expected effective september 2013 final recovery period dependent upon outcome rate case environmental liability includes amounts collected substantially excess certain polychlorinated biphenyl pcb environmental remediation costs date surcharge tgp’s customers settlement approved ferc november 1995 environmental liability deducted rate base tgp allowed earn return discussion matter see note 12 property plant depreciation amounts represent deferral customerfunded amounts costs future asset retirements 9 assets liabilities detail current noncurrent assets liabilities balance sheets december 31 10 property plant equipment depreciable lives table presents depreciation methods depreciable lives property plant equipment 1 composite group method assets similar useful lives characteristics grouped depreciated one asset apply depreciation rate approved rate settlements total cost group net book value equals salvage value reevaluate depreciation rates time file ferc increase decrease rates 2 capitalized costs associated proved reserves amortized life reserves capitalized costs associated unproved properties excluded amortizable base properties evaluated determined costs impaired excess purchase costs december 31 2011 2010 tgp el paso natural gas pipeline epng excess purchase costs associated historical acquisition total excess costs pipelines approximately 25 billion accumulated depreciation approximately 06 billion 05 billion december 31 2011 2010 excess purchase costs depreciated estimated weighted average remaining life 47 years related depreciation expense year ended december 31 2011 2010 2009 approximately 42 million capitalized costs construction capitalize pretax carrying cost funds related construction longlived assets reflect amount increase cost asset balance sheet also capitalize amounts consist interest cost debt could attributed assets constructed ii regulated pipelines return equity could attributed assets constructed equity portion calculated using recent ferc approved equity rate return interest costs capitalized included reduction interest expense income statements 63 million 60 million 48 million years ended december 31 2011 2010 2009 equity amounts capitalized exclusive taxes ferc regulated business included nonoperating income statement 124 million 156 million 61 million years ended december 31 2011 2010 2009 amounts recovered depreciable lives longlived assets relate noncash investing activities construction workinprogress december 31 2011 2010 approximately 13 billion 48 billion construction workinprogress included property plant equipment unevaluated capitalized costs unevaluated capitalized costs oil natural gas properties follows 2011 released approximately 86 million unevaluated capitalized costs brazilian full cost pool upon completing evaluation certain exploratory wells drilled 2009 2010 also released approximately 94 million related brazilian development project denied necessary environmental permit actions contributed ceiling test charge recorded brazilian full cost pool 2011 see note 3 discussion december 31 2011 total oil natural gas capitalized costs approximately 74 million 205 million egypt brazil 74 million 8 million unevaluated capitalized costs asset retirement obligations legal obligations associated retirement oil natural gas wells related infrastructure natural gas pipelines transmission facilities storage wells exploration production operations obligations plug wells abandoned production exhausted longer plan use wells pipeline operations legal obligations primarily involve purging sealing pipelines abandoned also obligations remove hazardous materials associated natural gas transmission facilities ever demolished replaced continue evaluate asset retirement obligations future developments could impact amounts record reasonably estimate asset retirement obligation accrue liability based estimate timing amount settlement estimating asset retirement obligations utilize several assumptions including projected inflation rate 25 percent creditadjusted discount rates currently range 5 12 percent based liabilities recorded record changes estimates based changes expected amount timing payments settle obligations typically changes result obtaining new information timing obligations plug abandon oil natural gas wells costs certain events accelerate timing asset retirements eg impact hurricanes pipelines operations intend operating maintaining natural gas pipeline storage systems long supply demand natural gas exists expect foreseeable future therefore believe cannot reasonably estimate asset retirement obligation substantial majority natural gas pipeline storage system assets indeterminate lives net asset retirement obligation december 31 reported balance sheet current noncurrent liabilities changes net liability years ended december 31 follows 1 amount 2010 reflects updated information received hurricane related asset retirement obligations 11 debt financing obligations credit facilities following provides additional detail financing obligations changes financing obligations 2011 following changes longterm financing obligations millions 1 september 2011 ruby debt obligations became nonrecourse us deconsolidated ruby result longer reflect debt obligations related interest rate swaps balance sheet see note 18 loss debt extinguishment 2011 repurchased approximately 10 billion senior unsecured notes conjunction transactions recorded total losses debt extinguishment 169 million 2010 repurchased approximately 709 million senior notes exchanged approximately 349 million 1200 senior notes due 2013 cash 650 senior notes due 2020 conjunction transactions paid 168 million cash premiums recorded losses debt extinguishment 217 million debt maturities aggregate maturities principal amounts longterm financing obligations december 31 2011 next 5 years total thereafter follows millions credit facilitiesletters credit various credit facilities place allow us borrow funds issue letters credit lcs enter letters credit issue surety bonds ordinary course operating activities well periodically conjunction sales assets businesses december 31 2011 aggregate amount borrowings outstanding credit facilities 15 billion addition 06 billion letters credit surety bonds outstanding december 31 2011 including approximately 03 billion related price risk management activities listed description credit facilities including remaining capacity facilities december 31 2011 1 based december 31 2011 credit rating applicable margin used calculate interest borrowings letters credit commitment fees determined variable pricing grid tied credit ratings senior secured debt 2 multiissuer facility primarily used letters credit however facility allows cash draws 150 million one parties facility december 31 2011 borrowed 98 million interest rate libor 15 3 based december 31 2011 borrowing levels 4 facility available eppoc subsidiaries borrowings guaranteed el paso pipeline partners lp epb designated subsidiaries amounts borrowed nonrecourse el paso borrowing capacity expandable 15 billion certain expansion projects acquisitions 5 based eppoc’s december 31 2011 credit rating applicable margin used calculate interest borrowings letters credit commitment fees determined variable pricing grid tied credit ratings eppoc’s senior unsecured debt restrictive covenants collateral provisions 125 billion revolving credit agreement el paso certain subsidiaries guaranteed facility collateralized general partnership interests epb stock ownership epng tgp also eligible borrowers 2011 collateral restrictions modified providing us ability sell 100 percent ownership interests either epng tgp combination thereof epb upon achieving investment grade status stable outlook either two rating agencies standard poors moody’s collateral support facility eliminated covenants 125 billion revolving credit facility include restrictions debt levels restrictions liens securing debt guarantees restrictions mergers eg proposed merger kmi sales assets dividend restrictions cross default crossacceleration provisions breach covenants could result acceleration debt financial obligations subsidiaries upon event unless agreement amended covenants waived credit agreement restrictive debt covenants cross default provisions ratio debt consolidated earnings interest income taxes depreciation amortization ebitda defined credit agreement shall exceed 525 1 maturity b ratio consolidated ebitda defined credit agreement interest expense plus dividends paid shall less 20 1 maturity c epng tgp cannot incur incremental debt incurrence incremental debt would cause debt consolidated ebitda ratio defined credit agreement particular company exceed 50 1 occurrence event default expiration applicable grace period respect debt aggregate principal amount 200 million epe 10 billion revolving credit agreement facility collateralized certain oil natural gas properties credit agreement subject borrowing base redetermination semiannual basis november 2011 latest revaluation borrowing base capacity reaffirmed 10 billion lenders facility epe’s borrowings facility also subject conditions financial coverage ratio facility requires epe’s debt ebitda defined credit agreement must exceed 40 10 epe’s ebitda interest expense less 20 10 eppoc 10 billion revolving credit facility requires epb wyoming interstate wic maintain consolidated leverage ratio consolidated indebtedness consolidated ebitda defined credit agreement end quarter less 50 10 trailing four consecutive quarter period 55 10 four quarter period three full fiscal quarters subsequent consummation specified permitted acquisitions borrowings facility restricted use eppoc subsidiaries restrictions provisions addition restrictions provisions andor subsidiaries subject various financial nonfinancial covenants restrictions covenants restrictions include change control provisions limitations additional debt subsidiaries limitations use proceeds borrowing subsidiaries limitations cases transactions affiliates limitations incurrence liens limitations subsidiaries participate cash management program potential limitations ability subsidiaries declare pay dividends restrictive crossacceleration provision associated indenture one subsidiaries indenture states event default occur resulting acceleration debt obligations subsidiary excess 10 million longterm debt obligation containing provision could accelerated acceleration debt would adversely affect liquidity position turn financial condition december 31 2011 compliance debt covenants restrictions credit agreements facilities noted also issued various guarantees securing financial obligations subsidiaries affiliates similar covenants facilities financing arrangements capital trusts el paso energy capital trust wholly owned business trust issued 65 million 475 percent trust convertible preferred securities 325 million trust exists sole purpose issuing preferred securities investing proceeds 475 percent convertible subordinated debentures issued due 2028 trust i’s sole source income interest earned debentures interest income used pay distributions preferred securities provide full unconditional guarantee trust i’s preferred securities trust i’s preferred securities nonvoting except limited circumstances pay quarterly distributions annual rate 475 percent carry liquidation value 50 per security plus accrued unpaid distributions convertible common shares time prior close business march 31 2028 option holder rate 12022 common shares trust preferred security equivalent conversion price 4159 per common share classified securities longterm debt right redeem securities time wyco development llc wyco conjunction construction totem gas storage facility totem high plains pipeline joint venture partner wyco funded 50 percent construction costs reflected payments made joint venture partner noncurrent liabilities balance sheet construction upon project completion advances converted financing obligation wyco december 31 2011 principal amounts totem facility high plains pipeline facility 77 million 100 million respectively paid monthly installments 2039 extended term related firm service agreements 2060 2043 respectively interest payments obligations based 50 percent operating results facilities’ currently estimated 155 percent rate december 31 2011 12 commitments contingencies legal proceedings shareholder class actions beginning october 17 2011 twentyone purported shareholder class actions filed challenging proposed acquisition el paso kmi lawsuits filed companies advisor el paso board directors shareholder class actions generally allege el paso board breached fiduciary duties shareholders approving transaction two companies aided alleged breach shareholder class actions seek enjoin transaction hearing held delaware chancery court february 2012 anticipate decision regarding injunction made court early march 2012 eight actions filed consolidated state district court harris county texas thirteen filed consolidated delaware chancery court additional purported class action lawsuit filed behalf unitholders epb delaware chancery court december 2011 el paso board directors lawsuit alleges merger transaction kmi adversely affected unitholders epb el paso board directors breached fiduciary duties motion dismiss suit filed believe purported shareholder class actions without merit intend defend vigorously brinckerhoff lawsuit december 2011 derivative lawsuit filed behalf epb us board directors general partner epb associated transaction completed march 2010 involving sale interests southern lng company llc slng elba express epb lawsuit alleges various conflicts interest consideration paid transaction epb excessive believe action without merit intend defend vigorously retiree medical benefits matters 2002 group retirees case corporation case filed lawsuit federal court detroit michigan entitled yolton et al v el paso tennessee pipeline co case corporation series decisions previous years trial court ruled retirees entitled retiree medical benefits us pursuant collective bargaining agreement case spinoff agreement one predecessors tenneco inc addition obligated pay damages incurred retirees prior court’s entry injunction requiring us pay cost coverage settled case 2011 settlement approved court final process implementing settlement includes amending level benefits see note 13 discussion participants submit claims damages incurred effective date injunction believe accruals established matter adequate cash balance plan lawsuit december 2004 purported class action lawsuit entitled tomlinson et alv el paso corporation el paso corporation pension plan filed us district court denver colorado lawsuit alleges various violations employee retirement income security act erisa age discrimination employment act result change final average earnings formula pension plan cash balance pension plan 2010 district court dismissed claims matter plaintiffs appealed dismissal case august 2011 court appeals tenth circuit affirmed district court’s decision plaintiffs filed petition united states supreme court review case denied matter resolved liability part el paso el paso corporation pension plan price reporting litigation beginning 2003 several lawsuits filed el paso marketing lp epm alleging el paso epm energy companies conspired manipulate price natural gas providing false price information industry trade publications published gas indices several cases settled dismissed remaining cases pending nevada dismissed appeals filed although damages excess 140 million alleged total defendants one remaining lawsuits damage number provided remains significant uncertainty regarding validity causes action damages asserted level damages may allocated us therefore costs legal exposure related remaining outstanding lawsuits claims currently determinable mtbe certain subsidiaries used produced sold distributed methyl tertiarybutyl ether mtbe gasoline additive various lawsuits filed throughout us regarding potential impact mtbe water supplies lawsuits brought different parties including state attorney generals water districts individual water companies seeking different remedies us many defendants including remedial activities damages attorneys’ fees costs cases initially consolidated pretrial purposes multidistrict litigation mdl us district court southern district new york several cases later remanded state court ninetyseven cases settled dismissed settlements substantially funded insurance two remaining lawsuits pending mdl based upon discovery conducted date share relevant markets upon alleged damages historically allocated among individual defendants relatively small addition remains significant uncertainty regarding validity causes action damages asserted level damages may allocated us therefore costs legal exposure related remaining lawsuits currently determinable addition proceedings subsidiaries affiliates named defendants numerous lawsuits governmental proceedings claims arise ordinary course business also regulatory rules orders various stages adoption review andor implementation matters evaluate merits case claim exposure matter possible legal settlement strategies likelihood unfavorable outcome determine unfavorable outcome probable estimated establish necessary accruals outcome matters including discussed cannot predicted certainty still uncertainties related costs may incur based upon evaluation experience date believe established appropriate reserves matters possible however new information future developments could require us reassess potential exposure related matters adjust accruals accordingly adjustments could material december 31 2011 approximately 38 million accrued outstanding legal proceedings rates regulatory matters epng rate case april 2010 ferc approved offer settlement epng’s rate case increased base tariff rates effective january 1 2009 part settlement epng made refunds customers 2010 settlement resolved four issues rate proceeding january 2011 presiding administrative law judge issued decision part found epng four issues epng appealed decisions ferc may also seek review ferc’s decisions us court appeals although final outcome currently determinable believe accruals established matter adequate september 2010 epng filed new rate case ferc proposing increase base tariff rates would increase revenues approximately 100 million annually previously effective tariff rates october 2010 ferc issued order accepting suspending effective date proposed rates april 1 2011 subject refund outcome hearing proceedings hearing commenced late october 2011 concluded december 2011 decision due may 2012 uncertain whether increase achieved context settlement epng customers following outcome hearing rate case although final outcome matter currently determinable believe accruals established matter adequate tgp rate case december 2011 ferc approved tgp’s settlement resolved outstanding issues arising general rate case filing settlement provides among things increase tgp’s base tariff rates effective june 1 2011 ii implementation cost trackers fuel pipeline safety greenhouse gas iii significant contract extensions october 2014 iv filing requirement next general rate case effective earlier april 2014 later november 2015 v revenue sharing mechanism certain customers certain revenues annual threshold addition part settlement tgp refund approximately 68 million customers march 31 2012 believe accruals established matter adequate addition provisions discussed settlement also required tgp reduce regulatory liabilities associated postretirement benefit plan certain deferred taxes reflected adjustments increase operating revenues approximately 40 million since items provided prior rate settlements funding requirement cost recovery current rates items discussion regulatory assets liabilities see note 8 cig rate case august 2011 ferc approved uncontested prefiling settlement cig’s rate case required terms previous settlement generally provides cig’s current tariff rates continue next general rate case effective earlier october 1 2014 later october 1 2016 ii contract extensions march 2016 iii revenue sharing mechanism certain customers certain revenues annual threshold amounts iv revenue surcharge mechanism certain customers charge certain shortfalls revenue less annual threshold amount environmental matters subject federal state local laws regulations governing environmental quality pollution control laws regulations require us remove remedy effect disposal release specified substances current former operating sites december 31 2011 accrued approximately 181 million environmental matters reduced 18 million amounts paid directly government sponsored programs settlement arrangements third parties accrual includes approximately 178 million expected remediation costs associated onsite offsite groundwater technical studies approximately 3 million related environmental legal costs estimates potential liability range approximately 181 million approximately 321 million recorded environmental liabilities reflect current estimates amounts expend remediation projects various stages completion however depending stage completion assessment ultimate extent contamination remediation required may known additional assessments occur remediation efforts continue may incur additional liabilities type site reserves based following estimates reasonably possible outcomes superfund matters included recorded environmental liabilities projects received notice designated could designated potentially responsible party prp comprehensive environmental response compensation liability act cercla commonly known superfund state equivalents 28 active sites liability federal cercla statute may joint several meaning could required pay excess pro rata share remediation costs consider financial strength prps estimating liabilities accruals issues included previously indicated estimates superfund sites 2012 estimate total remediation expenditures approximately 67 million expended government directed cleanup plans addition expect make capital expenditures environmental matters approximately 19 million aggregate years 2012 2016 including capital expenditures associated impact epa rule emissions hazardous air pollutants reciprocating internal combustion engines subject regulations compliance october 2013 possible new information future developments could require us reassess potential exposure related environmental matters may incur significant costs liabilities order comply existing environmental laws regulations also possible developments increasingly strict environmental laws regulations orders regulatory agencies well claims damages property environment injuries employees persons resulting current past operations could result substantial costs liabilities future information becomes available relevant developments occur adjust accrual amounts accordingly still uncertainties related ultimate costs may incur based upon evaluation experience date believe reserves adequate commitments purchase obligations matters operating leases maintain operating leases ordinary course business activities leases include office space operating facilities equipment terms agreements vary 2012 2053 future minimum annual rental commitments operating leases net minimum sublease rentals december 31 2011 follows rental expense 38 million year ended december 31 2011 39 million years ended december 31 2010 2009 reflected operation maintenance expense included rental expense approximately 20 million period associated rightofway arrangements principally related longterm commitment extends 2025 guarantees indemnifications involved various joint ventures ownership arrangements sometimes require financial performance guarantees financial guarantee obligated make payments guaranteed party fails make payments violates terms financial arrangement performance guarantee provide assurance guaranteed party execute terms contract required perform behalf also periodically provide indemnification arrangements related assets businesses sold arrangements include limited indemnifications income taxes resolution existing disputes environmental matters potential exposure guarantee indemnification agreements range specified amount unlimited dollar amount depending nature claim specificity duration particular transaction arrangements specified dollar amount maximum stated value approximately 710 million comprised 438 million indemnification associated sale anr pipeline company anr 120 million indemnification associated sale macae power facility brazil 152 million indemnifications guarantees related sale legacy assets fourth quarter 2011 received full claim macae indemnification matters believe specifically excluded scope indemnification amounts exclude guarantees issued related letters credit discussed note 11 included maximum stated value certain indemnification agreements expired however claims made prior expiration related claim periods unable estimate maximum exposure guarantee indemnification agreements provide limits amount future payments due uncertainty exposures december 31 2011 2010 recorded obligations 15 million 18 million related guarantee indemnification arrangements liability consists primarily indemnification one subsidiaries provided related sale ammonia facility reflected financial statements estimated fair value provided partial parental guarantee subsidiary’s obligations indemnification believe guarantee indemnification agreements recorded liability probable resulting future losses based assessment nature guarantee financial condition guaranteed party period time guarantee outstanding among considerations commitments purchase obligations 2009 ferc approved amendment 1995 ferc settlement tgp provides interim refunds three year period approximately 157 million plus interest 8 amounts collected related certain environmental costs december 31 2011 tgp refunded approximately 138 million customers expects refund remaining obligation recorded current liabilities balance sheet approximately 40 million 2012 also various commercial commitments purchase obligations recorded balance sheet december 31 2011 firm commitments transportation storage capacity contracts 1150 million approximately half paid next 5 years ii purchase capital commitments including drilling maintenance engineering procurement construction contracts approximately 230 million majority due less one year also hold cancelable easements rightofway arrangements landowners permitting use land construction operation pipeline systems see operating leases 13 retirement benefits overview retirement benefit plans pension plans primary pension plan defined benefit plan covers substantially us employees provides benefits cash balance formula certain employees participated prior pension plans el paso sonat inc coastal corporation receive greater cash balance benefits transition benefits prior plan formulas anticipate making contributions cash balance pension plan 2012 addition primary pension plan maintain supplemental executive retirement plan serp provides additional benefits selected officers key management serp provides benefits excess certain irs limits essentially mirror primary pension plan expect contribute 4 million serp 2012 retirement savings plan maintain defined contribution plan covering us employees match 75 percent participant basic contributions six percent eligible compensation make additional discretionary matching contributions depending overall performance company relative peers amounts expensed plan approximately 38 million 39 million 19 million years ended december 31 2011 2010 2009 2011 2010 amounts expensed include additional discretionary matching contribution postretirement benefit plans provide postretirement benefits opeb including medical benefits closed groups retired employees certain retirees case described note 12 limited postretirement life insurance benefits current retired employees medical benefits closed groups retirees may subject deductibles copayment provisions limitations dollar caps amount employer costs reserve right change benefits opeb plans certain regulated pipeline companies prefunded extent costs recoverable rates information see notes 1 8 expect contribute 32 million postretirement benefit plans 2012 matters conjunction settlement case matter described note 12 amended opeb plan plaintiffs participants align benefits plan settlement agreement impact amendment reflected opeb liability accumulated comprehensive income december 31 2011 benefit obligation plan assets funded status accounting pension opeb plans record asset liability based funded status plan deferred amounts related unrecognized gains losses changes actuarial assumptions recorded either regulatory asset liability certain regulated operations accumulated comprehensive income loss operations gains losses recognized income statement 2011 reclassified 19 million net taxes 6 million net regulatory liability accumulated comprehensive income pursuant rate case settlements whereby amounts longer included rates charge customers certain regulated operations table provides information pension opeb plans years ended december 31 1 benefit obligation pension plans represents projected benefit obligation benefit obligation opeb plans represents accumulated postretirement benefit obligation 2 amounts opeb shown net subsidy approximately 6 million 5 million years ended december 31 2011 2010 related medicare prescription drug improvement modernization act 2003 3 defer difference actual return plan assets expected return three year period considered inclusion net benefit expense income deferred actuarial gains losses amortized extent remaining unrecognized actual gains losses exceed greater 10 percent benefit obligations market related value plan assets components funded status following table details amounts recognized balance sheet december 31 2011 2010 related pension opeb plans components accumulated comprehensive income loss following table details amounts recognized accumulated comprehensive income loss net income taxes december 31 2011 2010 related pension opeb plans anticipate approximately 53 million accumulated comprehensive loss net tax recognized part net periodic benefit cost 2012 accumulated benefit obligation defined benefit pension plans 23 billion 22 billion december 31 2011 2010 accumulated benefit obligation defined benefit pension plans whose accumulated benefit obligations exceeded fair value plan assets 23 billion 22 billion december 31 2011 2010 fair value plans’ assets approximately 19 billion 20 billion december 31 2011 2010 accumulated postretirement benefit obligation opeb plans whose accumulated postretirement benefit obligations exceeded fair value plan assets 435 million 558 million december 31 2011 2010 fair value plans’ assets 3 million 58 million december 31 2011 2010 plan assets primary investment objective plans ensure longterm life plans adequate pool sufficiently liquid assets exists meet benefit obligations participants retirees beneficiaries investment objectives longterm nature covering typical market cycles shortfall investment performance compared investment objectives generally result economic capital market conditions plans’ investments include wide diversification asset types fund strategies fund managers although actual allocations vary time targeted allocations target allocations pension plans’ assets 50 percent equity securities 40 percent fixed income securities 10 percent types investments target allocations opeb plans’ assets 65 percent equity 35 percent fixed income securities equity securities pension plans’ assets may include investments largecap midcap smallcap companies united states well investments foreign companies fixed income securities may include corporate bonds companies diversified industries well international fixed income securities united states treasuries stable income products investment contracts types investments may include hedge funds real estate investments follow several different strategies opeb plans may invest plan assets manner replicates extent feasible russell 3000 index barclays capital aggregate bond index achieve equity fixed income diversification respectively details pension opeb plans assets classified level description fair values • level 1 assets’ fair values based quoted prices instruments actively traded markets included level interest bearing cash equity securities exchange traded mutual fund securities • level 2 assets’ fair values primarily based pricing data representative quoted prices similar assets active markets identical assets less active markets included level commoncollective trust funds mutual funds fixed income securities commoncollective trust funds’ mutual funds’ fair values primarily based net asset value reported issuer determined based fair value underlying securities valuation date common collective trust funds mutual funds certain restrictions redemption exist december 31 2011 issuer reserves right temporarily delay withdrawal certain situations market conditions issuer’s discretion fixed income securities fair values primarily based evaluated price based compilation primarily observable market information broker quote nonactive market • level 3 assets’ fair values similar level 2 assets calculated using valuation techniques require inputs significant fair value measurement unobservable included level limited partnership mutual fund fair value investments primarily based net asset value reported issuer determined based fair value underlying securities valuation date listed fair values pension opeb plans’ assets recorded fair value classified level december 31 2011 2010 millions 1 2011 category includes commoncollective trust funds invested approximately 54 percent fixed income 42 percent equity 4 percent short term securities 2010 category includes commoncollective trust funds invested approximately 51 percent fixed income 46 percent equity 3 percent short term securities 2 2011 category includes mutual funds invested approximately 45 percent fixed income 55 percent investments 2010 category includes mutual funds invested approximately 59 percent fixed income 41 percent investments 1 category includes common collective trust funds invested approximately 65 percent equity 35 percent fixed income securities following table presents changes pension plan assets included level 3 years ended december 31 2011 2010 expected payment future benefits december 31 2011 expect following benefit payments plans 1 includes reduction approximately 7 million years 20122016 approximately 34 million aggregate 20172021 expected subsidy related medicare prescription drug improvement modernization act 2003 actuarial assumptions sensitivity analysis benefit obligations net benefit cost based actuarial estimates assumptions following table details weightedaverage actuarial assumptions used determining benefit obligation net benefit costs pension opeb plans 2011 2010 2009 1 expected return plan assets listed table pretax rate return based targeted portfolio investments utilize aftertax expected return plan assets determine benefit costs based unrelated business income tax rate 35 percent actuarial estimates opeb plans assumed weightedaverage annual rate increase per capita costs covered health care benefits 73 percent gradually decreasing 50 percent year 2019 assumed health care cost trends significant effect amounts reported opeb plans onepercentage point change assumed health care cost trends would following effects december 31 2011 2010 components net benefit cost years ended december 31 components net benefit cost follows components comprehensive income loss following table details amounts recognized comprehensive loss net income taxes years ended december 31 2011 2010 2009 related pension opeb plans 14 equity noncontrolling interests convertible perpetual preferred stock march 2011 exercised conversion right related 750 million convertible perpetual preferred stock upon conversion holders convertible preferred stock received approximately 579 million shares common stock approximately 772295 shares el paso common stock share preferred stock converted common preferred stock dividends table shows amount dividends declared andor paid millions except per share amounts dividends common stock preferred stock treated reduction additional paidincapital since currently accumulated deficit expect dividends paid common stock 2012 taxable stockholders anticipate dividends paid current accumulated earnings profits tax purposes accumulated comprehensive income loss following table provides components accumulated comprehensive income loss december 31 noncontrolling interests general partner epb master limited partnership mlp december 31 2011 44 percent interest epb 2 percent general partner interest 42 percent limited partner interest years ended december 31 2011 2010 2009 epb issued noncontrolling interests net issuance costs 09 billion 13 billion 02 billion conjunction contribution epb additional ownership interests cig sng southern lng company llc slng owns elba island lng receiving terminal el paso elba express company llc elba express owns elba express pipeline december 31 2011 mlp owns 100 percent entities except cig owns 86 percent issuance epb common units reflected consolidated statements equity december 31 2011 increase 610 million noncontrolling interests increase 213 million net deferred tax liability el paso corporation’s additional paid capital net income attributable el paso corporation together increase el paso corporation’s additional paidin capital year ended december 31 2011 totaled 354 million accordance partnership agreement epb obligated make quarterly distributions available cash unitholders receive share cash distributions limited partner ownership interest general partner interest incentive distribution rights idr’s hold general partner prior february 15 2011 held subordinated units epb upon payment quarterly cash distribution fourth quarter 2010 financial tests required conversion subordinated units common units satisfied result subordinated units converted february 15 2011 common units oneforone basis effective january 3 2011 extent consideration sales assets epb form additional equity epb interest assets becomes diluted time however economic interest benefit receipt incentive distributions accordance partnership agreement idrs pay increasing percentage interest quarterly distributions cash based level distribution unitholders holder rights elect relinquish right receive incentive distribution payments reset higher levels minimum quarterly distribution amount cash target distribution levels upon incentive distribution payments would set currently entitled receive maximum level incentive distributions additional information regarding master limited partnership see note 11 net income attributable noncontrolling interests components net income attributable noncontrolling interests statements income year ended december 31 follows 15 stockbased compensation overview stockbased compensation plans issue employees incentive stock options common stock intended qualify section 422 internal revenue code nonqualified stock options restricted stock restricted stock units stock appreciation rights performance shares performance units stockbased awards pursuant merger agreement kmi closing merger unvested stockbased compensation awards immediately vest become exercisable performance shares vesting 100 percent targeted shares time unrecognized stockbased compensation expense accelerate disclosures tables follow based existing terms stockbased compensation awards reflect impacts merger agreement kmi currently authorized grant awards approximately 62 million shares common stock current plans includes 545 million shares omnibus plan 25 million shares nonemployee director plan 5 million shares employee stock purchase plan december 31 2011 approximately 173 million shares remain available grant current plans includes approximately 138 million shares omnibus plan 15 million shares nonemployee director plan 2 million shares employee stock purchase plan also approximately 4 million shares stock option awards outstanding granted terminated plans obligate us issue additional shares common stock exercised stock option exercises restricted stock funded primarily issuance new common shares record stockbased compensation expense excluding amounts capitalized operation maintenance expense requisite service period separately vesting portion award net estimates forfeitures actual forfeitures differ estimates additional adjustments compensation expense required future periods nonqualified stock options grant nonqualified stock options employees exercise price equal market value stock grant date stock option awards contractual terms 10 years generally vest equal amounts three years grant date pay dividends unexercised options summary stock option transactions year ended december 31 2011 presented 2011 2010 2009 recognized approximately 20 million 24 million 23 million pretax compensation expense stock options capitalized approximately 3 million 4 million 5 million expense part fixed assets generated 7 million 8 million 8 million income tax benefits respectively total compensation cost related nonvested option awards yet recognized december 31 2011 approximately 14 million expected recognized weighted average period 9 months options exercised years ended december 31 2011 2010 2009 total intrinsic value 53 million 5 million less 1 million generated 68 million 8 million 1 million cash proceeds generated unrealized income tax benefit 19 million 2011 options exercised years ended december 31 2010 2009 generate significant associated income tax benefits fair value assumptions fair value stock option granted estimated date grant using blackscholes optionpricing model based several assumptions based management’s best estimate time grant years ended december 31 2011 2010 2009 weighted average grant date fair value per share options granted 729 455 296 listed weighted average assumption based grants fiscal year estimate expected volatility based analysis implied volatilities traded options common stock historical stock price volatility expected term estimate expected term option awards based vesting period average remaining contractual term referred “simplified method” use method provide reasonable basis estimating expected term based insufficient historical data prior 2006 primarily due significant changes composition employees receiving stockbased compensation awards restricted stock grant shares restricted common stock carry voting dividend rights officers employees sale transfer shares restricted vest fair value restricted shares determined grant date shares generally vest equal amounts three years date grant summary changes nonvested restricted shares year ended december 31 2011 presented weighted average grant date fair value per share restricted stock granted 2011 2010 2009 1818 1109 653 total fair value shares vested 2011 2010 2009 42 million 27 million 13 million 2011 2010 2009 recognized approximately 42 million 25 million 26 million pretax compensation expense restricted share awards capitalized approximately 6 million 4 million 7 million expense part fixed assets 2011 generated unrealized income tax benefit 15 million 2010 2009 recorded income tax benefits 9 million related restricted stock arrangements total unrecognized compensation cost related arrangements december 31 2011 approximately 40 million expected recognized weighted average period 10 months performance shares beginning 2011 granted approximately 07 million performance shares el paso officers number performance shares ultimately earned vary zero 200 percent targeted shares depending level total shareholder return “tsr” relative el paso’s peer group companies performance shares carry dividend rights cannot sold transferred vest fair value performancebased shares granted estimated day grant using montecarlo simulation awards granted fifty percent vest end two year performance period beginning january 1 2011 grant date fair value per share 2793 remaining fifty percent vest end three year performance period beginning january 1 2011 grant date fair value per share 2764 2011 recognized approximately 6 million pretax compensation expense related awards generated unrealized income tax benefit 2 million december 31 2011 number shares would issue 2011 performance grants assuming awards vested relative tsr performance determined date would approximately 13 million shares december 31 2011 performance shares unvested unrecognized compensation cost approximately 12 million expected recognized weighted average period approximately 12 months employee stock purchase plan employee stock purchase plan allows participating employees right purchase common stock 95 percent market price last trading day month plan noncompensatory provisions current stock compensation accounting standards shares issued plan insignificant 2011 2010 2009 16 business segment information december 31 2011 business consists two core segments pipelines exploration production also marketing segment segments strategic business units provide variety energy products services managed separately segment requires different technology marketing strategies discussion segment activities follows pipelines segment provides natural gas transmission storage related services united states december 31 2011 conducted activities primarily eight wholly majority owned interstate pipeline systems equity interests three transmission systems addition storage capacity wholly majority owned pipelines systems also interests three underground natural gas storage facilities two lng terminalling facilities exploration production exploration production segment engaged exploration acquisition development production oil natural gas ngl united states brazil egypt marketing segment markets manages price risks associated oil natural gas production well manages remaining legacy trading portfolio activities include general administrative functions midstream operations miscellaneous businesses customers whose revenues exceeded 10 percent total revenues 2011 2010 2009 use segment earnings interest expense income taxes segment ebit measure assess operating results effectiveness business segments believe segment ebit useful investors allows use performance measure analyzed internally management evaluate performance operating businesses investments without regard manner financed capital structure segment ebit defined net income loss adjusted interest debt expense income taxes reflect reduction amounts attributable noncontrolling interests segment ebit may comparable measurements used companies additionally segment ebit considered conjunction net income loss income loss income taxes performance measures operating income operating cash flows 2010 2009 amounts conformed reflect current performance measure reconciliation segment ebit net income loss periods ended december 31 following tables reflect segment results three years ended december 31 1 revenues external customers include gains 284 million related financial derivative contracts associated oil natural gas production 2 intersegment revenues along intersegment expenses incurred normal course business operating segments intersegment revenues primarily represent sales marketing segment responsible marketing production third parties additionally 2011 tgp sold 95 tbtu natural gas used operations affiliate el paso marketing lp june 2011 tgp terminated contract connection implementation fuel volume tracker part rate case filed ferc 3 reflects noncash loss approximately 600 million 475 million based difference carrying value ruby estimated fair value investment ruby 125 million related recognition accumulated comprehensive loss associated interest rate swaps ruby’s debt see note 18 4 includes gain approximately 16 million related sale remaining interest telecommunications equity investment 5 total foreign assets approximately 03 billion relates property plant equipment approximately 01 billion relates investments unconsolidated affiliates 6 amounts net third party reimbursements cash capital expenditures returns capital sales investments advances 1 revenues external customers include gains 390 million related financial derivative contracts associated oil natural gas production 2 intersegment revenues along intersegment expenses incurred normal course business operating segments intersegment revenues primarily represent sales marketing segment responsible marketing production third parties 3 includes 110 million gain related sale midstream assets newly formed joint venture 21 million noncash asset write pipelines based ferc order related sale compressor station gas processing plant 2009 4 includes gain approximately 80 million related sale interests certain mexican pipeline compression assets 5 total foreign assets approximately 04 billion relates property plant equipment approximately 01 billion relates investments advances unconsolidated affiliates 6 amounts net third party reimbursements cash capital expenditures returns capital sales investments advances 1 revenues external customers include gains 687 million related financial derivative contracts associated oil natural gas production 2 intersegment revenues along intersegment expenses incurred normal course business operating segments intersegment revenues primarily represent sales marketing segment responsible marketing production third parties 3 total foreign assets approximately 04 billion relates property plant equipment approximately 03 billion relates investments advances unconsolidated affiliates 4 amounts net third party reimbursements cash capital expenditures returns capital sales investments advances 17 accounts receivable sales programs accounts receivable sales programs participate accounts receivable sales programs several pipeline subsidiaries sell receivables entirety thirdparty financial institution whollyowned special purpose entities sale accounts receivable shortterm assets generally settle within 60 days qualify sale accounting third party financial institution involved accounts receivable sales programs acquires interests various financial assets issues commercial paper fund acquisitions consolidate third party financial institution power control direct exert significant influence overall activities since receivables comprise significant portion operations connection accounts receivable sales receive portion sales proceeds front receive additional amount upon collection underlying receivables refer deferred purchase price ability recover deferred purchase price based solely collection underlying receivables table contains information related accounts receivable sales programs 1 years ended december 31 2011 2010 losses recognized sale accounts receivable immaterial 2 january 2010 terminated previous accounts receivable sales programs paid 90 million acquire related senior interests certain receivables programs 2009 sold approximately 19 billion accounts receivable programs fees losses related programs material 1 initially recorded amount approximates fair value level 2 measurement deferred purchase price related accounts receivable sold reflected accounts receivable balance sheet cash received front deferred purchase price relate sale ultimate collection underlying receivables subject significant risks given short term nature reflect cash flows accounts receivable sales programs operating cash flows statement cash flows accounts receivable sales programs service underlying receivables fee fair value servicing agreements well fees earned material financial statements years ended december 31 2011 2010 2009 18 investments earnings transactions unconsolidated affiliates hold investments unconsolidated affiliates accounted using equity method accounting earnings unconsolidated affiliates reflected income statement include share net earnings directly attributable unconsolidated affiliates ii impairments gains losses divestitures adjustments recorded us december 31 2011 net equity underlying net assets investments exceeded investment balance 245 million december 31 2010 investment balance exceeded net equity underlying net assets investments 98 million difference balances primarily relates purchase price adjustments certain investments net impairments andor differences resulting deconsolidation certain entities information related unconsolidated affiliates includes net investment earnings losses recorded investments including amortization andor impairments investments ii summarized financial information investments iii revenues charges unconsolidated affiliates net ownership interest investments earnings losses unconsolidated affiliates follows years ended december 31 1 common interests ruby partner owns convertible preferred interests ruby amortize portion difference underlying equity net assets ruby investment balance 2 december 31 2011 outstanding receivables approximately 37 million included long term assets related promissory note citrus whereby lend 150 million 3 recorded amortization purchase cost excess underlying net assets four star 34 million year ended december 31 2011 38 million year ended december 31 2010 48 million year ended december 31 2009 included amortize generally assess recoverability investment based development production underlying estimated proved oil natural gas reserves four star fair value investment four star could decline result lower natural gas prices may required record impairment carrying value future 4 december 31 2011 2010 outstanding advances receivables 165 million 85 million included current long term assets related investment gulf lng 5 33 percent bbpp holdings ltd owns 29 percent bolivia brazil pipeline 6 2010 completed sale interest investment recorded pretax gain approximately 80 million see note 2 7 includes gain approximately 16 million related sale remaining interest telecommunications equity investment received distributions dividends unconsolidated affiliates approximately 61 million 64 million 90 million years ended december 31 2011 2010 2009 2010 made capital contribution 100 million citrus one unconsolidated affiliates ruby prior september 2011 reflected ruby consolidated variable interest entity primary beneficiary september 2011 met certain conditions lenders partner global infrastructure partners gip el paso’s guarantee gip’s preferred interests ruby cheyenne plains investment company llc cheyenne plains expired accordingly longer reflect approximately 769 million preferred stock subsidiaries liabilities equity balance sheet included 700 million gip’s investment convertible preferred stock subsidiaries 69 million accrued preferred returns result meeting conditions gip transferred 145 million convertible preferred interests cheyenne plains us exchange additional convertible preferred interests ruby following events ruby cheyenne plains longer considered variable interest entities although continue operate ruby pipeline controlling financial interest ruby therefore deconsolidated prospectively financial statements prior deconsolidation ruby’s individual assets liabilities reflected balance sheet income loss reflected income statement gip’s returns preferred interests ruby cheyenne plains recorded net income attributable noncontrolling interests income statement upon ruby’s deconsolidation september 2011 longer reflect individual assets liabilities ruby balance sheet began recording ruby’s results earnings unconsolidated affiliates income statement time deconsolidation amounts balance sheet consisted primarily approximately 3673 million property plant equipment 348 million regulatory assets 125 million price risk management liabilities associated interest rate swaps ruby’s debt 138 million liabilities 1447 million long term debt upon deconsolidation required assess investment ruby impairment based fair value different model assessing recoverability ruby pipeline based estimated undiscounted cash flows consolidated fair value assessment based number factors including present value anticipated distributable cash flows produced underlying operations ruby investment assessing cash flows required use assumptions related future demand ruby’s operations forecasted commodity prices interest rates anticipated economic conditions timing gip’s conversion preferred interest common equity interest inputs many available observable market data result estimate fair value level 3 fair value measurement result deconsolidation ruby fair value assessments recorded noncash loss approximately 475 million based difference carrying value ruby estimated fair value investment ruby noncash loss 125 million related recognition accumulated comprehensive loss associated interest rate swaps ruby’s debt summarized financial information unconsolidated affiliates summarized financial information operating results financial position unconsolidated affiliates revenues expenses transactions unconsolidated affiliates material 2011 2010 2009 investmentrelated matters currently outstanding disputes matters related investment two brazilian power plant facilities manausrio negro formerly owned us filed lawsuits collect amounts due us approximately 62 million brazilian reaisdenominated accounts receivable plant’s power purchaser also guaranteed purchaser’s parent eletrobras brazil’s stateowned utility power utility purchased power facilities parent asserted counterclaims would fully offset accounts receivable absent resolution matters settlement anticipate ultimate resolution likely occur legal proceedings brazilian courts believe receivables collectible therefore established allowance receivables owed reviewed obligations power purchase agreements accrued believe appropriate amount relation asserted counterclaims believe remaining counterclaims without merit based anticipated timing resolution legal proceedings classified accounts receivable accrual counterclaims noncurrent asset liability financial statements project companies previously owned manaus rio negro power plants also assessed approximately 76 million brazilian reaisdenominated icms taxes brazilian taxing authorities payments received companies plants’ power purchaser 1999 2001 agreement power purchaser indemnifying project companies icms taxes along related interest penalties third quarter 2010 court hearing rio negro case seized funds certain rio negro project company’s bank accounts partial satisfaction security potential tax liability order prevent collection efforts tax authorities matter project companies security must provided potential tax liability court’s satisfaction power purchaser taxing authorities agreed upon posting shares subsidiary power purchaser’s parent security courts hearing rio negro manaus cases accepted shares security court rio negro case lifted order respect project company’s assets matter fully resolved ability collect amounts due us power purchaser could impacted potential taxes owed manaus rio negro project companies also guaranteed purchaser’s parent believe required pay amounts related matter accordingly established accruals matter ultimate resolution matters discussed unknown time adverse developments related either ability collect amounts due us related disputes claims could require us record additional losses future supplemental selected quarterly financial information unaudited financial information quarter summarized items affecting comparability amounts reported respective quarters 2011 2010 december 31 2011 recorded 71 million tax benefit conversion subsidiary limited liability company ii 40 million increase operating revenues result rate case settlement iii 10 million gains related changes fair value exploration production financial derivatives september 30 2011 recorded 600 million noncash loss deconsolidation ruby ii 251 million gains related changes fair value exploration production financial derivatives iii 152 million noncash brazilian ceiling test charge iv 101 million losses associated repurchase debt june 30 2011 recorded 132 million gains related changes fair value exploration production financial derivatives ii 27 million losses associated repurchase debt march 31 2011 recorded 109 million losses related changes fair value exploration production financial derivatives ii 41 million losses associated repurchase debt december 31 2010 recorded 113 million loss debt extinguishment ii 110 million gain sale midstream assets joint venture iii 78 million losses related changes fair value exploration production financial derivatives september 30 2010 recorded 184 million gains related changes fair value exploration production financial derivatives ii 104 million loss debt extinguishment june 30 2010 recorded 80 million gain sale interests certain mexican pipeline compression assets earnings unconsolidated affiliates ii 31 million gains related changes fair value exploration production financial derivatives march 31 2010 recorded 253 million gains related changes fair value exploration production financial derivatives supplemental oil natural gas operations unaudited exploration production segment engaged exploration acquisition development production oil natural gas ngl united states us brazil egypt capitalized costs capitalized costs relating oil natural gas producing activities related accumulated depreciation depletion amortization follows december 31 millions 1 capitalized costs egypt 74 million 66 million december 31 2011 2010 included costs subject amortization 2011 recorded ceiling test charge 152 million brazilian full cost pool 2010 recorded ceiling test charge 25 million egyptian full cost pool 2 amounts represent approximate 49 percent equity interest underlying oil gas assets four star four star applies successful efforts method accounting oil gas properties total costs incurred costs incurred oil natural gas producing activities whether capitalized expensed follows year ended december 31 millions 1 costs incurred egypt 8 million 20 million 81 million years ended december 31 2011 2010 2009 2 amounts represent approximate 49 percent equity interest underlying costs incurred four star pursuant full cost method accounting capitalize certain general administrative expenses directly related property acquisition exploration development activities interest costs incurred attributable unproved oil natural gas properties major development projects oil natural gas properties table includes capitalized internal general administrative costs incurred connection acquisition development exploration oil natural gas reserves 81 million years ended december 31 2011 2010 80 million year ended december 31 2009 also capitalized interest 13 million 9 million 7 million years ended december 31 2011 2010 2009 december 31 2011 reserve report amounts estimated spent 2012 2013 2014 develop consolidated worldwide proved undeveloped reserves 1003 million 1009 million 1329 million respectively unevaluated capitalized costs exclude capitalized costs oil natural gas properties amortization various stages evaluation part major development project expect costs included amortization calculation next three five years presented analysis capitalized costs oil natural gas properties year expenditure amortized december 31 2011 pending determination proved reserves millions 1 includes capitalized interest 2 million 6 million 2 million years ended december 31 2011 2010 2009 2 includes 155 million related wolfcamp shale 94 million related eagle ford shale december 31 2011 3 includes 8 million related brazil december 31 2011 informed environmental permit request pinauna field camamu basin denied result released 94 million unevaluated capitalized costs related field brazilian full cost pool additionally 2011 released approximately 86 million unevaluated capitalized costs brazilian full cost pool related espirito santo basin upon completion evaluation exploratory wells drilled 2009 2010 without additions proved reserves continue pursue alternatives hydrocarbons discovered areas see note 3 discussion oil natural gas reserves net quantities proved developed undeveloped reserves natural gas oil condensate ngl changes reserves december 31 2011 presented tables based internal reserve report net proved reserves exclude royalties interests owned others reflect contractual arrangements royalty obligations effect time estimate 2010 consolidated proved reserves consistent estimates proved reserves filed federal agencies 2011 except differences less five percent resulting actual production acquisitions property sales necessary reserve revisions additions reflect actual experience ryder scott company lp ryder scott conducted audit estimates proved reserves prepared us december 31 2011 connection audit ryder scott reviewed 86 percent properties associated proved reserves natural gas equivalent basis representing 87 percent total discounted future net cash flows proved reserves ryder scott also conducted audit estimates prepared proved reserves four star december 31 2011 connection audit proved reserves ryder scott reviewed 87 percent properties associated four star’s total proved reserves natural gas equivalent basis representing 91 percent total discounted future net cash flows reviewed properties overall proved reserves estimates within 10 percent ryder scott’s estimates ryder scott’s report included exhibit annual report form 10k 1 2009 572 bcfe extensions discoveries 301 bcfe related central division 208 bcfe related haynesville shale 70 bcfe related hollykingston fields also 147 bcfe extensions discoveries related altamont western division 83 bcfe related camarupim field brazil addition 41 bcfe extensions discoveries related gulf coast division 14 bcfe related eugene island 364365 gulf mexico 12 bcfe related wilcox area south texas 2009 acquired interests domestic oil natural gas producing properties located western division also sold domestic natural gas producing properties located central western divisions 2 2010 693 bcfe extensions discoveries 452 bcfe related central division 425 bcfe related haynesville shale area 238 bcfe extensions discoveries gulf coast division 187 bcfe coming eagle ford shale western division accounted 3 bcfe extensions discoveries extensions discoveries international division 3 2011 1105 bcfe extensions discoveries 428 bcfe related central division 389 bcfe related haynesville shale area 592 bcfe extensions discoveries southern division 479 bcfe coming eagle ford shale 113 coming wolfcamp shale western division accounted 85 bcfe extensions discoveries extensions discoveries international division beginning december 31 2009 accordance sec regulation sx rule 410 amended use 12month average price calculated unweighted arithmetic average spot price first day month within 12month period prior end reporting period first day 12month average us price used estimate proved reserves december 31 2011 412 per mmbtu natural gas 9619 per barrel oil prices used international assets contractually defined aggregate international price used estimate proved reserves december 31 2011 531 per mmbtu natural gas 10929 per barrel oil estimates proved reserves determined according rules prescribed sec existence time estimates made rules require standard “reasonable certainty” applied proved reserve estimates defined high degree confidence quantities recovered high degree confidence exists quantity much likely achieved technical economic data becomes available positive upward revision much likely negative downward revision estimates subject revision based upon number factors including many factors beyond control reservoir performance prices economic conditions government restrictions addition result drilling testing production subsequent date estimate may justify revision estimate reserve estimates often different quantities oil natural gas ultimately recovered estimating quantities proved oil natural gas reserves complex process involves significant interpretations assumptions cannot measured exact manner requires interpretations judgment available technical data including evaluation available geological geophysical engineering data accuracy reserve estimate highly dependent quality available data accuracy assumptions based upon economic factors oil natural gas prices production costs severance excise taxes capital expenditures workover remedial costs assumed effects governmental regulation addition due lack substantial production data greater uncertainties estimating proved undeveloped reserves proved developed nonproducing reserves proved developed reserves early production life result reserve estimates inherently imprecise meaningfulness reserve estimates highly dependent accuracy assumptions based general volume production oil natural gas properties declines reserves depleted except extent conduct successful exploration development activities acquire additional properties containing proved reserves proved reserves decline reserves produced subsequent december 31 2011 major discoveries events favorable otherwise may considered caused significant change estimated proved reserves december 31 2011 current natural gas prices significantly 12month average price used determine domestic proved reserves december 31 2011 sustained period low domestic natural gas prices time result downward revision proved reserves corresponding reduction discounted future net cash flows proved reserves results operations results operations oil natural gas producing activities fiscal year follows december 31 millions 1 excludes effects oil natural gas derivative contracts 2 production costs include lease operating costs production related taxes including ad valorem severance taxes 3 includes 152 million related brazil year ended december 31 2011 25 million 34 million related egypt years ended december 31 2010 2009 4 includes accretion expense asset retirement obligations 13 million 005mcfe 2011 16 million 006mcfe 2010 2009 respectively 5 results include amortization 34 million 38 million 48 million years ended december 31 2011 2010 2009 related cost excess equity interest underlying net assets four star 6 includes accretion expense asset retirement obligations 2 million 010mcfe 2011 1 million 006mcfe 2010 2 million 006mcfe 2009 standardized measure discounted future net cash flows standardized measure discounted future net cash flows relating consolidated proved oil natural gas reserves december 31 follows millions 1 company commoditybased derivative contracts designated accounting hedges december 31 2011 2010 2009 amounts also exclude impact future net cash flows derivatives designated accounting hedges 2 amounts represent approximate 49 percent equity interest four star calculations preceding table estimated future cash inflows estimated future production proved reserves december 31 2011 computed using first day 12month average us price 412 per mmbtu natural gas 9619 per barrel oil aggregate international price used estimate proved reserves december 31 2011 531 per mmbtu natural gas 10929 per barrel oil changes standardized measure discounted future net cash flows following principal sources change consolidated worldwide standardized measure discounted future net cash flows millions 1 disclosure reflects changes standardized measure calculation excluding effects hedging activities schedule valuation qualifying accounts schedule ii el paso corporation valuation qualifying accounts years ended december 31 2011 2010 2009 millions 1 amounts reflect valuation allowances primarily associated foreign state net operating losses foreign ceiling test charges 2 reflects rate refund settlement activity item 9 nannannannanitem 15 exhibits financial statement schedules reports form 8k following documents filed part report 1 financial statements consolidated financial statements included part ii item 8 report b reports form 8k also furnished information sec item 9 current reports form 8k item 9 current reports form 8k considered filed purposes section 18 securities exchange act 1934 subject liabilities section furnished comply regulation fd el paso corporation exhibit list december 31 2002 exhibit identified filed part report exhibits incorporated reference prior filing designated asterisk exhibits designated incorporated herein reference prior filing indicated exhibits designated constitute management contract compensatory plan arrangement required filed exhibit report pursuant item 14c form 10k undertaking hereby undertake pursuant regulation sk item 601b paragraph 4iii furnish securities exchange commission upon request constituent instruments defining rights holders longterm debt consolidated subsidiaries filed herewith reason total amount securities authorized instruments exceed 10 percent total consolidated assets signatures pursuant requirements section 13 15d securities exchange act 1934 amended el paso corporation duly caused report signed behalf undersigned thereunto duly authorized 31st day march 2003 el paso corporation registrant ronald l kuehn jr ronald l kuehn jr chairman board chief executive officer pursuant requirements securities exchange act 1934 amended report signed following persons behalf el paso corporation capacities dates indicated certification ronald l kuehn jr certify 1 reviewed annual report form 10k el paso corporation 2 based knowledge annual report contain untrue statement material fact omit state material fact necessary make statements made light circumstances statements made misleading respect period covered annual report 3 based knowledge financial statements financial information included annual report fairly present material respects financial condition results operations cash flows registrant periods presented annual report 4 registrants certifying officers responsible establishing maintaining disclosure controls procedures defined exchange act rules 13a14 15d14 registrant designed disclosure controls procedures ensure material information relating registrant including consolidated subsidiaries made known us others within entities particularly period annual report prepared b evaluated effectiveness registrants disclosure controls procedures date within 90 days prior filing date annual report evaluation date c presented annual report conclusions effectiveness disclosure controls procedures based evaluation date 5 registrants certifying officers disclosed based recent evaluation registrants auditors audit committee registrants board directors persons performing equivalent function significant deficiencies design operation internal controls could adversely affect registrants ability record process summarize report financial data identified registrants auditors material weaknesses internal controls b fraud whether material involves management employees significant role registrants internal controls 6 registrants certifying officers indicated annual report whether significant changes internal controls factors could significantly affect internal controls subsequent date recent evaluation including corrective actions regard significant deficiencies material weaknesses ronald l kuehn jr ronald l kuehn jr chairman board chief executive officer principal executive officer el paso corporation date march 31 2003 certification dwight scott certify 1 reviewed annual report form 10k el paso corporation 2 based knowledge annual report contain untrue statement material fact omit state material fact necessary make statements made light circumstances statements made misleading respect period covered annual report 3 based knowledge financial statements financial information included annual report fairly present material respects financial condition results operations cash flows registrant periods presented annual report 4 registrants certifying officers responsible establishing maintaining disclosure controls procedures defined exchange act rules 13a14 15d14 registrant designed disclosure controls procedures ensure material information relating registrant including consolidated subsidiaries made known us others within entities particularly period annual report prepared b evaluated effectiveness registrants disclosure controls procedures date within 90 days prior filing date annual report evaluation date c presented annual report conclusions effectiveness disclosure controls procedures based evaluation date 5 registrants certifying officers disclosed based recent evaluation registrants auditors audit committee registrants board directors persons performing equivalent function significant deficiencies design operation internal controls could adversely affect registrants ability record process summarize report financial data identified registrants auditors material weaknesses internal controls b fraud whether material involves management employees significant role registrants internal controls 6 registrants certifying officers indicated annual report whether significant changes internal controls factors could significantly affect internal controls subsequent date recent evaluation including corrective actions regard significant deficiencies material weaknesses dwight scott dwight scott executive vice president chief financial officer principal financial officer el paso corporation date march 31 2003 exhibit index exhibit identified filed part report exhibits incorporated reference prior filing designated asterisk exhibits designated incorporated herein reference prior filing indicated exhibits designated constitute management contract compensatory plan arrangement required filed exhibit report pursuant item 14c form 10k undertaking hereby undertake pursuant regulation sk item 601b paragraph 4iii furnish securities exchange commission upon request constituent instruments defining rights holders longterm debt consolidated subsidiaries filed herewith reason total amount securities authorized instruments exceed 10 percent total consolidated assetsitem 15 exhibits financial statement schedules reports form 8k following documents filed part report 1 financial statements following consolidated financial statements included part ii item 8 report b reports form 8k also furnished information sec item 9 item 701 item 12 item 202 current reports form 8k current reports form 8k considered filed purposes section 18 securities exchange act 1934 subject liabilities section gulfterra energy partners lp subsidiaries consolidated financial statements report independent auditors december 31 2003 gulfterra energy partners lp subsidiaries consolidated statements income thousands except per unit amounts see accompanying notes gulfterra energy partners lp subsidiaries consolidated statements income continued thousands except per unit amounts see accompanying notes gulfterra energy partners lp subsidiaries consolidated balance sheets thousands see accompanying notes gulfterra energy partners lp subsidiaries consolidated statements cash flows thousands gulfterra energy partners lp subsidiaries consolidated statements cash flows continued thousands see accompanying notes gulfterra energy partners lp subsidiaries consolidated statements partners capital thousands 1 october 2003 redeemed remaining outstanding series b preference units 156 million 2 issued 10937500 series c units el paso corporation value 350 million connection acquisition san juan assets discussion new class units included note 8 3 gulfterra energy company llc sole general partner owned 50 percent subsidiary el paso corporation 50 percent subsidiary enterprise products partners lp 4 income allocation general partner includes incentive distributions one percent ownership interest see accompanying notes gulfterra energy partners lp subsidiaries consolidated statements comprehensive income changes accumulated comprehensive income loss thousands comprehensive income accumulated comprehensive income loss see accompanying notes gulfterra energy partners lp subsidiaries notes consolidated financial statements 1 summary significant accounting policies organization publicly held delaware master limited partnership established 1993 purpose providing midstream energy services including gathering transportation fractionation storage related activities producers natural gas oil onshore offshore gulf mexico december 31 2003 58404649 common units outstanding representing limited partner interests 10937500 series c units outstanding representing nonvoting limited partner interests date public owned 48020404 common units 822 percent outstanding common units el paso corporation subsidiaries owned 10384245 common units 178 percent outstanding common units series c units 50 percent general partner owns one percent general partner interest may 2003 changed name gulfterra energy partners lp el paso energy partners lp reorganized general partner connection name change also changed names several subsidiaries may 2003 including following listed table sole general partner gulfterra energy company llc recentlyformed delaware limited liability company owned 50 percent subsidiary el paso corporation 50 percent subsidiary enterprise publicly traded master limited partnership el paso corporation subsidiaries owned 100 percent general partner october 2003 goldman sachs acquired 99 percent interest general partner december 2003 el paso corporation reacquired goldman sachs interest general partner sold 50 percent interest general partner subsidiary enterprise december 15 2003 along enterprise el paso corporation announced executed definitive agreements merge enterprise gulfterra form one largest publicly traded mlps enterprise continuing entity general partner combined partnership jointly owned affiliates el paso corporation privatelyheld enterprise products company owning 50percent interest combined partnership retain name enterprise products partners lp serve largest producing basins natural gas crude oil ngls us including gulf mexico rocky mountains san juan basin permian basin south texas east texas midcontinent louisiana gulf coast basins connections thirdparty pipelines canadas western sedimentary basin partnership also serve largest consuming regions natural gas crude oil ngls us gulf coast basis presentation principles consolidation consolidated financial statements include accounts majorityowned controlled subsidiaries elimination significant intercompany accounts transactions account investments companies ability exert significant influence control operating financial policies using equity method accounting prior may 2001 general partners approximate one percent nonmanaging interest twelve subsidiaries represented minority interest gulfterra energy partners lp subsidiaries notes consolidated financial statements continued consolidated financial statements may 2001 purchased general partners one percent nonmanaging ownership interest twelve subsidiaries 8 million result acquisition subsidiaries equity investees whollyowned us part 2003 2002 third parties minority ownership interests matagorda island area gathering system miags arizona gas llc assets liabilities operations entities included consolidated financial statements account third party ownership interest minority interest consolidated balance sheets minority interest income expense consolidated statements income october 2003 purchased remaining 17 percent interest miags result longer recognize third party ownership interest miags minority interests consolidated balance sheets consolidated statements income consolidated financial statements prior periods include reclassifications made conform current year presentation reclassifications impact reported net income partners capital reflected results operations prince assets disposition discontinued operations years ended december 31 2002 2001 see note 2 discussion prince assets disposition use estimates preparation financial statements conformity accounting principles generally accepted united states requires us make estimates assumptions affect reported amounts assets liabilities revenues expenses disclosure contingent assets liabilities exist date financial statements believe estimates appropriate actual results often differ estimates accounting regulated operations hios interstate natural gas system petal storage facility subject jurisdiction ferc accordance natural gas act 1938 natural gas policy act 1978 system operates separate ferc approved tariffs establish rates terms conditions system provides services customers businesses subject regulations accounting requirements ferc followed accounting requirements statement financial accounting standards sfas 71 accounting effects certain types regulation may differ accounting requirements nonregulated entities transactions recorded differently result regulatory accounting requirements include capitalization equity return component regulated capital projects provisions sfas 143 accounting asset retirement obligations adopted january 1 2003 cost associated retirement longlived assets regulated entities accounted sfas 71 classified regulatory liability instead component property plant equipment result reclassified 136 million property plant equipment regulatory liability december 31 2003 balance included noncurrent liabilities consolidated balance sheet prior january 2003 item reflected accumulated depreciation depletion amortization balance item december 31 2002 129 million accounting method followed required allowed regulatory authority ratemaking purposes method conforms generally accepted accounting principle gaap matching costs revenues apply gulfterra energy partners lp subsidiaries notes consolidated financial statements continued cash equivalents consider shortterm investments little risk change value changes interest rates purchased original maturity less three months cash equivalents allowance doubtful accounts established allowance losses accounts believe uncollectible review collectibility regularly adjust allowance necessary primarily specific identification method december 31 2003 2002 allowance 40 million 25 million natural gas imbalances natural gas imbalances result differences gas volumes received delivered customers arise customer delivers less gas pipelines take imbalances settled kind tracking mechanism negotiated cashouts parties subject cashout procedure valued prices representing estimated value imbalances upon settlement estimate value imbalances prices representing estimated value imbalances upon settlement changes natural gas prices may impact valuation value imbalances based current monthend spot prices likely would purchase receive natural gas point time settle imbalance natural gas imbalances reflected accounts receivable accounts payable appropriate accompanying consolidated balance sheets imbalance receivables imbalance payables follows december 31 thousands property plant equipment record property plant equipment original cost construction upon acquisition fair value asset acquired additionally capitalize direct costs labor materials indirect costs overhead interest regulated businesses apply provisions sfas 71 equity return component also capitalize major units property replacements improvements expense minor items including repair maintenance costs addition reduce property plant equipment balance amounts receive form contributions aid construction regulated interstate system storage facility use composite group method depreciate regulated property plant equipment method assets similar lives characteristics grouped depreciated one asset apply depreciation rate approved tariff total cost group net book value equals estimated salvage value currently depreciation rates regulated interstate system storage facility vary 1 20 percent using rates remaining depreciable lives assets range 1 39 years gulfterra energy partners lp subsidiaries notes consolidated financial statements continued nonregulated gathering pipelines platforms related facilities processing facilities equipment storage facilities equipment depreciated straightline basis estimated useful lives follows account oil natural gas exploration production activities using successful efforts method accounting method costs successful exploratory wells developmental wells acquisitions mineral leasehold interests capitalized production exploratory dry hole exploration costs including geological geophysical costs delay rentals expensed incurred unproved properties assessed periodically impairment value recognized currently depreciation depletion amortization expense depreciation depletion amortization capitalized costs producing oil natural gas properties consisting principally tangible intangible costs incurred developing property costs productive leasehold interests computed unitofproduction method unitofproduction rates based annual estimates remaining proved developed reserves proved reserves appropriate property estimated dismantlement restoration abandonment costs estimated residual salvage values taken account determining depreciation provisions gathering pipelines platforms related facilities oil natural gas properties december 31 2002 accrued abandonment costs 246 million 64 million related offshore wells discussed adopted sfas 143 accounting asset retirement obligations january 1 2003 amounts accrued capitalized adjusted conform provisions statement retirements sales disposals assets recorded eliminating related costs accumulated depreciation depletion amortization disposed assets resulting gain loss reflected income accounting asset retirement obligations january 1 2003 adopted sfas 143 provisions statement relate primarily obligations plug abandoned offshore wells constitute part nonsegment assets upon adoption sfas 143 recorded 74 million net increase property plant equipment relating offshore wells representing noncurrent retirement assets ii 57 million increase noncurrent liabilities representing retirement obligations iii 17 million increase income cumulative effect accounting change retirement asset depreciated remaining useful life longterm asset retirement liability associated ongoing expense recognized interest component liability due changes value retirement liability result passage time reflect component depreciation expense income statement obligations plug abandon wells cannot estimate costs retire remove assets used business believe assets definite lives legal obligation abandon dismantle assets believe lives assets underlying reserves associated assets cannot estimated therefore aside liability associated plugging abandonment offshore wells recorded liabilities relating assets gulfterra energy partners lp subsidiaries notes consolidated financial statements continued pro forma income continuing operations amounts per common unit years ended december 31 2002 2001 assuming provisions sfas 143 adopted prior earliest period presented shown pro forma amount asset retirement obligations december 31 2002 2001 assuming asset retirement obligations provided sfas 143 recorded prior earliest period presented 57 million 53 million asset retirement obligation december 31 2003 shown 1 abandonment work performed year ended december 31 2003 goodwill intangible assets adopted provisions sfas 142 goodwill intangible assets january 1 2002 except goodwill intangible assets acquired june 30 2001 adopted provisions immediately accordingly record identifiable intangible assets acquire individually group assets fair value upon acquisition identifiable intangible assets finite useful lives amortized expense estimated useful life asset identifiable intangible assets indefinite useful lives goodwill evaluated annually impairment comparison carrying amounts fair value individual assets recognize impairment loss income amount carrying value identifiable intangible asset goodwill exceeds fair value specific assets december 31 2003 2002 goodwill described december 31 2003 2002 carrying amount equity investment poseidon exceeded underlying equity net assets approximately 30 million adoption sfas 142 january 1 2002 longer amortize excess amount test impairment event occurs indicates may loss value least annually prior january 1 2002 amortized excess amount using straight line method approximately 30 years excess amount reflected accompanying consolidated balance sheets investments unconsolidated affiliates adoption statement material impact financial position results operations part acquisition epn holding assets san juan assets obtained intangible assets representing contractual rights dedication transportation agreements producers december 31 2003 2002 value intangible assets approximately 34 million gulfterra energy partners lp subsidiaries notes consolidated financial statements continued 40 million reflected accompanying consolidated balance sheets intangible assets amortize intangible assets acquired epn holding asset acquisition expense using unitsofproduction method expected lives reserves ranging 26 45 years amortize intangible assets acquired san juan asset acquisition life contracts approximately 4 years impairment disposal longlived assets apply provisions sfas 144 accounting impairment disposal longlived assets account impairment disposal longlived assets accordingly evaluate recoverability longlived assets adverse events changes circumstances indicate carrying value asset group assets may recoverable determine recoverability asset group assets estimating undiscounted cash flows expected result use eventual disposition asset group assets lowest level separate cash flows measured total undiscounted cash flows less carrying amount assets estimate fair value asset group assets recognize amount carrying value exceeds fair value less cost sell impairment loss income operations period impairment determined additionally required sfas 144 classify longlived assets disposed sale eg abandonment exchange distribution held used item abandoned exchanged distributed evaluate assets disposed sale impairment recognize loss excess carrying value fair value longlived assets disposed sale recognition meeting specific criteria classified held sale measured lower cost fair value less cost sell report results operations component classified held sale including gain loss periods occur upon adoption sfas 144 reclassified losses sale longlived assets 04 million 114 million years ended december 31 2002 2001 operating income conform provisions sfas 144 also reclassify asset assets either held sale discontinued operations depending whether independently determinable cash flow whether continuing involvement capitalization interest financing costs capitalized connection construction drilling activities part cost asset amortized related assets estimated useful life debt issue costs debt issue costs capitalized amortized life related indebtedness using effective interest method unamortized debt issue costs expensed time related indebtedness repaid terminated december 31 2003 2002 unamortized amount debt issue costs included noncurrent assets 292 million 326 million amortization debt issue costs years ended december 31 2003 2002 2001 75 million 44 million 36 million included interest debt expense consolidated statements income revenue recognition cost natural gas products revenue gathering transportation hydrocarbons recognized upon receipt hydrocarbons pipeline systems revenue commodity sales recognized upon delivery commodity storage revenues platform access revenues consist primarily fixed fees capacity reservation transportation contracts viosca knoll system indian basin lateral also contain fixed fee reserve transportation capacity fixed fees recognized month gulfterra energy partners lp subsidiaries notes consolidated financial statements continued capacity reserved customer regardless much capacity actually used revenue processing services treating services fractionation services recognized period services provided interruptible revenues natural gas storage generated providing excess storage capacity variable nature recognized service provided revenues generally recorded services provided products delivered prior 2002 cost natural gas consisted primarily natural gas purchased gulfterra alabama intrastate resale result acquisition epn holding assets san juan assets incurring additional costs related system imbalances purchase natural gas part producer services activities convenience producers may purchase natural gas wellhead index price less amount compensates us gathering services sell gas open market points system index price reflect sales revenues related purchases cost natural gas accompanying consolidated statements income typhoon oil pipelines transportation agreement bhp chevron texaco provides typhoon oil purchase oil produced inlet pipeline index price less amount compensates typhoon oil transportation services outlet pipeline typhoon oil resells oil back producers index price beginning 2003 record revenue buysell transactions upon delivery oil based net amount billed producers acquired typhoon oil pipeline november 2002 year ended december 31 2002 recorded revenue based gross amount billed producers year ended december 31 2002 reclassified 105 million cost natural gas products revenue conform 2003 presentation reclassification effect operating income net income partners capital july 1 2003 hios implemented new rates subject refund established reserve estimate refund obligation continue review expected refund obligation rate case moves hearing process may increase decrease amounts reserved refund obligation expectation changes environmental costs expense capitalize expenditures ongoing compliance environmental regulations relate past current operations appropriate expense amounts clean existing environmental contamination caused past operations benefit future periods record liabilities environmental assessments indicate remediation efforts probable costs reasonably estimated estimates liabilities based currently available facts existing technology presently enacted laws regulations taking consideration likely effects inflation societal economic factors include estimates associated legal costs amounts also consider prior experience remediating contaminated sites companies cleanup experience data released environmental protection agency epa organizations estimates subject revision future periods based actual costs new circumstances included consolidated balance sheets noncurrent liabilities undiscounted amounts accounting price risk management activities business activities expose us variety risks including commodity price risk interest rate risk time engage price risk management activities nontrading purposes manage market risks associated commodities purchase sell interest rates variable rate debt price risk management activities involve use variety derivative financial instruments including exchangetraded future contracts involve cash settlement gulfterra energy partners lp subsidiaries notes consolidated financial statements continued forward contracts involve cash settlements physical delivery commodity swap contracts require payments receipts counterparties based difference fixed variable price two variable prices commodity variable rate debt instrument account derivative instruments consolidated financial statements sfas 133 accounting derivative instruments hedging activities record derivatives consolidated balance sheets fair value assets liabilities classify current noncurrent based upon anticipated settlement date instruments entered hedge risk qualify hedges apply provisions sfas 133 accounting treatment depends instruments intended use designated addition designation hedge must effective changes value derivative resulting cash flows must substantially offset changes value cash flows item hedged formally document relationships hedging instruments hedged items well risk management objectives strategies undertaking various hedge transactions hedging instruments linked hedged asset liability firm commitment forecasted transaction also assess inception hedge ongoing basis whether derivatives used hedging transactions highly effective offsetting changes cash flows fair values hedged items discontinue hedge accounting prospectively determine derivative highly effective hedge decide discontinue hedging relationship 2003 2002 2001 entered cash flow hedges qualify hedge accounting sfas 133 treatment changes fair value derivative designated cash flow hedge recorded accumulated comprehensive income portion change value derivative effective ineffective portion derivative recorded earnings current period classification income statement ineffective portion based income classification item hedged date hedged transaction reclassify gains losses resulting sale maturity extinguishment termination derivative instruments designated hedges accumulated comprehensive income operating income interest expense appropriate consolidated statements income classify cash inflows outflows associated settlement derivative transactions cash flows operating activities consolidated statements cash flows also record ownership percentage changes fair value derivatives investments unconsolidated affiliates accumulated comprehensive income may also purchase sell instruments economically hedge price fluctuations commodity markets instruments documented hedges due shortterm nature qualify provisions sfas 133 hedge accounting due terms instruments derivatives qualify documented changes fair value recorded earnings current period august 2002 entered derivative financial instrument hedge exposure 2003 changes natural gas prices san juan basin anticipation acquisition san juan assets august 2002 acquisition date november 27 2002 accounted derivative current earnings since qualify hedge accounting sfas 133 beginning acquisition date november 2002 designated derivative cash flow hedge accounting sfas 133 normal course business may enter contracts qualify derivatives provisions sfas 133 result evaluate contracts determine whether derivative gulfterra energy partners lp subsidiaries notes consolidated financial statements continued accounting appropriate contracts meet criteria derivative qualify normal purchases normal sales terms defined sfas 133 may excluded sfas 133 treatment april 2003 fasb issued sfas 149 amendment statement 133 derivative instruments hedging activities statement amends sfas 133 incorporate several interpretations derivatives implementation group dig also makes several minor modifications definition derivative defined sfas 133 sfas 149 effective contracts entered modified june 30 2003 initial financial statement impact adopting standard although fasb dig continue deliberate application standard certain derivative contracts may impact financial statements future income taxes december 31 2003 neither subsidiaries taxable entities however taxable income loss resulting operations ultimately included federal state income tax returns general limited partners individual partners different investment bases depending upon timing price acquisition partnership units partners tax accounting partially dependent upon tax position may differ accounting followed consolidated financial statements accordingly could significant differences individual partners tax basis share net assets reported consolidated financial statements access information individual partners tax attributes aggregate tax bases cannot readily determined income loss per common unit basic income loss per common unit excludes dilution computed dividing net income loss attributable common unitholders weighted average number common units outstanding period diluted income loss per common unit reflects potential dilution computed dividing net income loss attributable common unitholders weighted average number common units outstanding period increased number additional common units would outstanding potentially dilutive units issued basic income loss per common unit diluted income loss per common unit years ended december 31 2002 2001 number potentially dilutive units small cause diluted earnings per unit different basic earnings per unit comprehensive income comprehensive income determined based net income loss adjusted changes accumulated comprehensive income loss cash flow hedging activities associated gulfterra alabama intrastate operations indian basin processing plant san juan assets unconsolidated affiliate poseidon oil pipeline company llc following table presents allocation accumulated comprehensive loss december 31 gulfterra energy partners lp subsidiaries notes consolidated financial statements continued accounting stockbased compensation use intrinsic value method established accounting principles board opinion apb 25 accounting stock issued employees value unit options issued individuals general partners current board directors grants made prior el paso corporations acquisition general partner august 1998 omnibus plan director plan years ending december 31 2003 2002 2001 cost stockbased compensation impact net income options granted exercise price equal market value underlying common stock date grant use provisions sfas 123 accounting stockbased compensation account stockbased compensation programs december 2002 fasb issued sfas 148 accounting stockbased compensation transition disclosure statement amends sfas 123 provide alternative methods transition voluntary change fair value method accounting stockbased employee compensation addition statement amends disclosure requirements sfas 123 require prominent disclosures annual interim financial statements methods accounting stockbased employee compensation effect method used reported results statement effective fiscal years ending december 15 2002 decided continue use apb 25 value stockbased compensation issued individuals general partners current board directors grants made prior el paso corporations acquisition general partner august 1998 include data providing pro forma income effect using fair value method required sfas 148 continue use provisions sfas 123 account stockbased compensation programs compensation expense related plans determined applying fair value method sfas 123 net income allocated common unitholders net income per common unit would approximated pro forma amounts effects applying sfas 123 pro forma disclosure may indicative future amounts accounting debt extinguishments january 2003 adopted sfas 145 rescission fasb statements 4 44 64 amendment fasb statement 13 technical corrections accordingly evaluate nature gulfterra energy partners lp subsidiaries notes consolidated financial statements continued debt extinguishments determine whether report gain loss resulting early extinguishment debt extraordinary item component income continuing operations accounting costs associated exit disposal activities january 2003 adopted sfas 146 accounting costs associated exit disposal activities statement impacts exit disposal activities initiate january 1 2003 recognize costs associated exit disposal activities incurred rather commit exit disposal plan adoption pronouncement effect financial position results operations accounting guarantees accordance provisions financial accounting standards board fasb interpretation fin 45 guarantors accounting disclosure requirements guarantees including indirect guarantees indebtedness others record liability fair value otherwise disclose certain guarantees issued december 31 2002 contractually require us make payments guaranteed party based occurrence certain events entered material guarantees would require recognition fin 45 accounting certain financial instruments characteristics liabilities equity may 2003 fasb issued sfas 150 accounting certain financial instruments characteristics liabilities equity statement provides guidance classification financial instruments equity liabilities equity provisions sfas 150 effective financial instruments entered modified may 31 2003 otherwise effective beginning first interim period beginning july 1 2003 adopted provisions sfas 150 july 1 2003 adoption material impact financial statements new accounting pronouncements issued yet adopted consolidation variable interest entities january 2003 fasb issued fin 46 consolidation variable interest entities interpretation arb 51 interpretation defines variable interest entity vie legal entity whose equity owners sufficient equity risk andor controlling financial interest entity standard requires company consolidate vie allocated majority entitys losses andor returns including fees paid entity december 2003 fasb issued fin 46r amended fin 46 extend effective date first quarter 2004 types entities except special purpose entities spes addition fin 46r also limited scope fin 46 exclude certain joint ventures entities meet characteristics businesses spes defined fin nos 46 46r evaluated joint ventures unconsolidated subsidiaries contractual arrangements could considered variable interests variable interest entities created february 1 2003 determined significant effect reported results financial position adopt provisions fin 46r first quarter 2004 gulfterra energy partners lp subsidiaries notes consolidated financial statements continued 2 acquisitions dispositions merger enterprise december 15 2003 along enterprise el paso corporation announced executed definitive agreements merge enterprise gulfterra form one largest publicly traded mlps general partner combined partnership jointly owned affiliates el paso corporation privatelyheld enterprise products company owning 50percent interest definitive agreements include three transactions two affect us first transaction effects us occurred signing merger agreement wholly owned subsidiary enterprise purchased 50 percent limitedvoting interest general partner interest entitles enterprise half cash distributed general partner allow enterprise elect general partners directors otherwise generally participate general partners management business second transaction affects us occur merger date closing merger outstanding gulfterra common unit owned enterprise convert 181 enterprise common units gulfterra become whollyowned subsidiary enterprise el paso corporation acquire 50 percent interest enterprises general partner including right elect half directors enterprises general partner closing merger subject satisfaction specified conditions including obtaining clearance hartscottrodino antitrust improvement acts approval unitholders enterprises unitholders completion merger expected occur second half 2004 merger agreement enterprise limits ability raise additional capital prior closing merger without enterprises approval addition closing merger change control thus default credit facility either repay amend facility prior closing addition merger closing constitute change control indentures required offer repurchase outstanding senior subordinated notes possibly senior notes 101 percent principal amount closing coordination enterprise evaluating alternative financing plans preparation close merger enterprise agree date merger closing receipt necessary approvals intend close appropriate financing place merger agreement terminated 1 business transaction us third party conflicts merger proposed certain conditions met 2 materially willfully violated agreement solicit transactions conflict merger required pay enterprise termination fee 112 million merger agreement terminated unitholders approve merger either 1 possible business transaction involving us involving enterprise conflicting merger publicly proposed board directors publicly timely reaffirmed recommendations enterprise merger 2 possible business transaction publicly announced required pay enterprise termination fee 15 million enterprise subject similar termination fee requirements exchange el paso corporation connection november 2002 san juan assets acquisition el paso corporation retained obligation repurchase chaco plant us 77 million october 2021 october 2003 released el paso corporation obligation exchange el paso corporation contributing specified communication assets rights us communication assets received used operation pipeline systems prior october 2003 exchange access assets general gulfterra energy partners lp subsidiaries notes consolidated financial statements continued administrative services agreement el paso corporation recorded communication assets el paso corporations book value 233 million offset partners capital result october 2003 exchange revised estimate depreciable life chaco plant 19 30 years estimated remaining useful life chaco plant depreciation expense decrease approximately 05 million 23 million quarter annual basis cameron highway oil pipeline company refer note 3 discussion related sale 50 percent interest cameron highway oil pipeline san juan assets november 2002 acquired subsidiaries el paso corporation interests assets collectively refer san juan assets consist following 100 percent el paso field services san juan gathering processing businesses include natural gas gathering system related compression facilities rattlesnake treating plant 50percent equity interest coyote gas treating llc owns coyote natural gas treating facility remaining interests chaco cryogenic natural gas processing plant already located san juan basin northwest new mexico southwestern colorado 100 percent typhoon oil pipeline assets located deepwater trend area gulf mexico typhoon oil placed service july 2001 provides transportation oil produced typhoon field delivery platform green canyon block 19 onshore access various oil pipelines 100 percent typhoon gas pipeline placed service august 2001 typhoon gas also located deepwater trend area gulf mexico pipeline gathers natural gas typhoon field redelivery el paso corporations anr patterson system 100 percent coastal liquids partners ngl business consisting integrated set ngl assets stretch mexico border near mcallen texas houston texas business includes fractionation facility near houston texas truckloading terminal near mcallen texas leased underground ngl storage facilities purchased san juan assets 782 million 764 million adjustments capital expenditures actual working capital acquired 2003 total purchase price net assets acquired decreased 24 million due postclosing purchase price adjustments related natural gas imbalances ngl inkind reserves well loss reserves financed purchase assets net proceeds offering 200 million 10 58 senior subordinated notes due 2012 borrowings 2375 million senior secured acquisition term loan issuance el paso corporation 10937500 series c units valued 32 per unit 350 million currently available funds acquired san juan assets strategically located active supply development areas supported longterm contracts provide us growing reliable cash flows consistent stated growth strategy connection acquisition entered agreement el paso corporation el paso corporation would required subject specified conditions repurchase chaco plant us 77 million october 2021 time would right lease plant period 10 years option renew lease annually thereafter october 2003 gulfterra energy partners lp subsidiaries notes consolidated financial statements continued released el paso corporation repurchase obligation exchange el paso corporation contributing communication assets us result acquisition san juan assets financial results operation chaco plant significantly different results prior purchase following ways longer receive fixed fee revenue 0134dth natural gas processed rather majority customers receive processing fee inkind portion ngl produced natural gas processed sell ngl accordingly processing revenues affected changes price ngl longer receive revenue leasing chaco plant el paso field services longer recognize amortization expense relating investment processing agreement terminated upon completing acquisition decrease amortization expense offset additional depreciation expense associated acquired assets accordance procedures evaluating valuing material acquisitions el paso corporation audit conflicts committee engaged independent financial advisors separate financial advisors delivered fairness opinions acquisition san juan assets issuance series c units based opinions audit conflicts committee full board approved transactions following table summarizes allocation fair values assets acquired liabilities assumed november 27 2002 allocation among assets acquired based results independent thirdparty appraisal acquired intangible assets represent contractual rights obtained dedication transportation agreements producers amortizing expense life contracts approximately 4 years recorded adjustments purchase price approximately 18 million primarily capital expenditures actual working capital acquired consolidated financial statements include results operations san juan assets november 27 2002 purchase date included assets operating results el paso field services san juan gathering processing businesses typhoon gas pipeline natural gas pipelines plants segment assets operating results typhoon oil pipeline coastal liquids partners ngl business oil ngl logistics segment purchase date following gulfterra energy partners lp subsidiaries notes consolidated financial statements continued selected unaudited pro forma financial information presents consolidated operating results years ended december 31 2002 2001 acquired san juan assets january 1 2001 unaudited pro forma financial information presented necessarily indicative results operations might realized transaction completed beginning earliest period presented necessarily indicate consolidated operating results future period epn holding assets april 2002 acquired series related transactions subsidiaries el paso corporation following midstream assets located texas new mexico collectively refer purposes financial statements epn holding assets waha natural gas gathering treating system carlsbad natural gas gathering system generally located permian basin region texas new mexico 50 percent undivided interest channel pipeline system intrastate natural gas transmission system located along gulf coast texas tpc offshore pipeline system collection natural gas gathering transmission assets located offshore matagorda bay texas including oyster lake milsp condensate separation stabilization facilities undivided interests smaller pipelines gulfterra texas pipeline lp owned among assets gulfterra texas intrastate pipeline system ii tgp natural gas lateral pipelines iii leased natural gas storage facilities located wharton county texas generally known wilson storage facility iv 80 percent undivided interest east texas 36 inch pipeline v 50 percent undivided interest west texas 30 inch pipeline vi 50 percent undivided interest north texas 36 inch pipeline vii mcmullen county natural gas gathering system viii hidalgo county natural gas gathering system ix 22 percent undivided interest bethelhoward pipeline x 75 percent undivided interest longhorn pipeline el paso hub services llc owned certain contract rights parcels real property located texas 100 percent outstanding joint venture interest warwink gathering treating company owned among assets warwink natural gas gathering system located permian basin region texas new mexico conjunction acquisition assets obtained another affiliate el paso corporation equity interest el paso indian basin lp owned 423 percent undivided nonoperating interest indian basin natural gas processing plant treating facility located southeastern new mexico price risk management activities associated plant acquired epn holding assets provide us significant new source cash flow greater diversification midstream asset base provide new long term internal growth opportunities texas intrastate market purchased epn holding assets 750 million adjusted assumption gulfterra energy partners lp subsidiaries notes consolidated financial statements continued 15 million net working capital obligations related natural gas imbalances resulting net consideration 735 million comprised following 420 million cash 119 million assumed shortterm indebtedness payable el paso corporation subsequently repaid 6 million common units 190 million assets comprised prince tlp nine percent overriding royalty interest prince field see discussion 2003 purchase price net assets acquired increased 175 million due postclosing purchase price adjustments related primarily reduction natural gas imbalance payables assumed transaction entered limited recourse credit agreement syndicate commercial banks finance substantially cash consideration associated transaction see note 6 additional discussion regarding epn holding term credit facility following table summarizes allocation fair values assets acquired liabilities assumed april 8 2002 allocation among assets acquired based results independent thirdparty appraisal acquired intangible assets represent contractual rights obtained dedication transportation agreements producers amortize expense using unitsofproduction method expected lives underlying reserves ranging 26 45 years additionally assumed environmental liabilities 211 million estimated environmental remediation costs associated gulfterra texas intrastate pipeline assets discussed note 11 consolidated financial statements include results operations epn holding assets april 8 2002 purchase date included assets operating results waha carlsbad warwink natural gas gathering systems channel tpc offshore pipeline systems gulfterra texas pipeline assets excluding wilson storage facility natural gas pipelines plants segment 423 percent ownership interest assets operating results indian basin plant included oil ngl logistics segment wilson storage facility assets operating results included natural gas storage segment following selected unaudited pro forma information depicts gulfterra energy partners lp subsidiaries notes consolidated financial statements continued consolidated results operations years ended december 31 2002 2001 acquired epn holding assets january 1 2001 unaudited pro forma financial information presented necessarily indicative results operations might realized transaction completed beginning earliest period presented necessarily indicate consolidated operating results future period prince assets connection april 2002 acquisition epn holding assets el paso corporation sold prince tension leg platform tlp nine percent overriding royalty interest prince field subsidiaries el paso corporation results operations assets accounted discontinued operations excluded continuing operations periods consolidated statements income accordingly segment results note 15 reflect neither results operations prince assets related net assets held sale prince tlp previously included platform services segment related royalty interest included nonsegment activity included income discontinued operations years ended december 31 2002 2001 revenues 78 million 88 million attributable disposed assets april 2002 sold prince assets 190 million recognized gain sale 04 million 2002 conjunction transaction repaid related outstanding 95 million principal balance argo term loan deepwater holdings llc chaco transaction october 2001 acquired remaining 50 percent interest already deepwater holdings approximately 81 million consisting 26 million cash 55 million assumed indebtedness acquisition date also repaid deepwater holdings 110 million indebtedness hios east breaks became indirect whollyowned assets transaction separate transaction acquired interests title holder interests chaco cryogenic natural gas processing plant 1985 million total purchase price composed payment 77 million acquire plant bank group provided financing construction facility payment 1215 million el paso field services connection execution 20year feebased processing agreement relating processing capacity chaco plant dedication natural gas gathered el paso field services chaco plant terms processing agreement received fixed fee dekatherm natural gas processed chaco plant bore costs associated plants ownership operations el paso field services personnel continued operate plant accordance original construction financing agreements chaco plant operating lease el paso field services el paso field services right repurchase chaco plant end lease term october 2002 approximately 77 million funded transactions borrowing revolving credit facility accounted transactions purchases assigned purchase price net assets acquired based upon estimated fair value net assets acquisition date operating results associated deepwater holdings included earnings unconsolidated affiliates periods prior october 2001 included gulfterra energy partners lp subsidiaries notes consolidated financial statements continued operating results deepwater holdings chaco plant consolidated financial statements acquisition date since chaco transaction asset acquisition assigned total purchase price property plant equipment investment processing agreement since deepwater holdings transaction acquisition additional interests business providing summary information related acquisition deepwater holdings following table thousands connection acquisition san juan assets november 2002 original terms processing lease operating agreements chaco plant el paso field services terminated effect operation chaco plant resulting acquisition san juan assets discussed gtm texas formerly epn texas february 2001 acquired gtm texas subsidiary el paso corporation 133 million funded acquisition assets borrowing revolving credit facility assets include 500 miles ngl gathering transportation pipelines ngl pipeline system gathers transports unfractionated fractionated products also acquired three fractionation plants capacity approximately 96 mbblsd plants fractionate ngl ethane propane butane natural gasoline products used refineries petrochemical plants along texas gulf coast accounted acquisition purchase assigned purchase price assets acquired based upon estimated fair value assets acquisition date included operating results gtm texas consolidated financial statements acquisition date following selected unaudited pro forma information represents consolidated results operations pro forma basis year ended december 31 2001 acquired gtm texas chaco plant remaining 50 percent interest deepwater holdings january 1 2001 gulf mexico assets accordance ftc order related el paso corporations merger coastal corporation along deepwater holdings agreed sell several offshore gulf mexico assets third parties january 2001 total consideration received assets approximately 163 million consisting approximately 109 million assets sold approximately 54 million assets deepwater holdings sold offshore assets sold include interests stingray utos nautilus manta ray offshore nemo tarpon green canyon pipeline assets well interests two offshore platforms one dehydration facility recognized net losses asset sales approximately 12 million deepwater holdings recognized losses approximately 21 million share deepwater holdings losses gulfterra energy partners lp subsidiaries notes consolidated financial statements continued approximately 14 million reflected earnings unconsolidated affiliates accompanying 2001 consolidated statement income additional consideration transactions el paso corporation agreed make payments us totaling 29 million payments made quarterly installments 225 million three years beginning 2001 receive final payment 2 million first quarter 2004 additional consideration realized income approximately 25 million first quarter 2001 reflected income accompanying 2001 consolidated statement income 3 investments unconsolidated affiliates hold investments unconsolidated affiliates accounted using equity method accounting december 31 2003 carrying amount equity investments exceeded underlying equity net assets approximately 30 million included oil ngl logistics segment adoption sfas 142 january 1 2002 longer amortize excess amount refer note 1 summary significant accounting policies goodwill intangible assets summarized financial information investments follows recorded adjustments primarily differences estimated earnings reported annual report form 10k actual earnings reported unaudited financial statements unconsolidated affiliates b total earnings unconsolidated affiliates includes 898 thousand gain associated sale interest copper eagle c cameron highway oil pipeline company deepwater gateway llc development stage companies therefore operating revenues operating expenses provide operational results since formations incurred organizational expenses received interest income gulfterra energy partners lp subsidiaries notes consolidated financial statements continued cameron highway june 2003 formed cameron highway oil pipeline company contributed newly formed company 458 million cameron highway oil pipeline system construction project cameron highway responsible building operating pipeline scheduled completion fourth quarter 2004 entered producer agreements three major anchor producers bp exploration production company bhp billiton petroleum deepwater inc union oil company california agreements assigned assumed cameron highway producer agreements require construction 390mile cameron highway oil pipeline july 2003 sold 50 percent interest cameron highway valero energy corporation 86 million forming joint venture valero paid us approximately 70 million closing including 51 million representing 50 percent capital investment expended date pipeline project july 2003 recognized 19 million gain sale longlived assets addition valero pay us 5 million system completed another 11 million end 2006 expect reflect receipts additional amounts periods received gains sale longlived assets statement income connection formation cameron highway joint venture valero agreed pay proportionate share pipeline construction costs exceed cameron highways capital resources including initial equity contributions proceeds cameron highways project loan facility cameron highway oil pipeline system project expected funded 37 percent equity 169 million capital contributions us valero two cameron highway partners contributions already made 63 percent debt 325 million project loan facility consisting 225 million construction loan 100 million senior secured notes see note 6 additional discussion project loan facility december 31 2003 cameron highway spent approximately 256 million 85 million constituted equity contributions us related pipeline construction stage valero obligated make additional capital contributions cameron highway extent construction costs pipeline exceed cameron highways capital resources including initial equity contributions proceeds cameron highways project loan facility deepwater gateway december 31 2003 contributed 33 million 50 percent share deepwater gateway amount satisfies initial equity funding requirement related marco polo tlp expect remaining costs associated marco polo tlp funded 155 million project finance loan deepwater gateways members contingent equity obligations share 14 million project finance loan mature july 2004 unless construction completed time deepwater gateway meets specified conditions case project finance loan convert term loan final maturity date july 2009 loan agreement requires deepwater gateway maintain debt service reserve equal six months interest debt service reserve amounts agreed upon 667 percent majority interest deepwater gateways members deepwater gateway project finance loan either repaid converted term loan distribute available cash members quarterly deepwater gateway currently generating income cash flow deepwater gateway managed management committee consisting representative members front runner oil pipeline september 2003 announced poseidon 36 percent owned joint venture entered agreement purchase sale crude oil front runner field poseidon construct operate 28 million project connect front runner platform poseidons existing system ship shoal block 332 new 36mile 14inch pipeline expected operational third quarter 2004 capacity 65 mbblsd poseidon expects fund front runners capital expenditures operating cash flow revolving credit gulfterra energy partners lp subsidiaries notes consolidated financial statements continued facility expect receive distributions poseidon front runner oil pipeline completed acquired interest coyote gas treating llc november 2002 part san juan assets acquisition b june 2002 formed deepwater gateway llc 5050 joint venture cal dive international inc construct install marco polo tlp also august 2002 deepwater gateway obtained project finance loan fund substantial portion cost construct marco polo tlp discussion project loan see note 6 financing transactions deepwater gateway llc development stage company therefore operating revenues operating expenses provide operational results since deepwater gateways formation 2002 incurred organizational expenses received interest income c recorded adjustments primarily differences estimated year end earnings reported annual report form 10k actual earnings recorded audited annual reports unconsolidated affiliates adjustment poseidon primarily represents receipt proceeds favorable litigation related january 2000 pipeline rupture gulfterra energy partners lp subsidiaries notes consolidated financial statements continued january 2001 deepwater holdings sold stingray west cameron subsidiaries deepwater holdings sold interest utos subsidiary april 2001 october 2001 acquired remaining 50 percent deepwater holdings result transaction acquisition date deepwater holdings consolidated financial statements information presented deepwater holdings equity investment october 18 2001 b divested investments contains manta ray offshore gathering company llc nautilus pipeline company llc january 2001 sold 2567 percent interest manta ray offshore 2567 percent interest nautilus c october 2001 company processed gas deepwater holdings stingray subsidiary agreement terminated october 2001 date operations related investment income loss deepwater holdings allocated proportionately ownership percentage capital contributed us larger amount total capital time formation therefore allocated larger amount amortization deepwater holdings excess purchase price investments also allocated larger portion deepwater holdings 21 million loss incurred 2001 due sale stingray utos west cameron dehydration facility total share losses relating sales approximately 14 million e recorded adjustments primarily differences estimated year end earnings reported annual report form 10k actual earnings reported audited annual reports unconsolidated affiliates gulfterra energy partners lp subsidiaries notes consolidated financial statements continued 4 property plant equipment property plant equipment consisted following 1 includes leasehold acquisition costs unamortized balance 32 million 41 million december 31 2003 2002 one interpretation considered relative sfas 141 business combinations sfas 142 goodwill intangible assets oil gas mineral rights held lease contractual arrangements representing right extract reserves undeveloped developed leaseholds classified separately oil gas properties intangible assets consolidated balance sheets continue include costs property plant equipment guidance provided due sale interest manta ray offshore system january 2001 lost primary connecting point manta ray pipeline result abandoned manta ray pipeline recorded impairment approximately 39 million first quarter 2001 reflected natural gas pipelines plants segment 5 investment processing agreement part october 2001 chaco transaction paid 1215 million el paso field services 20year feebased processing agreement processing agreement amortized straightline basis life agreement recorded amortization expense 56 million 2002 15 million 2001 related asset result san juan acquisition november 2002 gathering system related facilities previously owned el paso field services including rights el paso field services arrangements relating chaco plant part san juan acquisition processing agreement terminated 6 financing transactions credit facility credit facility consists two parts revolving credit facility maturing 2006 senior secured term loan maturing 2008 credit facility guaranteed us subsidiaries except unrestricted subsidiaries detailed note 16 collateralized substantially assets excluding assets unrestricted subsidiaries interest rates charged credit facility determined option using one two indices include variable base rate equal greater prime rate determined jpmorgan chase bank federal funds rate plus 05 certificate deposit cd rate determined jpmorgan chase bank increased 100 ii libor interest rate charged contingent upon leverage ratio defined credit facility ratings assigned sp moodys interest charged would increase 025 credit ratings gulfterra energy partners lp subsidiaries notes consolidated financial statements continued senior secured credit facility decrease leverage ratio decreases alternatively would decrease 025 ratings increased leverage ratio improves additionally pay commitment fees unused portion revolving credit facility rates vary 030 050 credit facility contains covenants include restrictions subsidiaries ability incur additional indebtedness liens sell assets make loans investments acquire acquired companies amend contracts well requiring maintenance certain financial ratios failure comply provisions covenants could result acceleration debt financial obligations subsidiaries restrict ability make distributions unitholders financial covenants associated credit facility follows ratio consolidated ebitda defined credit agreements consolidated interest expense cannot less 20 10 b ratio consolidated total senior indebtedness last day fiscal quarter consolidated ebitda four quarters ending last day current quarter cannot exceed 325 10 c ratio consolidated total indebtedness last day fiscal quarter consolidated ebitda four quarters ending last day current quarter cannot exceed 525 10 among things credit agreement includes event default change control defined failure el paso corporation subsidiaries longer least 50 percent general partner compliance financial ratios covenants contained credit facilities december 31 2003 revolving credit facility september 2003 renewed revolving credit facility among things expand credit available 600 million 700 million extend maturity may 2004 september 2006 december 31 2003 382 million outstanding revolving credit facility average interest rate 317 may elect portion revolving credit facility bear interest either variable rate described increased 10 libor increased 20 total amount available us december 31 2003 facility 318 million senior secured term loan december 2003 refinanced term loan portion credit facility provide greater financial flexibility among things expanding existing term component 160 million 300 million extending maturity october 2007 december 2008 reducing semiannual payments 25 million 15 million reducing interest rate charged 125 used proceeds term loan repay 155 million outstanding initial term loan temporarily reduce amounts outstanding revolving credit facility charged 28 million interest debt expense december 2003 writeoff unamortized debt issuance costs associated initial term loan senior secured term loan payable semiannual installments 15 million june december year first nine installments remaining balance maturity december 2008 may elect portion senior secured term loan bear interest either 125 variable base rate discussed libor increased 225 december 31 2003 300 million outstanding average interest rate 342 gulfterra energy partners lp subsidiaries notes consolidated financial statements continued gulfterra holding term credit facility formerly epn holding term credit facility connection acquisition epn holding assets el paso corporation april 2002 epn holding entered 560 million term credit facility group commercial banks term credit facility provided term loan gulfterra holding term loan 535 million finance acquisition epn holding assets revolving credit facility gulfterra holding revolving credit facility 25 million finance epn holdings working capital time acquisition epn holding borrowed 535 million 531 million net issuance costs term loan 25 million available gulfterra holding revolving credit facility used net proceeds approximately 149 million april 2002 common unit offering 06 million contributed general partner maintain one percent capital account balance 225 million net proceeds may 2002 offering 8 12 senior subordinated notes reduce indebtedness term loan july 2003 repaid remaining 160 million balance term credit facility proceeds issuance 250 million 6 14 senior notes due 2010 recognized loss 12 million related writeoff unamortized debt issuance costs connection repayment facility senior secured acquisition term loan part november 2002 san juan assets acquisition entered 2375 million senior secured acquisition term loan fund portion purchase price repaid senior secured acquisition term loan march 2003 proceeds issuance 300 million 8 12 senior subordinated notes due 2010 recognized loss 38 million related writeoff unamortized debt issuance costs connection repayment facility issuance senior secured acquisition term loan november 2002 repayment date interest rates revolving credit facility gulfterra holding term credit facility 225 variable base rate described libor increased 350 argo term loan balance 95 million including current maturities december 31 2001 repaid full april 2002 connection epn holding assets acquisition senior notes july 2003 issued 250 million aggregate principal amount 6 14 senior notes due june 2010 used proceeds approximately 2451 million net issuance costs repay 160 million indebtedness gulfterra holding term credit facility temporarily repay 851 million balance outstanding revolving credit facility interest senior notes payable semiannually june december principal maturing june 2010 senior notes unsecured obligations rank senior existing future subordinated debt equally existing future senior debt although effectively junior right payment existing future senior secured debt extent collateral securing debt senior notes guaranteed us subsidiaries except unrestricted subsidiaries may redeem senior notes option time least 30 days notice price equal greater 1 100 percent principal amount plus accrued interest 2 sum present value remaining scheduled payments plus accrued interest senior subordinated notes issue senior subordinated notes subordinated right payment existing future senior debt including existing credit facility senior notes issued july 2003 gulfterra energy partners lp subsidiaries notes consolidated financial statements continued march 2003 issued 300 million aggregate principal amount 8 12 senior subordinated notes interest notes payable semiannually june december notes mature june 2010 used proceeds approximately 2935 million net issuance costs repay 2375 million indebtedness senior secured acquisition term loan temporarily repay 555 million balance outstanding revolving credit facility may option prior june 1 2006 redeem 33 percent originally issued aggregate principal amount notes redemption price 10850 percent principal amount december 2003 redeemed 45 million provision see discussion may redeem part remainder notes time june 1 2007 redemption price date 10425 percent principal amount declining annually reaches 100 percent principal amount november 2002 issued 200 million aggregate principal amount 10 58 senior subordinated notes interest notes payable semiannually june december mature december 2012 notes issued 198 million net discount 15 million yield 1075 proceeds 194 million net issuance costs used fund portion acquisition san juan assets may option prior december 1 2005 redeem 33 percent originally issued aggregate principal amount notes redemption price 110625 december 2003 redeemed 66 million provision see discussion december 1 2007 may redeem part remainder notes 105313 principal amount may 2002 issued 230 million aggregate principal amount 8 12 senior subordinated notes interest notes payable semiannually june december mature june 2011 senior subordinated notes issued 2346 million proceeds approximately 230 million net issuance costs used proceeds 225 million reduce indebtedness epn holding term credit facility remainder general partnership purposes may option prior june 1 2004 redeem 33 percent originally issued aggregate principal amount senior subordinated notes due june 2011 redemption price 108500 december 2003 redeemed 759 million provision see discussion june 1 2006 may redeem part remainder notes 104250 principal amount may 2001 issued 250 million aggregate principal amount 8 12 senior subordinated notes interest notes payable semiannually june december mature june 2011 proceeds approximately 243 million net issuance costs used reduce indebtedness revolving credit facility may option prior june 1 2004 redeem 33 percent originally issued aggregate principal amount senior subordinated notes due june 2011 redemption price 108500 december 2003 redeemed 825 million provision see discussion june 1 2006 may redeem part remainder notes 104250 principal amount may 1999 issued 175 million aggregate principal amount 10 38 senior subordinated notes interest notes payable semiannually june december mature june 2009 proceeds approximately 169 million net issuance costs used reduce indebtedness revolving credit facility june 1 2004 may redeem part notes 105188 principal amount subsidiaries except gulfterra energy partners finance corporation unrestricted subsidiaries guaranteed obligations senior notes issuances senior subordinated notes described addition could required repurchase senior notes senior subordinated notes certain circumstances relating change control asset dispositions exist july 2003 achieve better mix fixed rate debt variable rate debt entered eightyear interest rate swap agreement provide floating interest rate 250 million 8 12 gulfterra energy partners lp subsidiaries notes consolidated financial statements continued senior subordinated notes due 2011 swap agreement pay counterparty libor based interest rate plus spread 420 rate 155 december 31 2003 receive fixed rate 8 12 accounting derivative fair value hedge sfas 133 december 31 2003 fair value swap liability included noncurrent liabilities approximately 74 million fair value hedged debt decreased amount december 2003 used portion net proceeds october 2003 equity offerings redeem approximately 2694 million principal amount senior subordinated notes terms indentures allow us use proceeds equity offering within 90 day period offering redeem 33 percent principal first three years notes outstanding incurred additional costs totaling 291 million resulting payment redemption premiums writeoff unamortized debt issuance costs premiums discounts accounted costs expense fourth quarter 2003 accordance provisions sfas 145 march 2004 gave notice exercise right terms senior subordinated notes indentures repay premium approximately 391 million principal amount senior subordinated notes indentures provide within 90 days equity offering call 33 percent original face amount premium amount repay limited net proceeds offering recognize additional costs totaling 41 million resulting payment redemption premiums writeoff unamortized debt issuance costs account costs expense second quarter 2004 accordance provisions sfas 145 restrictive provisions senior subordinated notes senior subordinated notes include provisions among things restrict ability subsidiaries excluding unrestricted subsidiaries incur additional indebtedness liens sell assets make loans investments acquire acquired companies enter sale leaseback transactions well requiring maintenance certain financial ratios failure comply provisions covenants could result acceleration debt financial obligations subsidiaries addition restricting ability make distributions unitholders many restrictive covenants associated senior notes effectively removed following period 90 consecutive days rated baa3 higher moodys bbb higher sp restrictive covenants associated senior subordinated notes suspended similarly rated credit facilities poseidon december 31 2003 poseidon oil pipeline company llc unconsolidated affiliate 36 percent joint venture ownership interest party 185 million credit agreement 123 million outstanding december 31 2003 january 2004 poseidon amended credit agreement decreased availability 170 million amended facility matures january 2008 outstanding balance previous facility transferred new facility january 2002 poseidon entered twoyear interest rate swap agreement fix variable libor based interest rate 75 million 123 million outstanding credit facility 349 january 2004 poseidon credit facility currently pays additional 125 libor rate resulting effective interest rate 474 hedged notional amount interest rates poseidon charged balances outstanding credit facility dependent leverage ratio defined poseidon credit facility poseidons interest rate december 31 2003 libor plus 125 eurodollar gulfterra energy partners lp subsidiaries notes consolidated financial statements continued loans variable base rate equal greater prime rate 050 plus federal funds rate terms defined poseidon credit agreement plus 025 base rate loans december 31 2003 remaining 48 million average interest rate 246 amended credit facility based poseidons leverage ratio year ended december 31 2003 poseidons interest rate libor plus 200 eurodollar loans variable base rate equal greater prime rate 050 plus federal funds rate terms defined poseidon credit agreement plus 100 base rate loans poseidons interest rates decrease 025 leverage ratio declines 300 100 less 050 leverage ratio declines 200 100 less 0625 leverage ratio declines 100 less additionally poseidon pays commitment fees unused portion credit facility rates vary 025 0375 credit agreement requires poseidon maintain debt service reserve equal two times previous quarters interest poseidons credit agreement contains covenants restrictions debt levels restrictions liens collateralizing debt guarantees restrictions mergers sales assets dividend restrictions breach covenants could result acceleration poseidons debt financial obligations poseidon 170 million revolving credit facility financial debt covenants poseidon must maintain consolidated tangible net worth amount less 75 million plus 100 net cash proceeds issuance poseidon equity securities kind b ratio poseidons ebitda defined poseidons credit agreement interest expense paid accrued four quarters ending last day current quarter must least 250 100 c ratio total indebtedness poseidon ebitda four quarters ending last day current quarter shall exceed 450 100 2004 350 100 2005 300 100 thereafter poseidon compliance covenants previous facility december 31 2003 deepwater gateway august 2002 deepwater gateway joint venture constructing marco polo tlp obtained 155 million project finance loan group commercial lenders finance substantial portion cost construct marco polo tlp related facilities deepwater gateway may elect portion project finance loan bear interest either libor plus 175 ii alternate base rate equal greater prime rate base cd rate plus 1 federal funds rate plus 05 terms defined project finance loan agreement plus 075 deepwater gateway must also pay commitment fees 0375 per year unused portion project finance loan collateralized substantially deepwater gateways assets deepwater gateway defaults payment obligations project finance loan would required pay lenders distributions subsidiaries received deepwater gateway 225 million december 31 2003 deepwater gateway 155 million outstanding project finance loan average interest rate 294 paid us subsidiaries distributions project finance loan mature july 2004 unless construction completed time deepwater gateway meets specified conditions case project finance loan convert term loan final maturity date july 2009 upon conversion project finance loan term loan deepwater gateway required maintain debt service reserve less projected principal interest fees due term loan immediately succeeding six month period addition gulfterra energy partners lp subsidiaries notes consolidated financial statements continued deepwater gateway prohibited making distributions project finance loan repaid converted cameron highway cameron highway oil pipeline company cameron highway unconsolidated affiliate 50 percent joint venture ownership interest see note 3 additional discussion relating formation cameron highway entered 325 million project loan facility consisting 225 million construction loan 100 million senior secured notes fund proportionately construction costs incurred 225 million construction loan bears interest cameron highways option borrowing either 200 variable base rate equal greater prime rate determined jpmorgan chase bank federal funds rate plus 05 certificate deposit cd rate determined jpmorgan chase bank increased 100 ii 300 libor upon completion construction loan convert term loan maturing july 2008 subject terms loan agreement end first quarter following first anniversary conversion term loan cameron highway required make quarterly principal payments 8125 million remaining unpaid principal amount payable maturity date construction loan fails convert term loan december 31 2006 construction loan senior secured notes become fully due payable december 31 2003 cameron highway 69 million outstanding construction loan average interest rate 421 interest rate cameron highways senior secured notes 325 rate 10year us treasury securities principal payments 4 million due quarterly september 2008 december 2011 6 million march 2012 december 2012 5 million march 2013 principal maturity date december 2013 december 31 2003 cameron highway 56 million outstanding notes average interest rate 738 terms project loan facility cameron highway must pay lenders senior secured noteholders commitment fees 05 per year unused portion lenders noteholders committed funds project loan facility whole collateralized 1 substantially cameron highways assets including upon conversion debt service reserve capital account 2 equity interest cameron highway pledge equity interest construction obligations relevant producer agreements discussed note 3 debt nonrecourse us construction loan senior secured notes prohibit cameron highway making distributions us construction loan converted term loan cameron highway meets certain financial requirements debt maturity table aggregate maturities principal amounts longterm debt financing obligations next 5 years total thereafter follows thousands gulfterra energy partners lp subsidiaries notes consolidated financial statements continued interest debt expense recognized interest cost incurred connection financing transactions follows years ended december 31 loss due early redemptions debt recognized losses associated early redemptions debt follows years ended december 31 7 financial instruments fair value financial instruments carrying amounts estimated fair values financial instruments december 31 follows 1 excludes market value interest rate swap see interest rate swap discussion gulfterra energy partners lp subsidiaries notes consolidated financial statements continued notional amounts terms financial instruments held purposes trading follows december 31 july 2003 entered eightyear interest rate swap agreement provide floating interest rate 250 million 8 12 senior subordinated notes due 2011 swap agreement pay counterparty libor based interest rate plus spread 420 rate 155 december 31 2003 receive fixed rate 8 12 december 31 2003 2002 carrying amounts cash equivalents shortterm borrowings trade receivables payables representative fair value shortterm nature instruments fair value longterm debt variable interest rates approximates carrying value variable interest rates loans reprice frequently reflect currently available interest rates estimated fair value debt fixed interest rates based quoted market prices similar issues estimated fair value derivative financial instruments prices indicated similar commodity transactions specific index credit risk credit risk relates risk loss would incur result customers failure pay customers concentrated energy sector creditworthiness several industry participants called question maintain credit policies minimize overall credit risk monitor exposure determine appropriate whether request prepayments letters credit collateral counterparties 8 partners capital general december 31 2003 58404649 common units outstanding common units totaling 48020404 owned public representing 822 percent common unit interest us december 31 2003 el paso corporation subsidiaries owned 10384245 common units 178 percent outstanding common units 10937500 series c units 50 percent one percent general partner interest offering common units 2003 issued following common units public offerings 1 offering includes 80 series f convertible units offered refer description gulfterra energy partners lp subsidiaries notes consolidated financial statements continued addition public offerings common units october 2003 sold 3000000 common units privately goldman sachs connection purchase 99 percent membership interest general partner used net proceeds 1115 million private sale net proceeds common unit public offerings temporarily reduce amounts outstanding revolving credit facility senior subordinated notes general partnership purposes may 2003 issued 1118881 common units 80 series f convertible units registered offering large institutional investor approximately 383 million net offering costs series f convertible units listed securities exchange market series f convertible unit comprised two separate detachable units series convertible unit series convertible unit identical terms except vesting termination dates number underlying common units may converted series units convertible 80 million common units anytime august 12 2003 date merge enterprise subject defined extension rights series units convertible 40 million common units series units terminate march 30 2005 subject defined extension rights price series f convertible units may converted common units equal lesser prevailing price defined prevailing price equal greater 3575 ii prevailing price minus product 50 percent positive difference 3575 minus prevailing price prevailing price equal lesser average closing price common units 60 business days ending including fourth business day prior receiving notice holder series f convertible units intent convert common units ii average closing price common units first seven business days 60 day period included iii average closing price common units last seven days 60 day period included price series f convertible units could converted common units assuming received conversion notice december 31 2003 march 2 2004 4038 3940 series f convertible units may converted maximum 8329679 common units holders series f convertible units entitled vote receive distributions 41 million value associated series f convertible units included partners capital component common units capital august 2003 amended terms series f convertible units permit holder elect cashless exercise holder gives common units value equal exercise price rather paying exercise price cash holder elects option settle net position issuing common units settlement price per unit 2600 per unit paying holder amount cash equal market price net number units amendments effect classification series f convertible units balance sheet december 31 2003 first quarter 2004 45 series convertible units converted 1146418 common units holder convertible units paid us 45 million series f convertible units outstanding merger date converted rights receive enterprise common units subject restrictions governing series f units number enterprise common units price per unit conversion adjusted based 181 exchange ratio connection offerings 2003 general partner contributed us approximately 20 million series b preference units cash 31 million order maintain one percent general partner interest april 2002 completed simultaneous offerings 4083938 common units included public offering 3000000 common units private offering unit price 1083938 common units general partner pursuant general partners antidilution rights partnership agreement transaction involving public offering used net cash proceeds approximately 149 million reduce indebtedness epn holdings term credit facility also april 2002 issued private gulfterra energy partners lp subsidiaries notes consolidated financial statements continued offering 159497 common units thencurrent market price 3774 per unit subsidiary el paso corporation partial consideration acquisition epn holding assets addition general partner contributed approximately 06 million cash us april 2002 order maintain one percent capital account balance october 2001 completed simultaneous offerings 5627070 common units included public offering 4150000 common units private offering unit price 1477070 common units general partner pursuant general partners antidilution rights partnership agreement transaction involving public offering used net cash proceeds approximately 212 million redeem 44608 series b preference units liquidation value 50 million reduce balance outstanding revolving credit facility addition general partner contributed 21 million cash us order satisfy one percent contribution requirement march 2001 completed public offering 2250000 common units used net cash proceeds 666 million offering reduce balance outstanding revolving credit facility addition general partner contributed 07 million us order satisfy one percent capital contribution requirement series b preference units august 2000 issued 170000 series b preference units value 170 million acquire petal hattiesburg natural gas storage businesses october 2001 redeemed 44608 series b preference units 50 million liquidation value including accrued distributions approximately 54 million bringing total number units outstanding 125392 december 31 2002 liquidation value outstanding series b preference units approximately 158 million october 2003 redeemed 123865 remaining outstanding series b preference units 156 million 7 percent discount liquidation value 167 million redemption used borrowings revolving credit facility reflected discount increase common units capital series c units capital general partners capital accounts series c units november 2002 issued subsidiary el paso corporation 10937500 series c units price 32 per unit 350 million aggregate part consideration paid san juan assets issuance series c units exempt transaction section 42 securities act 1993 transaction involving public offering series c units similar existing common units except series c units nonvoting april 30 2003 holder series c units right cause us propose vote common unitholders whether series c units converted common units common unitholders approve conversion series c unit convert common unit common unitholders approve conversion within 120 days vote requested distribution rate series c units increase 105 percent common unit distribution rate effect time thereafter series c unit distribution rate increase april 30 2004 110 percent common unit distribution rate april 30 2005 115 percent common unit distribution rate addition general partner contributed 35 million us order satisfy one percent capital contribution requirement holder series c units thus far requested vote convert series c units common units part proposed merger enterprise purchase subsidiary el paso corporation outstanding series c units converted enterprise common units merger rather remain limited partnership interests gulfterra closing merger transaction interest lose gulfterra common unit conversion distribution rights gulfterra energy partners lp subsidiaries notes consolidated financial statements continued cash distributions make quarterly distributions 100 percent available cash defined partnership agreement unitholders general partner available cash generally consists cash receipts plus reductions reserves less cash disbursements net additions reserves general partner broad discretion establish cash reserves proper partnership purpose include cash reserves future capital maintenance expenditures reserves stabilize distributions cash unitholders general partner reserves reduce debt necessary reserves comply terms agreements obligations cash distributions common units series c units general partner discretionary nature entitled arrearages minimum quarterly distributions following table reflects per unit cash distributions common unitholders total distributions paid common unitholders series c unitholder general partner year ended december 31 2003 january 2004 declared cash distribution 071 per common series c unit 493 million aggregate quarter ended december 31 2003 paid february 14 2004 addition paid general partner 213 million related general partner interest current distribution rates general partner receives approximately 302 percent total cash distributions role general partner option plans august 1998 adopted 1998 omnibus compensation plan omnibus plan provide general partner ability issue unit options attract retain services knowledgeable officers key management personnel unit options purchase maximum 3 million common units may issued pursuant omnibus plan unit options granted date pursuant omnibus plan immediately exercisable unit options granted 2001 onehalf unit options considered vested exercisable one year date grant remaining onehalf unit options considered vested exercisable one year first anniversary date grant unit options expire ten years grant date shall subject earlier termination certain circumstances grants unit options made 2002 2003 omnibus plan granted 17500 unit options 25000 timevested restricted units grant 25000 restricted units certain performance targets achieved employees el paso field services whose primary responsibilities commercial management assets august 1998 also adopted 1998 common unit plan nonemployee directors director plan formerly 1998 unit option plan nonemployee directors provide general partner ability issue unit options attract retain services knowledgeable directors unit options restricted units purchase maximum 100000 common units may issued pursuant director plan director plan nonemployee director receives grant 2500 unit options upon initial election board directors annual unit option grant 2000 unit options gulfterra energy partners lp subsidiaries notes consolidated financial statements continued beginning 2001 annual restricted unit grant equal directors annual retainer including chairmans retainers applicable divided fair market value common units grant date upon reelection board directors unit option granted vest immediately date grant expire ten years date subject earlier termination event nonemployee director ceases director general partner reason case unit options expire 36 months date except case death case unit options expire 12 months date director receiving grant restricted units recorded unitholder rights unitholder respect units including right distributions units restricted units nontransferable directors service board directors restrictions restricted units end director receive one common unit restricted unit granted upon directors termination director plan administered management committee consisting chairman board directors general partner senior officers general partner affiliates chairman may designate 2003 director plan granted 5226 restricted units fair value per unit 3637 10500 unit options grant price 3592 restricted units awards representing 5429 4090 granted 2002 2001 fair value 3223 3300 per unit december 31 2003 12292 restricted units outstanding accounted unit options restricted units except unit options issued nonemployee directors accordance sfas 123 sfas 123 report fair value issuances deferred compensation deferred compensation amortized compensation expense respective vesting performance period accounted unit options issued nonemployee directors general partners board directors accordance apb 25 issued timevested restricted units performancebased restricted units fair value date grant restrictions timevested units lapse four years date grant restrictions performancebased restricted units lapse achieve specified level target performance identified greenfield projects june 1 2007 15000 performancebased restricted units issued june 2003 august 1 2007 10000 performancebased restricted units issued august 2003 reach targets applicable dates performancebased units forfeited amortize fair value timevested restricted units fouryear restricted period fair value performancebased restricted units performance periods performancebased restricted units entitled vote receive distributions achieve specified level target performance restricted units issued nonemployee directors general partners board directors issued fair value date grant fair value amortized compensation expense period service estimated one year total unamortized deferred compensation december 31 2003 2002 approximately 15 million 12 million 2001 deferred compensation fully amortized deferred compensation reflected reduction partners capital allocated 1 percent general partner 99 percent limited partners gulfterra energy partners lp subsidiaries notes consolidated financial statements continued following table summarizes activity omnibus plan director plan excluding restricted units years ended december 31 2003 2002 2001 fair value unit option granted estimated date grant using blackscholes optionpricing model following weighted average assumptions blackscholes weighted average fair value options granted 2003 2002 2001 355 371 262 per unit option respectively options outstanding december 31 2003 summarized gulfterra energy partners lp subsidiaries notes consolidated financial statements continued 9 earnings per common unit following table sets forth computation basic diluted earnings per common unit thousands except unit amounts gulfterra energy partners lp subsidiaries notes consolidated financial statements continued 10 related party transactions majority related party transactions affiliates general partner agreement place indirect subsidiary el paso corporation purchased general partner affiliate general partner obligated provide individuals perform day financial administrative accounting operational functions us activities increased fee services also increased provide services various el paso corporation subsidiaries turn provide us services addition acquired number assets subsidiaries el paso corporation material transactions enterprise merger agreement transactions since enterprise acquired 50 percent general partner following table provides summary data transactions related parties years ended december 31 1 addition revenues continuing operations reflected also received revenues related parties 2002 2001 68 million 82 million prince tlp 10 million 07 million 9 percent overriding royalty interest included income discontinued operations income statements years ended december 31 2003 2002 2001 revenues received related parties consisted approximately 13 43 28 revenue continuing operations also undertaken efforts reduce transactions el paso merchant energy north america company merchant energy june 30 2003 replaced monthtomonth arrangements previously merchant energy similar arrangements third parties gulfterra energy partners lp subsidiaries notes consolidated financial statements continued following table provides summary data categorized related parties years ended december 31 1 addition revenues continuing operations el paso production company reflected 2002 2001 also received revenues 78 million 89 million el paso production company included income discontinued operations income statements 2 sold interest manta ray offshore january 2001 connection el paso corporations merger coastal corporation 3 january 2001 deepwater holdings sold stingray west cameron subsidiaries april 2001 deepwater holdings sold utos subsidiary october 2001 acquired remaining 50 percent deepwater holdings result transaction going forward basis deepwater holdings consolidated financial statements agreement deepwater holdings terminated revenues received related parties epn holding assets revenues related parties increased 2002 result epn holding transaction acquired gathering transportation processing contracts affiliates general partner years ended december 31 2003 2002 received 265 million gulfterra energy partners lp subsidiaries notes consolidated financial statements continued 689 million el paso merchant energy north america company 199 million 358 million el paso field services 34 million 40 million el paso production company gtm texas connection acquisition gtm texas february 2001 entered 20year feebased transportation fractionation agreement el paso field services pursuant agreement receive fixed fee barrel ngl transported fractionated facilities approximately 25 percent per barrel fee escalated annually increases inflation years ended december 31 2003 2002 2001 received revenue approximately 215 million 260 million 252 million related agreement chaco processing plant connection chaco transaction october 2001 entered 20year feebased processing agreement el paso field services pursuant agreement receive fixed fee dekatherm natural gas process chaco plant years ended december 31 2002 2001 received revenue 296 million 65 million related agreement accordance original construction financing agreements chaco plant operating lease el paso field services years ended december 31 2002 2001 received 18 million 06 million related lease result san juan asset acquisition november 2002 processing agreement operating lease terminated storage facilities april 2002 acquisition epn holding assets purchased contracts held wilson storage el paso merchant energy north america company year ended december 31 2002 received approximately 29 million el paso merchant energy north america company natural gas storage fees el paso merchant energy north america company tennessee gas pipeline company use petal hattiesburg storage facilities time years ended december 31 2002 2001 received approximately 01 million 16 million el paso merchant energy north america company natural gas storage fees year ended december 31 2001 received approximately 07 million tennessee gas pipeline company prince tlp september 2001 placed prince tlp service prior april 1 2002 received monthly demand charge approximately 19 million well processing fees el paso production company related production prince tlp year ended december 31 2002 four months ended december 31 2001 received 68 million 82 million platform revenue related agreement connection acquisition epn holding assets el paso corporation april 2002 sold prince tlp subsidiaries el paso corporation revenues reflected income discontinued operations production fields 2000 agreed sell substantially oil natural gas production el paso merchant energy north america company month basis agreement provided fees equal two percent sales value crude oil condensate 0015 per dekatherm natural gas marketing production beginning fourth quarter 2000 began selling oil natural gas directly third parties oil natural gas sales related el paso merchant energy north america company approximately 98 million 57 million years ended december 31 2002 2001 october 1999 farmed working interest prince field el paso production company terms farmout agreement net overriding royalty interest prince field increased weighted average approximately nine percent el paso production company began production prince field september 2001 year ended december 31 2002 four months ended december 31 2001 recorded approximately 10 million 07 million revenues related overriding royalty interest prince field connection acquisition epn holding assets el paso corporation april 2002 sold 9 percent overriding royalty interest prince field gulfterra energy partners lp subsidiaries notes consolidated financial statements continued subsidiaries el paso corporation revenues reflected income discontinued operations gulfterra alabama intrastate several el paso corporation subsidiaries buy transport natural gas gulfterra alabama intrastate system years ended december 31 2003 2002 2001 received approximately 07 million 68 million 83 million el paso merchant energy north america company years ended december 31 2003 2002 2001 received approximately 45 million 45 million 42 million el paso production company years ended december 31 2003 2002 2001 received approximately 01 million 01 million 02 million southern natural gas company hios october 2001 hios became whollyowned asset acquisition remaining 50 percent equity interest deepwater holdings hios natural gas transmission system entered interruptible transportation agreements nondiscounted rate 01244 years ended december 31 2003 2002 approximately three months ended december 31 2001 received 01 million 14 million 08 million el paso merchant energy year ended december 31 2003 2002 received 12 million 06 million el paso production company texas ngl assets connection acquisition san juan assets november 2002 entered 10year transportation agreement el paso field services pursuant agreement beginning january 1 2003 receive fee 15 million per year transportation ngl pipeline extends corpus christi near houston addition provide transportation fractionation storage terminaling services el paso field services well various third parties typically agreements one year term less received approximately 75 million 03 million revenues el paso field services years ended december 31 2003 2002 addition revenues discussed received 28 million 26 million el paso merchant north america 256 million 33 million el paso field services 2003 2002 additional gathering processing services 2003 increase revenues el paso field services primarily result higher natural gas prices ngl volumes sold el paso field services big thicket assets unconsolidated subsidiaries years ended december 31 2001 received approximately 003 million manta ray offshore gathering platform access processing fees related south timbalier 292 platform ship shoal 332 platform sold interest manta ray offshore january 2001 connection el pasos merger coastal corporation expenses paid related parties cost natural gas cost natural gas paid related parties increased 2003 2002 result san juan assets acquisitions epn holding transaction acquired contracts affiliates general partner year ended december 31 2003 san juan assets cost natural gas expenses 13 million el paso merchant energy north america 03 million el paso field services year ended december 31 2003 2002 epn holding assets cost natural gas expenses 09 million 03 million el paso merchant energy north america company 35 million 04 million el paso field services relating gulfterra texas gathering system gulfterra alabama intrastates purchases natural gas include transactions affiliates general partner years ended december 31 2003 2002 2001 natural gas purchases approximately 256 million 189 million 282 million el paso merchant energy north america company 01 million 02 million 02 million southern natural gas company 23 million 64 million el paso production company years ended december 31 2002 2001 also receive lease throughput fees el paso field services hattiesburg anse gulfterra energy partners lp subsidiaries notes consolidated financial statements continued la butte year ended december 31 2002 received 05 million el paso field services related fees operating expenses substantially individuals perform daytoday financial administrative accounting operational functions us well responsible directing controlling us currently employed el paso corporation general administrative services agreement subsidiaries el paso corporation us fee approximately 08 million per month charged general partner accordingly us intended approximate amount resources allocated el paso corporation affiliates providing various operational financial accounting administrative services behalf general partner us april 2002 connection acquisition epn holding assets general administrative services agreement extended december 31 2005 fee increased approximately 16 million per month november 2002 result san juan assets acquisition monthly fee general administrative services agreement increased 13 million bringing total monthly fee 29 million believe fee approximates actual costs incurred terms partnership agreement general partner entitled reimbursement reasonable general administrative expenses reasonable expenses incurred general partner affiliates behalf including limited amounts payable general partner el paso corporation management agreement also charged insurance costs paid directly el paso field services behalf became operator additional facilities systems acquired new operations constructed new facilities entered additional management operating agreements el paso field services fees paid contracts approximate actual costs incurred following table shows amount el paso field services charged us agreements year ended december 31 1 operating fees increased 2002 2003 2001 2002 due acquisition san juan assets epn holding assets cost reimbursements connection becoming operator poseidon entered operating agreement january 2001 fees received contracts approximate actual costs incurred acquisitions purchased assets related parties see note 2 discussion asset acquisitions matters addition related party transactions discussed pursuant terms many purchase sale agreements entered various entities controlled directly indirectly el paso corporation indemnified potential future liabilities expenses capital requirements negotiated threshold specifically indirect subsidiary el paso corporation agreed indemnify us specific litigation matters extent ultimate resolutions matters result judgments us discussion matters see note 11 commitments gulfterra energy partners lp subsidiaries notes consolidated financial statements continued contingencies legal proceedings agreements obligate certain indirect subsidiaries el paso corporation pay capital costs related maintaining assets acquired us costs exceed negotiated thresholds made claims approximately 5 million costs incurred year ended december 31 2003 costs exceeded established thresholds year ended december 31 2003 also entered capital contribution arrangements entities owned el paso corporation including regulated pipelines past likely future part normal commercial activities gulf mexico agreement receive 61 million 30 million collected anr pipeline company phoenix project december 31 2003 received 105 million anr pipeline 70 million el paso field services marco polo natural gas pipeline october 2003 collected 2 million tennessee gas pipeline medusa project amounts reflected reduction project costs regulated pipelines often contribute capital toward construction costs gathering facilities owned others connected pipelines el paso field services contribution anticipation additional natural gas volumes flow onshore natural gas processing facilities august 2003 arizona gas storage llc along 50 percent partner apacs holdings llc sold interest copper eagle gas storage llc el paso natural gas company epng subsidiary el paso corporation copper eagle gas storage developing natural gas storage project located outside phoenix arizona gas storage indirect 60 percent owned subsidiary us 40 percent owned intragas us gaz de france north american subsidiary apacs holdings llc wholly owned subsidiary pinnacle west energy subsidiary pinnacle west capital corporation right receive 62 million sale proceeds including note receivable 49 million paid quarterly next twelve months epng recorded gain 882 thousand related sale copper eagle event epng default copper eagle gas storage project revert back original owners without compensation epng september 2003 entered nonbinding letter intent southern natural gas company subsidiary el paso corporation regarding proposed development sale natural gas storage cavern proposed sale undivided interest pipeline facilities related natural gas storage cavern new storage cavern would located storage complex near hattiesburg mississippi southern natural gas determines sufficient market interest would purchase land mineral rights related proposed storage cavern would pay costs construct storage cavern related facilities upon completion storage cavern southern natural gas would acquire undivided interest petal pipeline connected storage cavern would also enter arrangement southern natural gas would operate storage cavern pipeline behalf consummate transaction enter definitive transaction documents transaction must recommended audit conflicts committee general partners board directors committee consists solely directors meeting independent director requirements established nyse sarbanesoxley act approved general partners full board directors october 2003 exchanged el paso corporation obligation repurchase chaco plant us 19 years additional assets refer note 2 also october 2003 redeemed outstanding series b preference units refer note 8 counterparty one san juan hedging activities j aron company affiliate goldman sachs goldman sachs also comanager 4800000 public common unit offering october 2003 one lenders revolving credit facility owned 99 percent general partner part fourth quarter 2003 gulfterra energy partners lp subsidiaries notes consolidated financial statements continued accounts receivable due related parties consisted following 1 december 2002 receivable balance includes approximately 15 million natural gas imbalances relating epn holding acquisition accounts payable due related parties consisted following 1 december 2002 payable balance includes approximately 19 million working capital adjustments relating epn holding acquisition due el paso field services approximately 22 million natural gas imbalances relating epn holding acquisition gulfterra energy partners lp subsidiaries notes consolidated financial statements continued connection sale gulf mexico assets january 2001 el paso corporation agreed make quarterly payments us 225 million three years beginning march 2001 ending 2 million payment first quarter 2004 present value amounts due el paso corporation classified follows 11 commitments contingencies legal proceedings grynberg 1997 along numerous energy companies named defendants actions brought jack grynberg behalf us government false claims act generally complaints allege industrywide conspiracy underreport heating value well volumes natural gas produced federal native american lands deprived us government royalties plaintiff case seeks royalties contends government received volume heating value differently measured analyzed calculated reported together interest treble damages civil penalties expenses future injunctive relief require defendants adopt allegedly appropriate gas measurement practices monetary relief specified case matters consolidated pretrial purposes natural gas royalties qui tam litigation us district court district wyoming filed june 1997 discovery proceeding costs legal exposure related lawsuits claims currently determinable price formerly quinque along numerous energy companies named defendants price et al v gas pipelines predecessors et al filed 1999 district court stevens county kansas plaintiffs allege defendants mismeasured natural gas volumes heating content natural gas nonfederal nonnative american lands seek certification nationwide class natural gas working interest owners natural gas royalty owners recover royalties contend owners received volume heating value natural gas produced properties differently measured analyzed calculated reported together prejudgment postjudgment interest punitive damages treble damages attorneys fees costs expenses future injunctive relief require defendants adopt allegedly appropriate gas measurement practices monetary relief specified case plaintiffs motion class certification nationwide class natural gas working interest owners natural gas royalty owners denied april 10 2003 plaintiffs granted leave file fourth amended petition narrows proposed class royalty owners wells kansas wyoming colorado removes claims heating content second class action petition filed heating content claims costs legal exposure related lawsuits claims currently determinable connection april 2002 acquisition epn holding assets subsidiaries el paso corporation agreed indemnify us obligations related existing legal matters acquisition date including legal matters involving leapartners lp city edinburg houston pipe line company lp city corpus christi discussed 2000 leapartners lp filed suit el paso field services others district court loving county texas alleging breach contract gather process natural gas areas western texas related asset owned gulfterra holding may 2001 court ruled favor gulfterra energy partners lp subsidiaries notes consolidated financial statements continued leapartners entered judgment el paso field services approximately 10 million el paso field services filed appeal eighth court appeals el paso texas august 15 2003 court appeals reversed lowers courts calculation past judgment interest otherwise affirmed judgment motion rehearing denied petition review texas supreme court filed also gulfterra texas pipeline lp gulfterra texas formerly known epgt texas pipeline lp owned gulfterra holding involved litigation city edinburg concerning citys claim gulfterra texas required pay pipeline franchise fees contract city rio grande valley gas company previously owned gulfterra texas owned southern union gas company adverse judgment southern union gulfterra texas rendered hidalgo county state district court december 1998 found breach contract held gulfterra texas southern union jointly severally liable city approximately 47 million judgment relied single business enterprise doctrine impose contractual obligations gulfterra texas southern union entities parties contract city gulfterra texas appealed case texas supreme court seeking reversal judgment rendered gulfterra texas city sought remand trial court claim tortious interference gulfterra texas briefs filed oral arguments held november 2002 october 2003 texas supreme court issued opinion favor gulfterra texas southern union issues city requested rehearing december 2000 30inch natural gas pipeline jointly owned gulfterra intrastate lp gulfterra intrastate owned gulfterra holding houston pipe line company lp ruptured mont belvieu texas near baytown resulting substantial property damage minor physical injury gulfterra intrastate operator pipeline two lawsuits filed state district court chambers county texas eight plaintiffs including two homeowners insurers suits sought recovery physical pain suffering mental anguish physical impairment medical expenses property damage houston pipe line company added additional defendant accordance terms operating agreement gulfterra intrastate agreed assume defense indemnify houston pipe line company december 31 2003 claims settled settlements impact financial statements city corpus christi texas city alleged gulfterra texas various coastal entities owed monies past obligations city ordinances propose tax gulfterra texas gross receipts local natural gas sales use street rightsofway gulfterra texas pipe issue using rightsofway since 1960s addition city demanded gulfterra texas agree goingforward consent agreement order gulfterra texas pipe coastal pipe right remain city rightsofway december 2003 gulfterra texas city entered license agreement releasing gulfterra texas past obligations providing certain rights use city rightsofway city owned property agreement retroactive october 1 2002 august 2002 acquired big thicket assets consist vidor plant silsbee compressor station big thicket gathering system located east texas approximately 11 million bp america production company bp pursuant purchase agreement identified environmental conditions working bp appropriate regulatory agencies address bp agreed indemnify us exposure resulting activities related ownership operation facilities prior purchase period three years nonenvironmental claims ii one year following completion environmental remediation environmental claims following expiration indemnity periods obligated indemnify bp environmental gulfterra energy partners lp subsidiaries notes consolidated financial statements continued nonenvironmental claims along bp various defendants named following two lawsuits claims based activities occurring prior purchase facilities christopher beverly gretchen beverly individually behalf estate john beverly v gulfterra gc lp et al june 2003 plaintiffs sued us state district court hardin county texas plaintiffs parents john christopher beverly two year old child died april 15 2002 allegedly result exposure arsenic benzene harmful chemicals water supply plaintiffs allege several defendants responsible contamination including us bp connection occurrences basis suit appears august 2002 purchase certain assets bp including facility hardin county texas known silsbee compressor station terms indemnity provisions purchase sale agreement gulfterra bp gulfterra requested bp indemnify gulfterra exposure bp agreed indemnify us matter melissa duvail et al v gulfterra gc lp et al june 2003 seventyfour residents hardin county texas sued us others state district court hardin county texas plaintiffs allege exposed hazardous chemicals including arsenic benzene water supply defendants responsible exposure beverly case connection occurrences basis suit appears august 2002 purchase certain assets bp including facility known silsbee compressor station located hardin county texas terms indemnity provisions purchase sale agreement us bp agreed indemnify us matter addition matters subsidiaries affiliates named defendants numerous lawsuits governmental proceedings arise ordinary course business outstanding legal matters evaluate merits case exposure matter possible legal settlement strategies likelihood unfavorable outcome determine unfavorable outcome probable estimated establish necessary accruals december 31 2003 reserves legal matters outcome outstanding legal matters cannot predicted certainty based information known date expect ultimate resolution matters material adverse effect financial position results operations cash flows new information becomes available relevant developments occur establish accruals appropriate environmental operating segments subject extensive federal state local laws regulations governing environmental quality pollution control laws regulations applicable segment require us remove remedy effect environment disposal release specified substances current former operating sites december 31 2003 reserve approximately 21 million included noncurrent liabilities remediation costs expected incurred time associated mercury meters assumed liability connection april 2002 acquisition epn holding assets part november 2002 san juan assets acquisition el paso corporation agreed indemnify us known unknown environmental liabilities related assets purchased purchase price 766 million indemnified unknown liabilities three years purchase date acquisition addition indemnified third parties remediation costs associated assets purchased expect make capital expenditures environmental matters approximately 3 million aggregate years 2004 2008 primarily comply clean air regulations gulfterra energy partners lp subsidiaries notes consolidated financial statements continued shoup air permit violation december 16 2003 el paso field services lp received notice enforcement noe texas commission environmental quality tceq concerning alleged clean air act violations shoup texas plant noe included draft agreed order assessing penalty 365750 cited violations alleged violations pertained emission limit exceedences testing reporting recordkeeping issues 2001 noe addressed el paso field services lp substance noe also concerns equipment owned shoup plant gulfterra gc lp el paso field services lp responded noe preparing meet tceq discuss alleged violations proposed penalty outcome outstanding environmental matters cannot predicted certainty based information known date existing accruals expect ultimate resolution matters material adverse effect financial position results operations cash flows possible new information future developments could require us reassess potential exposure related environmental matters may incur significant costs liabilities order comply existing environmental laws regulations also possible developments increasingly strict environmental laws regulations claims damages property employees persons environment resulting current past operations could result substantial costs liabilities future information becomes available relevant developments occurwe adjust accrual amounts accordingly still uncertainties relating ultimate costs may incur based upon evaluation experience date believe current reserves adequate rates regulatory matters marketing affiliate final rule november 2003 ferc issued final rule extending standards conduct governing relationship interstate pipelines marketing affiliates energy affiliates since hios natural gas pipeline petal natural gas storage facility including 60mile petal natural gas pipeline interstate facilities defined natural gas act regulations dictate hios petal conduct business interact energy affiliates el paso corporation us standards conduct require us absent waiver functionally separate hios petal interstate facilities entities must dedicate employees manage operate interstate facilities independently energy affiliates employee group must function independently prohibited communicating nonpublic transportation information customer information energy affiliates separate office facilities systems necessary requirement restrict affiliate access interstate transportation information final rule also limits sharing employees offices energy affiliates final rule effective february 9 2004 subject possible rehearing date transmission provider filed ferc posted internet website plan scheduling implementing final rule june 1 2004 written procedures implementing final rule posted internet website requests rehearing filed pending time cannot predict outcome requests minimum adoption regulations form outlined final rule place additional administrative operational burdens us pipeline safety final rule december 2003 us department transportation issued final rule requiring pipeline operators develop integrity management programs gas transmission pipelines located leak rupture could harm high consequence areas hca final rule requires operators 1 perform ongoing assessments pipeline integrity 2 identify characterize applicable threats pipeline segments could impact hca 3 improve data collection integration analysis 4 repair remediate pipeline necessary 5 implement preventive mitigative actions final rule incorporates requirements pipeline safety improvement act 2002 new gulfterra energy partners lp subsidiaries notes consolidated financial statements continued bill signed law december 2002 final rule effective january 14 2004 time cannot predict outcome final rule regulatory matters hios subject jurisdiction ferc accordance natural gas act 1938 natural gas policy act 1978 hios operates ferc approved tariff governs operations terms conditions service rates timely filed required rate case hios december 31 2002 rate filing tariff changes based hios cost service includes operating costs management fee changes depreciation rates negative salvage amortization requested rates effective february 1 2003 ferc suspended rate increase july 1 2003 subject refund july 1 2003 hios implemented requested rates subject refund established reserve estimate refund obligation continue review expected refund obligation rate case moves hearing process may increase decrease amounts reserved refund obligation expectation changes ferc conducted hearing matter initial decision expected issued april 2004 latter half 2002 experienced significant unfavorable variance fuel usage hios fuel collected customers use believe series events may contributed variance including two major storms hit gulf coast region assets late september early october 2002 december 31 2003 recorded fuel differences approximately 82 million included noncurrent assets currently discussions ferc well customers regarding potential collection fuel differences time able determine amount may collectible customers amount unable resolve collect customers negatively impact earnings december 1999 gulfterra texas filed petition ferc approval rates interstate transportation service june 2002 ferc issued order required revisions gulfterra texas proposed maximum rates changes ordered ferc involve reductions rate return depreciation rates revisions proposed rate design including requirement separately state rates gathering service ferc also ordered refunds customers difference originally proposed levels revised rates ordered ferc believe amount rate refund would minimal since transportation services discounted maximum rate gulfterra texas established reserve refunds july 2002 gulfterra texas requested rehearing certain issues raised fercs order including depreciation rates requirement separately state gathering rate february 25 2004 ferc issued order denying gulfterra texas request rehearing ordered gulfterra texas file within 45 days issuance order calculation refunds refund plan additionally ferc ordered gulfterra texas file new rate case justification existing rates within three years date order july 2002 falcon gas storage competitor also requested late intervention rehearing order falcon asserts gulfterra texas imbalance penalties terms service preclude third parties offering imbalance management services ferc denied falcons late intervention february 25 2004 meanwhile december 2002 gulfterra texas amended statement operating conditions provide shippers option resolving daily imbalances using thirdparty imbalance service provider falcon filed formal complaint march 2003 railroad commission texas claiming gulfterra texas imbalance penalties terms service preclude third parties offering hourly imbalance management services gulfterra texas system gulfterra texas filed response specifically denying falcons assertions requesting complaint denied railroad commission set case hearing beginning april 13 2004 city board public service san antonio filed intervention opposition falcons complaint gulfterra energy partners lp subsidiaries notes consolidated financial statements continued outcome rates regulatory matters cannot predicted certainty based information known date expect ultimate resolution matters material adverse effect financial position results operations cash flows new information becomes available relevant developments occur establish accruals appropriate joint ventures conduct portion business joint venture arrangements including cameron highway deepwater gateway poseidon joint ventures form construct operate finance development onshore offshore midstream energy businesses obligated make proportionate share additional capital contributions joint ventures extent unable satisfy obligations sources including proceeds credit arrangements operating lease longterm operating lease commitments associated wilson natural gas storage facility acquired april 2002 connection epn holding acquisition term natural gas storage facility base gas leases runs january 2008 subject certain conditions one optional renewal periods five years fair market rent time renewal also longterm operating lease commitments associated two ngl storage facilities texas acquired november 2002 connection san juan asset acquisition leases covering facilities expire 2006 2012 future minimum lease payments operating lease commitments december 31 2003 follows millions rental expense operating leases approximately 72 million 39 million years ended december 31 2003 2002 operating leases prior acquisition epn holding assets april 2002 matters result current circumstances generally surrounding energy sector creditworthiness several industry participants called question result general circumstances established internal group monitor exposure determine appropriate whether request prepayments letters credit collateral counterparties 12 accounting hedging activities majority commodity purchases sales relate sales oil natural gas associated production operations purchases sales natural gas associated pipeline operations sales natural gas liquids purchases sales gas associated processing plants gathering activities spot market forward market prices use futures forward contracts swaps limit exposure fluctuations commodity markets allow fixed cash flow stream gulfterra energy partners lp subsidiaries notes consolidated financial statements continued activities january 1 2001 adopted provisions sfas 133 accounting derivative instruments hedging activities derivative contracts place december 31 2000 therefore transition adjustment recorded financial statements 2003 2002 2001 entered cash flow hedges august 2002 entered derivative financial instrument hedge exposure 2003 changes natural gas prices relating gathering activities san juan basin anticipation acquisition san juan assets derivative financial swap 30000 mmbtu per day whereby receive fixed price 3525 per mmbtu pay floating price based san juan index august 2002 acquisition date november 27 2002 accounted derivative current earnings since qualify hedge accounting sfas 133 acquisition date 2002 recognized 04 million gain margin natural gas pipelines plants segment beginning acquisition date november 2002 accounting derivative cash flow hedge sfas 133 february august 2003 entered additional derivative financial instruments continue hedge exposure 2004 changes natural gas prices relating gathering activities san juan basin derivatives financial swaps 30000 mmbtu per day whereby receive average fixed price 423 per mmbtu pay floating price based san juan index december 31 2003 2002 fair value cash flow hedges liability 58 million 48 million market price dates higher hedge price year ended december 31 2003 reclassified approximately 98 million unrealized accumulated loss related derivatives accumulated comprehensive income decrease revenue ineffectiveness exists hedging relationship purchase sale prices based index volumes hedge transaction connection san juan asset purchase also acquired outstanding risk management positions chaco plant value ngl natural gas positions 05 million liability acquisition date amount included working capital adjustments purchase price positions expired december 2002 connection gulfterra alabama intrastate operations fixed price contracts specific customers sale predetermined volumes natural gas delivery established periods time entered cash flow hedges 2002 2003 offset risk increasing natural gas prices december 31 2003 fair value cash flow hedges asset approximately 77 thousand twelve months ended december 31 2003 reclassified approximately 218 thousand unrealized accumulated gain related derivatives accumulated comprehensive income earnings december 31 2002 fair value cash flow hedges asset 86 thousand year ended december 31 2002 reclassified loss 14 million comprehensive income earnings ineffectiveness exists hedging relationship purchase sale prices based index volumes hedge transaction beginning april 2002 connection epn holding acquisition swaps place interest indian basin processing plant hedge price received sale natural gas liquids hedges expired december 31 2002 recorded loss 163 thousand 2002 cash flow hedges ineffectiveness hedging relationship since sale prices based index hedge transaction 2003 entered additional derivative financial instruments hedge portion business exposure changes ngl prices 2003 2004 entered financial swaps 3500 barrels per day february june 2003 3200 barrels per day july 2003 4900 barrels per day august 2003 6000 barrels per day august 2003 september 2004 average fixed price received 049 per gallon 2003 047 per gallon 2004 pay monthly average floating price based opis average price month december 31 2003 fair value cash flow hedges liability 33 million twelve months ended december 31 gulfterra energy partners lp subsidiaries notes consolidated financial statements continued 2003 reclassified approximately 04 million unrealized accumulated loss related derivatives accumulated comprehensive income earnings january 2002 poseidon entered twoyear interest rate swap agreement fix variable libor based interest rate 75 million 185 million variable rate revolving credit facility 349 life swap prior april 2003 credit facility poseidon paid additional 150 libor rate resulting effective interest rate 499 hedged notional amount beginning april 2003 additional interest poseidon pays libor reduced resulting effective fixed interest rate 474 hedged notional amount interest rate swap expired january 9 2004 recognized reduction income 36 percent share poseidons realized loss interest rate swap 17 million twelve months ended december 31 2003 06 million earnings unconsolidated affiliates december 31 2002 fair value interest rate swap liability 14 million market interest rate lower hedge rate resulting accumulated comprehensive loss 14 million included 36 percent share liability 05 million reduction investment poseidon loss accumulated comprehensive income additionally recognized income 36 percent share poseidons realized loss 12 million twelve months ended december 31 2002 04 million earnings unconsolidated affiliates estimate entire 90 million unrealized losses included accumulated comprehensive income december 31 2003 reclassified accumulated comprehensive income reduction earnings next 12 months derivative financial instruments settled related amount accumulated comprehensive income recorded income statement operating revenues cost natural gas products interest debt expense depending item hedged effect reclassifying amounts income statement line items recording earnings period hedged price derivative financial instruments july 2003 achieve better mix fixed rate debt variable rate debt entered eightyear interest rate swap agreement provide floating interest rate 250 million 480 million 8 12 senior subordinated notes due 2011 swap agreement pay counterparty libor based interest rate plus spread 420 rate 155 december 31 2003 receive fixed rate 8 12 accounting derivative fair value hedge sfas 133 december 31 2003 fair value interest rate swap liability included noncurrent liabilities approximately 74 million fair value hedged debt decreased amount counterparties san juan hedging activities j aron company affiliate goldman sachs ubs warburg require collateral anticipate nonperformance counterparties june 2003 counterparty gulfterra alabama intrastate operations el paso merchant energy beginning august 2003 counterparty ubs warburg require collateral anticipate nonperformance counterparty ngl hedging activities indian basin chaco plants j aron company affiliate goldman sachs require collateral anticipate nonperformance counterparty poseidons hedging activity credit lyonnais poseidon require collateral anticipate nonperformance counterparty wachovia bank counterparty interest rate swap 8 12 notes require collateral anticipate nonperformance counterparty gulfterra energy partners lp subsidiaries notes consolidated financial statements continued 13 supplemental disclosures statements cash flows cash paid interest net amounts capitalized follows noncash investing financing activities excluded consolidated statements cash flows follows 14 major customers percentage revenue major customers follows 2003 major customers result san juan asset acquisition november 2002 also 2003 decreased activities affiliates el paso corporation including replacing monthtomonth arrangements previously el paso merchant energy similar arrangements third parties 2002 percentage increase revenue el paso merchant energy north america company el paso field services primarily due epn holding acquisition completed 2002 gulfterra energy partners lp subsidiaries notes consolidated financial statements continued 15 business segment information segments business units offer different services products managed separately since segment requires different technology marketing strategies segregated business activities four distinct operating segments natural gas pipelines plants oil ngl logistics natural gas storage platform services accounting policies individual segments described note 1 record intersegment revenues rates approximate market use performance cash flows formerly referred ebitda evaluate performance segments determine resources allocated develop strategic plans define performance cash flows earnings interest income taxes depreciation amortization adjustments historically lenders equity investors viewed performance cash flows measure indication ability generate sufficient cash meet debt obligations pay distributions believe shift investors evaluation regarding investments mlps put much focus performance mlp investment ability pay distributions reason disclose performance cash flows measure segments performance believe performance cash flows also useful investors allows evaluate effectiveness business segments operational perspective exclusive costs finance activities income taxes depreciation amortization none directly relevant efficiency operations measurement may comparable measurements used companies used substitute net income performance measures gulfterra energy partners lp subsidiaries notes consolidated financial statements continued operating results financial position reflect acquisitions san juan assets november 2002 epn holding assets april 2002 chaco plant remaining 50 percent interest already deepwater holdings october 2001 gtm texas february 2001 acquisitions accounted purchases therefore operating results acquired entities included prospectively purchase date following results periods ended december 31 1 represents predominately oil natural gas production activities well intersegment eliminations intersegment revenues along intersegment operating expenses consist normal course businesstype transactions operating segments record intersegment revenue elimination included nonsegment activity column remove intersegment transactions 2 revenue amount oil ngl logistics segment reduced 105 million reflect reclassification typhoon oil pipelines cost sales products see note 1 summary significant accounting policies discussion gulfterra energy partners lp subsidiaries notes consolidated financial statements continued reconciliation segment performance cash flows net income follows gulfterra energy partners lp subsidiaries notes consolidated financial statements continued 16 guarantor financial information may 2001 purchased general partners 101 percent nonmanaging interest owned twelve subsidiaries 8 million result acquisition subsidiaries equity investees wholly owned us december 31 2003 credit facility guaranteed subsidiaries excluding unrestricted subsidiaries arizona gas storage llc gulfterra arizona gas llc collateralized substantially assets addition senior notes senior subordinated notes jointly severally fully unconditionally guaranteed us subsidiaries excluding unrestricted subsidiaries december 31 2002 revolving credit facility gulfterra holding term credit facility senior secured term loan senior secured acquisition term loan guaranteed subsidiaries excluding unrestricted subsidiaries matagorda island area gathering system arizona gas storage llc gulfterra arizona gas llc collateralized general administrative services agreement substantially assets general partners one percent general partner interest addition december 31 2002 senior subordinated notes jointly severally fully unconditionally guaranteed us subsidiaries excluding unrestricted subsidiaries consolidating eliminations column condensed consolidating balance sheets eliminates investment consolidated subsidiaries intercompany payables receivables transactions subsidiaries consolidating eliminations column condensed consolidating statements income cash flows eliminates earnings consolidated affiliates nonguarantor subsidiaries year ended december 31 2003 consisted unrestricted subsidiaries arizona gas storage llc gulfterra arizona gas llc nonguarantor subsidiaries year ended december 31 2002 consisted argo quarter ended march 31 2002 gulfterra holding known epn holding subsidiaries owned epn holding assets equity interests gulfterra holding known epn holding quarters ended june 30 2002 september 30 2002 unrestricted subsidiaries quarter ended december 31 2002 nonguarantor subsidiaries periods consisted argo owned prince tlp result disposal prince tlp related overriding royalty interest april 2002 results operations net book value assets reflected discontinued operations statements income assets held sale balance sheets argo became guarantor subsidiaries gulfterra energy partners lp subsidiaries notes consolidated financial statements continued condensed consolidating statement income year ended december 31 2003 gulfterra energy partners lp subsidiaries notes consolidated financial statements continued condensed consolidating statement income year ended december 31 2002 1 nonguarantor subsidiaries consisted argo quarter ended march 31 2002 epn holding subsidiaries quarters ended june 30 2002 september 30 2002 unrestricted subsidiaries quarter ended december 31 2002 gulfterra energy partners lp subsidiaries notes consolidated financial statements continued condensed consolidating statement income year ended december 31 2001 1 nonguarantor subsidiaries consist argo formed august 2000 gulfterra energy partners lp subsidiaries notes consolidated financial statements continued condensed consolidating balance sheets december 31 2003 gulfterra energy partners lp subsidiaries notes consolidated financial statements continued condensed consolidating balance sheets december 31 2002 1 nonguarantor subsidiaries consisted argo quarter ended march 31 2002 epn holding subsidiaries quarters ended june 30 2002 september 30 2002 unrestricted subsidiaries quarter ended december 31 2002 gulfterra energy partners lp subsidiaries notes consolidated financial statements continued condensed consolidating statements cash flow year ended december 31 2003 gulfterra energy partners lp subsidiaries notes consolidated financial statements continued condensed consolidating statements cash flow year ended december 31 2002 1 nonguarantor subsidiaries consisted argo quarter ended march 31 2002 epn holding subsidiaries quarters ended june 30 2002 september 30 2002 unrestricted subsidiaries quarter ended december 31 2002 gulfterra energy partners lp subsidiaries notes consolidated financial statements continued condensed consolidated statements cash flow year ended december 31 2001 1 nonguarantor subsidiaries consist argo formed august 2000 gulfterra energy partners lp subsidiaries notes consolidated financial statements continued 17 supplemental oil natural gas information unaudited general footnote discusses oil natural gas production activities year 2001 years 2003 2002 presented since operations significant part business defined sfas 69 disclosures oil gas producing activities expect become significant future oil natural gas reserves following table represents net interest estimated quantities proved developed proved undeveloped reserves crude oil condensate natural gas changes quantities year end 2001 estimates reserves december 31 2001 made independent engineering consulting firm netherland sewell associates inc except prince field 2001 prepared el paso production company affiliate operator prince field net proved reserves estimated quantities crude oil natural gas geological engineering data demonstrate reasonable certainty recoverable future years known reservoirs existing economic operating conditions policy recognize proved reserves economic producibility supported actual production result proved reserves booked respect producing fields absence actual production proved developed reserves proved reserve volumes expected recovered existing wells existing equipment operating methods proved undeveloped reserves proved reserve volumes expected recovered new wells undrilled acreage existing wells significant expenditure required recompletion reference rules 410a2i ii iii 3 4 regulation sx detailed definitions proved reserves found secs website httpwwwsecgovdivisionscorpfinformsregsxhtmgas estimates reserve quantities based sound geological engineering principles nature still estimates subject substantial upward downward revision additional information regarding producing fields technology becomes available 1 includes overriding royalty interest proved reserves garden banks block 73 prince field 2 includes overriding royalty interest proved reserves 1341 mbbls oil 1659 mmcf natural gas prince field began production 2001 reserves included proved reserves prior 2001 consistent policy economic producibility supported actual production also increases estimated proved reserves relating producing properties primarily west delta 35 field actual production prince field 2001 37 mbbls oil 32 mmcf natural gas gulfterra energy partners lp subsidiaries notes consolidated financial statements continued following estimates total proved developed proved undeveloped reserves oil natural gas producing property december 31 2001 general estimates economically recoverable oil natural gas reserves future net revenue therefrom based upon number variable factors assumptions historical production subject properties assumed effects regulation governmental agencies assumptions concerning future oil natural gas prices future operating costs future plugging abandonment costs may vary considerably actual results estimates degree speculative classifications reserves attempts define degree speculation involved reasons estimates economically recoverable oil natural gas reserves attributable particular group properties classifications reserves based risk recovery estimates future net revenue expected therefrom prepared different engineers different times may vary substantially meaningfulness estimates highly dependent upon assumptions upon based estimates respect proved undeveloped reserves may developed produced future often based upon volumetric calculations upon analogy similar types reserves rather upon actual production history estimates based methods generally less reliable based actual production history subsequent evaluation reserves based upon production history result variations may substantial estimated reserves significant portion reserves based upon volumetric calculations future net cash flows standardized measure discounted future net cash flows relating proved oil natural gas reserves calculated presented accordance sfas 69 accordingly future cash inflows determined applying yearend oil natural gas prices adjusted fixed price contracts effect estimated share future production proved oil natural gas reserves average prices utilized calculation standardized measure discounted future net cash flows december 31 2001 1675 per barrel oil 262 per mcf natural gas actual future prices costs may materially higher lower future production development costs computed applying yearend costs future years taxable entity future income taxes provided prescribed 10 percent discount factor applied future net cash flows opinion standardized measure representative measure fair market value standardized measure presented proved oil natural gas reserves representative reserve value standardized measure intended assist financial statement users making comparisons companies table following amounts future production costs restated gulfterra energy partners lp subsidiaries notes consolidated financial statements continued include platform access fees paid platform segment see note 2 table discussion impact fees consolidated standardized measure discounted future net cash flows 1 future cash inflows include estimated future receipts overriding royalty interest prince field garden banks block 73 since overriding royalty interests participate production development costs fields include proved reserves production volumes future cash inflows data 2 future production costs include platform access fees paid oil natural gas production business affiliated entities included platform services segment platform access fees eliminated consolidated financial statements future platform access fees paid platform segment 4960 2001 consolidated basis standardized measure discounted future net cash flows 43789 2001 estimated future net cash flows proved developed proved undeveloped reserves december 31 2001 follows following principal sources change standardized measure gulfterra energy partners lp subsidiaries notes consolidated financial statements continued development exploration acquisition expenditures following table details certain information regarding costs incurred development exploration acquisition activities year ended december 31 year presented elected incur costs develop proved undeveloped reserves capitalized costs capitalized costs relating natural gas oil producing activities related accumulated depreciation depletion amortization follows december 31 results operations results operations producing activities follows december 31 1 production costs include platform access fees paid affiliated entities included platform services segment platform access fees approximately 10 million year presented eliminated consolidated financial statements gulfterra energy partners lp subsidiaries notes consolidated financial statements continued 18 supplemental quarterly financial information 1 since november 2002 acquired typhoon oil pipeline recognized revenue attributable using gross method means record revenues oil purchase customers index price less amount compensates us service record cost oil resell customers index price believe net presentation appropriate gross presentation consistent evaluate performance typhoon oil pipeline based review accounting literature believe generally accepted accounting principles permit us use net method accordingly presented results typhoon oil net periods reflect reclassification operating revenues reduced 488 million 731 million 698 million quarters ended march 31 june 30 september 30 2003 change affect operating income net income 2 result loss allocated common unitholders quarter ended december 31 2003 basic diluted earnings per common units gulfterra energy partners lp subsidiaries notes consolidated financial statements continued 1 operating revenues quarter ended december 31 2002 reduced 105 million reflect reclassification typhoon oil pipelines cost oil report independent auditors unitholders gulfterra energy partners lp board directors stockholders gulfterra energy company llc general partner opinion accompanying consolidated balance sheets related consolidated statements income comprehensive income changes accumulated comprehensive income loss partners capital cash flows present fairly material respects financial position gulfterra energy partners lp subsidiaries partnership december 31 2003 2002 results operations cash flows three years period ended december 31 2003 conformity accounting principles generally accepted united states america financial statements responsibility partnerships management responsibility express opinion financial statements based audits conducted audits statements accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements assessing accounting principles used significant estimates made management evaluating overall financial statement presentation believe audits provide reasonable basis opinion discussed note 2 consolidated financial statements partnership entered definitive agreement merge enterprise products partners lp discussed note 1 consolidated financial statements partnership changed method accounting asset retirement obligations reporting gains losses resulting extinguishment debt effective january 1 2003 discussed note 1 consolidated financial statements partnership changed method accounting impairment disposal long lived assets effective january 1 2002 pricewaterhousecoopers llp houston texas march 12 2004 el paso corporation exhibit list december 31 2003 exhibit identified filed part report exhibits incorporated reference prior filing designated exhibits designated incorporated herein reference prior filing indicated exhibits designated constitute management contract compensatory plan arrangement required filed exhibit report pursuant item 14c form 10k undertaking hereby undertake pursuant regulation sk item 601b paragraph 4iii furnish securities exchange commission upon request constituent instruments defining rights holders longterm debt consolidated subsidiaries filed herewith reason total amount securities authorized instruments exceed 10 percent total consolidated assets signatures pursuant requirements section 13 15d securities exchange act 1934 amended el paso corporation duly caused report signed behalf undersigned thereunto duly authorized 30th day september 2004 el paso corporation registrant douglas foshee douglas l foshee president chief executive officer pursuant requirements securities exchange act 1934 amended report signed following persons behalf el paso corporation capacities dates indicated exhibit index december 31 2003 exhibit identified filed part report exhibits incorporated reference prior filing designated exhibits designated incorporated herein reference prior filing indicated exhibits designated constitute management contract compensatory plan arrangement required filed exhibit report pursuant item 14c form 10kitem 15 exhibits financial statement schedules reports form 8k following documents filed part report 1 financial statements following consolidated financial statements included part ii item 8 report pricewaterhousecoopers llp report independent registered public accounting firm partners management committee midland cogeneration venture limited partnership completed integrated audit midland cogeneration venture limited partnership 2004 consolidated financial statements internal control financial reporting december 31 2004 audits december 31 2003 december 31 2002 financial statements accordance standards public company accounting oversight board united states opinions based audits presented consolidated financial statements opinion accompanying consolidated balance sheets related consolidated statements operations partners’ equity cash flows present fairly material respects financial position midland cogeneration limited partnership michigan limited partnership subsidiaries mcv december 31 2004 2003 results operations cash flows three years period ended december 31 2004 conformity accounting principles generally accepted united states america financial statements responsibility mcv’s management responsibility express opinion financial statements based audits conducted audits statements accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit financial statements includes examining test basis evidence supporting amounts disclosures financial statements assessing accounting principles used significant estimates made management evaluating overall financial statement presentation believe audits provide reasonable basis opinion explained note 2 financial statements effective april 1 2002 midland cogeneration venture limited partnership changed method accounting derivative hedging activities accordance derivative implementation group “dig” issue c16 internal control financial reporting also opinion management’s assessment included accompanying management’s report internal control financial reporting appearing item 9a mcv maintained effective internal control financial reporting december 31 2004 based criteria established internal control integrated framework issued committee sponsoring organizations treadway commission coso fairly stated material respects based criteria furthermore opinion mcv maintained material respects effective internal control financial reporting december 31 2004 based criteria established internal control integrated framework issued committee sponsoring organizations treadway commission coso mcv’s management responsible maintaining effective internal control financial reporting assessment effectiveness internal control financial reporting responsibility express opinions management’s assessment effectiveness mcv’s internal control financial reporting based audit conducted audit internal control financial reporting accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether effective internal control financial reporting maintained material respects audit internal control financial reporting includes obtaining understanding internal control financial reporting evaluating management’s assessment testing evaluating design operating effectiveness internal control performing procedures consider necessary circumstances believe audit provides reasonable basis opinions company’s internal control financial reporting process designed provide reasonable assurance regarding reliability financial reporting preparation financial statements external purposes accordance generally accepted accounting principles company’s internal control financial reporting includes policies procedures pertain maintenance records reasonable detail accurately fairly reflect transactions dispositions assets company ii provide reasonable assurance transactions recorded necessary permit preparation financial statements accordance generally accepted accounting principles receipts expenditures company made accordance authorizations management directors company iii provide reasonable assurance regarding prevention timely detection unauthorized acquisition use disposition company’s assets could material effect financial statements inherent limitations internal control financial reporting may prevent detect misstatements also projections evaluation effectiveness future periods subject risk controls may become inadequate changes conditions degree compliance policies procedures may deteriorate pricewaterhousecoopers llp detroit michigan february 25 2005 midland cogeneration venture limited partnership consolidated balance sheets december 31 thousands accompanying notes integral part statements midland cogeneration venture limited partnership consolidated statements operations years ended december 31 thousands accompanying notes integral part statements midland cogeneration venture limited partnership consolidated statements partners’ equity years ended december 31 thousands accompanying notes integral part statements midland cogeneration venture limited partnership consolidated statements cash flows years ended december 31 thousands accompanying notes integral part statements midland cogeneration venture limited partnership notes consolidated financial statements 1 partnership associated risks mcv organized construct operate combinedcycle gasfired cogeneration facility “facility” located midland michigan mcv formed january 27 1987 facility began commercial operation 1990 1992 mcv acquired outstanding common stock pvco corp previously inactive company mcv pvco corp entered partnership agreement form mcv gas acquisition general partnership “mcv gagp” purpose buying selling natural gas spot market transactions involving natural gas activities pvco corp mcv gagp dissolved january 30 2004 july 2 2004 respectively due inactivity facility net electrical generating capacity approximately 1500 mw approximately 15 million pounds process steam capacity per hour mcv entered three principal energy sales agreements mcv contracted supply 1240 mw electric capacity “contract capacity” consumers energy company “consumers” power purchase agreement “ppa” resale customers 2025 ii supply electricity steam dow chemical company “dow” 2008 2015 respectively steam electric power agreement “sepa” iii supply steam dow corning corporation “dcc” steam purchase agreement “spa” 2011 time mcv enters sales agreements sale excess capacity andor energy available mcv’s internal use obligations ppa sepa spa results operations primarily dependent successfully operating facility near contractual capacity levels consumers’ ability perform obligations ppa sales pursuant ppa historically accounted 90 mcv’s revenues ppa permits consumers certain conditions reduce capacity energy charges payable mcv andor receive refunds capacity energy charges paid mcv michigan public service commission “mpsc” permit consumers recover customers capacity energy charges specified ppa “regulatoryout” provision september 15 2007 however capacity charge may reduced average capacity rate 377 cents per kilowatthour available contract capacity notwithstanding “regulatoryout” provision consumers mcv required support defend terms ppa facility qualifying cogeneration facility “qf” originally certified federal energy regulatory commission “ferc” public utility regulatory policies act 1978 amended “purpa” order maintain qf status certain operating efficiency standards must maintained calendaryear basis certain ownership limitations must met case toppingcycle generating plant facility applicable operating standard requires portion total energy output put useful purpose facilitating production power “thermal percentage” least 5 addition facility must achieve purpa efficiency standard sum useful power output plus onehalf useful thermal energy output divided energy input “efficiency percentage” least 45 facility maintains thermal percentage 15 higher required efficiency percentage reduced 425 since 1990 facility achieved applicable thermal efficiency percentages twelve months ended december 31 2004 facility achieved thermal percentage 156 efficiency percentage 476 loss qf status could among things cause mcv lose rights purpa sell power facility consumers’ “avoided cost” subject mcv additional federal state regulatory requirements facility wholly dependent upon natural gas fuel supply substantial portion facility’s operating expenses consist costs natural gas mcv recognizes existing gas contracts sufficient satisfy anticipated gas needs term ppa assurance given availability price natural gas expiration existing gas contracts midland cogeneration venture limited partnership notes consolidated financial statements continued addition extent costs associated production electricity rise faster energy charge payments mcv’s financial performance negatively affected extent impact depend upon amount average energy charge payable ppa based upon costs incurred consumers’ coalfired plants upon amount energy scheduled consumers delivery ppa however given unpredictability factors overall economic impact upon mcv changes energy charges payable ppa future fuel costs new existing contracts cannot accurately predicted state federal level efforts continue restructure electric industry significant issue mcv potential future regulatory denial recovery consumers customers market ppa costs consumers pays mcv state level mpsc entered series orders june 1997 february 1998 collectively “restructuring orders” mandating utilities “wheel” thirdparty power utilities’ customers thus permitting customers choose power provider mcv well others filed appeal michigan court appeals protect denial recovery consumers ppa charges michigan court appeals found restructuring orders unequivocally disallow recovery consumers therefore mcv’s issues ripe appellate review actual controversy regarding recovery costs could occur 2008 earliest june 2000 state michigan enacted legislation among things states restructuring orders voluntarily implemented consumers compliance legislation enforceable mpsc legislation provides rights parties existing contracts utilities like consumers qfs like mcv including rights ppa charges recovered customers utilities abrogated diminished permits utilities securitize certain stranded costs including ppa charges 1999 us district court granted summary judgment mcv declaring restructuring orders preempted federal law extent prohibit consumers recovering customers charge avoided costs “stranded costs” paid mcv purpa pursuant ppa 2001 united states court appeals “appellate court” vacated us district court’s 1999 summary judgment ordered case dismissed based upon finding actual case controversy existed adjudication parties appellate court determined parties’ dispute hypothetical time qfs’ including mcv claims premised speculation order might interpreted mpsc future two significant issues could affect mcv’s future financial performance price natural gas consumers’ abilityobligation pay ppa charges natural gas prices historically volatile presently consensus among forecasters price range future prices natural gas even approved resource conservation agreement reduced dispatch agreement gas prices continue present levels increase economics operating facility may adversely affected consumers’ abilityobligation pay ppa charges may affected mpsc order denying consumers recovery ratepayers issue likely addressed timeframe 2007 beyond mcv continues monitor participate matters appropriate evaluate potential impacts cash flows recoverability carrying value property plant equipment mcv management cannot time predict impact outcome matters 2 significant accounting policies preparation financial statements conformity accounting principles generally accepted united states america requires management make estimates assumptions affect reported amounts assets liabilities disclosure contingent assets liabilities date financial statements reported amounts revenues expenses reporting period actual results could differ estimates following discussion mcv’s significant accounting policies midland cogeneration venture limited partnership notes consolidated financial statements continued principles consolidation consolidated financial statements included accounts mcv whollyowned subsidiaries pvco corp mcv gagp previously material transactions balances among entities comprise mcv eliminated consolidated financial statements 2004 dissolution whollyowned subsidiaries impact financial position results operations revenue recognition mcv recognizes revenue sale variable energy fixed energy delivered capacity installment revenues recognized based plant availability contractual arrangements fuel costs mcv’s fuel costs associated securing natural gas transportation storage services necessary generate electricity steam facility costs recognized income statement based upon actual volumes burned produce delivered energy addition mcv engages certain cost mitigation activities offset fixed charges mcv incurs activities gains losses resulting activities resulted net gains approximately 67 million 77 million 39 million years ended 2004 2003 2002 respectively net gains reflected component fuel costs july 2000 response rapidly escalating natural gas prices since consumers’ electric rates frozen mcv entered series transactions consumers whereby consumers agreed reduce mcv’s dispatch level mcv agreed share consumers savings realized generate electricity “dispatch mitigation” january 1 2004 dispatch mitigation ceased consumers began dispatching mcv pursuant 915 mw settlement 325 mw settlement “availability caps” provision ie minimum dispatch 1100 mw offpeak “forced dispatch” 2004 mcv consumers entered resource conservation agreement “rca” reduced dispatch agreement “rda” among things provides consumers economically dispatch mcv certain conditions met dispatch expected reduce electric production occurring forced dispatch well decrease gas consumption mcv rca provides consumers right first refusal purchase market prices gas conserved rca rda provide sharing savings realized generate electricity rca rda approved order mpsc january 25 2005 mcv consumers accepted terms mpsc order making rca rda effective january 27 2005 mpsc order subject appeal parties mcv management cannot predict final outcome appeal awaiting approval order effective october 23 2004 mcv consumers entered interim dispatch mitigation program energy dispatch 1100 mw 1240 mw contract capacity ppa interim program structured similarly rca rda terminated january 27 2005 effective date rca rda twelve months ended december 31 2004 2003 2002 mcv estimates programs resulted net savings approximately 16 million 130 million 25 million portion realized reduced maintenance expenditures future years accounts receivable accounts receivable accounts receivablerelated parties recorded billed amount bear interest mcv evaluates need allowance doubtful accounts using mcv’s best estimate amount probable credit losses december 31 2004 2003 allowance provided since typically receivables collected within 30 days month end midland cogeneration venture limited partnership notes consolidated financial statements continued inventory mcv’s inventory natural gas stated lower cost market valued using lastin firstout “lifo” method inventory includes costs purchased gas variable transportation storage amount reserve reduce inventories firstin firstout “fifo” basis lifo basis december 31 2004 2003 103 million 84 million respectively inventory cost determined fifo basis approximates current replacement cost materials supplies materials supplies stated lower cost market using weighted average cost method majority mcv’s materials supplies considered replacement parts mcv’s facility depreciation original plant equipment pipeline valued cost constructed assets asset transfer price purchased contributed assets depreciated using straightline method estimated useful life 35 years term ppa except hot gas path components gtgs primarily depreciated 25year life plant construction additions since commercial operations 1990 depreciated using straightline method remaining life plant currently 22 years major renewals replacements extend useful life plant equipment capitalized maintenance repairs expensed incurred major equipment overhauls capitalized amortized next equipment overhaul personal property depreciated using straightline method estimated useful life 5 15 years cost assets related accumulated depreciation removed accounts sold retired resulting gain loss reflected operating income federal income tax mcv subject federal state income taxes partnership earnings taxed directly individual partner statement cash flows liquid investments purchased maturity three months less time purchase considered current cash equivalents fair value financial instruments carrying amounts cash equivalents shortterm investments approximate fair value short maturity instruments mcv’s shortterm investments made investment securities heldtomaturity december 31 2004 december 31 2003 original maturity dates approximately one year less unique nature negotiated financing obligation discussed note 6 makes unnecessary estimate fair value owner participants’ underlying debt equity instruments supporting financing obligation since sfas 107 “disclosures fair value financial instruments” require fair value accounting lease obligation accounting derivative instruments hedging activities effective january 1 2001 mcv adopted sfas 133 “accounting derivative instruments hedging activities” issued june 1998 amended sfas 137 “accounting derivative instruments hedging activities deferral effective date sfas 133” sfas 138 “accounting certain derivative instruments certain hedging activities midland cogeneration venture limited partnership notes consolidated financial statements continued amendment fasb statement 133” sfas 149 “amendment statement 133 derivative instruments hedging activity collectively referred “sfas 133” sfas 133 establishes accounting reporting standards requiring every derivative instrument recorded balance sheet either asset liability measured fair value sfas 133 requires changes derivative’s fair value recognized currently earnings unless specific hedge accounting criteria met special accounting qualifying hedges cases allows derivative’s gains losses offset related results hedged item income statement permits recognition hedge results comprehensive income requires company formally document designate assess effectiveness transactions receive hedge accounting electric sales agreements mcv believes electric sales agreements currently qualify derivatives sfas 133 due lack active energy market defined sfas 133 state michigan transportation cost deliver power contracts closest active energy market cinergy hub ohio record fair value contracts balance sheet active energy market emerges mcv intends apply normal purchase normal sales exception sfas 133 electric sales agreements extent exception applicable natural gas supply contracts mcv management believes longterm natural gas contracts contain volume optionality qualify sfas 133 normal purchases normal sales exception therefore contracts currently recognized fair value balance sheet fasb issued dig issue c16 became effective april 1 2002 regarding natural gas commodity contracts combine option component forward component guidance requires either entire contract accounted derivative components contract separated two discrete contracts first alternative entire contract considered together would qualify normal purchases sales exception revised guidance second alternative newly established forward contract could qualify normal purchases sales exception option contract would treated derivative sfas 133 changes fair value recorded earnings april 1 2002 mcv nine longterm gas contracts contained option forward component longer accounted normal purchases sales exception mcv began marktomarket accounting nine contracts earnings january 31 2005 four contracts original nine contracts contained option forward component remain effect addition result implementing rca rda effective january 27 2005 mcv determined effective date rca rda additional nine long term contracts total 13 longer accounted normal purchases sales exception per sfas 133 result additional marktomarket activity 2005 beyond mcv expects future earnings volatility remaining long term gas contracts contain volume optionality well long term gas contracts rca rda require marktomarket recognition quarterly basis based natural gas prices beginning april 2002 mcv recorded 581 million gain cumulative effect accounting change april 2002 december 2004 mcv recorded additional net marktomarket loss 23 million gas contracts cumulative marktomarket gain december 31 2004 558 million recorded current noncurrent derivative asset balance sheet detailed assets reverse remaining life gas contracts ranging 2005 2007 twelve months ended december 31 2004 2003 mcv recorded “fuel costs” losses 192 million 50 million respectively net marktomarket adjustments midland cogeneration venture limited partnership notes consolidated financial statements continued associated contracts addition december 31 2004 2003 mcv recorded “derivative assets” current assets amount 314 million 569 million respectively periods recorded “derivative assets noncurrent” assets amount 243 million 181 million respectively representing marktomarket value longterm natural gas contracts natural gas supply futures options manage market risks associated volatility natural gas prices mcv maintains gas hedging program mcv enters natural gas futures contracts option contracts counter swap transactions “otc swaps” order hedge unfavorable changes market price natural gas future months gas expected needed financial instruments utilized principally secure anticipated natural gas requirements necessary projected electric steam sales lock sales prices natural gas previously obtained order optimize mcv’s existing gas supply storage transportation arrangements financial instruments derivatives sfas 133 contracts utilized secure anticipated natural gas requirements necessary projected electric steam sales qualify cash flow hedges sfas 133 since hedge price risk associated cost natural gas mcv also engages cost mitigation activities offset fixed charges mcv incurs operating facility cost mitigation activities include use futures options contracts purchase andor sell natural gas maximize use transportation storage contracts determined needed facility operation although cost mitigation activities serve offset fixed monthly charges cost mitigation activities considered normal course business mcv qualify hedges sfas 133 therefore resulting marktomarket gains losses cost mitigation activities flowed mcv’s earnings cash deposited broker margin account time futures options contracts initiated change market value contracts requires adjustment margin account balances margin account balance december 31 2004 2003 recorded current asset “broker margin accounts prepaid expenses” amount 14 million 41 million respectively twelve months ended december 31 2004 mcv recognized comprehensive income unrealized 345 million increase futures contracts otc swaps hedges forecasted purchases plant use market priced gas resulted net 658 million gain comprehensive income december 31 2004 balance represents natural gas futures options otc swaps maturities ranging january 2005 december 2009 334 million gain expected reclassified earnings within next twelve months mcv also recorded december 31 2004 636 million current derivative asset “derivative assets” representing marktomarket gain natural gas futures anticipated projected electric steam sales accounted hedges addition twelve months ended december 31 2004 mcv recorded net 365 million gain earnings hedging activities related mcv natural gas requirements facility operations net 18 million gain earnings cost mitigation activities twelve months ended december 31 2003 mcv recognized unrealized 50 million increase comprehensive income futures contracts hedges forecasted purchases plant use market priced gas resulted 313 million gain balance comprehensive income december 31 2003 december 31 2003 mcv recorded 299 million current derivative asset “derivative assets” twelve months ended december 31 2003 mcv recorded net 350 million gain earnings hedging activities related mcv natural gas requirements facility operations net 10 million gain earnings cost mitigation activities midland cogeneration venture limited partnership notes consolidated financial statements continued new accounting standard 2003 emerging issues task force “eitf” issued eitf 031 “the meaning otherthantemporary impairment it’s application certain investments” eitf 031 addresses determine meaning otherthantemporary impairment certain debt equity securities measurement impairment loss accounting disclosure considerations subsequent recognition otherthantemporary impairment various sections eitf 031 became effective various times 2004 mcv adopted guidance expect application materially affect financial position results operations since mcv’s investments approximate fair value due short maturity permitted investments 3 restricted investment securities heldtomaturity noncurrent restricted investment securities heldtomaturity carrying amounts approximate fair value short maturity instruments consist following december 31 thousands 4 accounts payable accrued liabilities accounts payable accrued liabilities consist following december 31 thousands 5 gas supplier funds deposit pursuant individual gas contract terms counterparties deposit amounts letters credit may required one party based upon net amount exposure net amount exposure vary changes market prices credit provisions various factors collateral paid received posted one party based net amount exposure interest earned funds deposit december 31 2004 mcv supplying credit support two gas suppliers one form letter credit amount 24 million cash deposit amount 73 million december 31 2004 mcv holding 196 million cash deposit two mcv’s brokers addition december 31 2004 mcv also holding letters credit totaling 2086 million two gas suppliers 1840 million letter credit el paso corporation “el paso” related party midland cogeneration venture limited partnership notes consolidated financial statements continued 6 longterm debt longterm debt consists following december 31 thousands financing obligation june 1990 mcv obtained permanent financing facility entering sale leaseback agreements “overall lease transaction” lessor group related substantially mcv’s fixed assets proceeds financing used retire borrowings outstanding existing loan commitments make capital distribution partners retire portion notes issued mcv mec development corporation “mdc” connection transfer certain assets mdc mcv accordance sfas 98 “accounting leases” sale leaseback transaction accounted financing arrangement financing obligation utilizes effective interest rate method based minimum lease payments required end basic lease term 2015 management’s estimate additional anticipated obligations end basic lease term effective interest rate remainder basic lease term approximately 94 terms overall lease transaction mcv sold undivided interests fixed assets facility approximately 23 billion five separate owner trusts “owner trusts” established benefit certain institutional investors “owner participants” us bank national association formerly known state street bank trust company serves owner trustee “owner trustee” owner trusts leases undivided interests facility behalf owner trusts mcv initial term 25 years cms midland holdings company “cms holdings” currently wholly owned subsidiary consumers acquired 35 indirect equity interest facility purchase interest one owner trusts overall lease transaction requires mcv achieve certain rent coverage ratios financial tests prior distribution partners generally financial tests become restrictive passage time mcv restricted making permitted investments incurring permitted indebtedness specified overall lease transaction overall lease transaction also requires filing certain periodic operating financial reports notification lessors events constituting material adverse change significant litigation governmental investigation change status qualifying facility ferc proceedings court decisions among others notification approval required plant modification new business activities significant changes defined addition mcv agreed indemnify various parties sale leaseback transaction expenses environmental claims asserted certain federal state taxes imposed facility defined overall lease transaction terms overall lease transaction refinancing taxexempt bonds approximately 250 million transaction costs liability mcv recorded deferred cost financing costs incurred issuance debt deferred amortized using interest method remaining portion 25year lease term deferred financing costs approximately 12 million 14 million 15 million amortized years 2004 2003 2002 respectively midland cogeneration venture limited partnership notes consolidated financial statements continued interest fees incurred related longterm debt arrangements 2004 2003 2002 1034 million 1119 million 1183 million respectively interest fees paid 2004 2003 2002 1086 million 1154 million 1221 million respectively minimum payments due longterm debt arrangements next five years thousands revolving credit agreement mcv also entered working capital line “working capital facility” expires august 27 2005 terms existing agreement mcv borrow 500 million commitment form shortterm borrowings letters credit collateralized mcv’s natural gas inventory earned receivables given time borrowings letters credit limited amount borrowing base defined 90 earned receivables 50 natural gas inventory capped 15 million mcv utilize working capital facility year 2004 except letters credit associated normal business practices december 31 2004 mcv 476 million available working capital facility december 31 2004 mcv’s borrowing base capped maximum amount available 500 million mcv outstanding letters credit amount 24 million mcv believes amounts available working capital facility along available cash reserves sufficient meet working capital shortfalls might occur near term intercreditor agreement mcv also entered intercreditor agreement owner trustee working capital lender us bank national association collateral agent “collateral agent” senior subordinated indenture trustees terms agreement mcv required deposit revenues derived operation facility collateral agent purposes paying operating expenses rent addition funds required pay construction modification costs secure future rent payments december 31 2004 mcv deposited 1382 million reserve account reserve account maintained less 40 million 137 million debt portion next succeeding basic rent payment whichever greater excess funds reserve account periodically transferred mcv agreement also contains provisions governing distribution revenues rents due overall lease transaction establishes priority payment among owner trusts creditors owner trusts creditors mcv partnership midland cogeneration venture limited partnership notes consolidated financial statements continued 7 commitments agreements mcv entered numerous commitments agreements related facility principal agreements summarized follows power purchase agreement mcv consumers executed ppa sale consumers minimum amount electricity subject capacity requirements dow permissible electricity purchasers consumers right terminate andor withhold payment ppa facility fails achieve certain operating levels mcv fails provide adequate fuel assurances event early termination ppa mcv would maximum liability approximately 270 million ppa terminated 12th 24th years term agreement 35 years commercial operation date yeartoyear thereafter steam electric power agreement mcv dow executed sepa sale dow certain minimum amounts steam electricity dow’s facilities sepa terminated consumers fulfill mcv’s commitments provided backup steam electric power agreement mcv required pay dow termination fee calculated time ranging minimum 60 million maximum 85 million agreement provides sale dow steam electricity produced facility terms 25 years 15 years respectively commencing commercial operation date yeartoyear thereafter steam purchase agreement mcv dcc executed spa sale dcc certain minimum amounts steam use dcc midland site steam sales spa commenced july 1996 termination agreement prior expiration requires terminating party pay party percentage future revenues would realized initial term 15 years fulfilled percentage future revenues payable 50 termination occurs prior fifth anniversary commercial operation date 3313 termination occurs fifth anniversary agreement term agreement 15 years commercial operation date steam deliveries contract yeartoyear thereafter gas supply agreements mcv entered gas purchase agreements various producers supply natural gas current contracted volume totals 238531 mmbtu per day annual average 2005 january 1 2005 gas contracts us suppliers provide purchase 173336 mmbtu per day gas contracts canadian suppliers provide purchase 65195 mmbtu per day contracts require mcv pay minimum amount natural gas per year whether taken estimated minimum commitments contracts based current long term prices gas years 2005 2009 3846 million 4021 million 4367 million 3588 million 3240 million respectively portion payments may utilized future years offset cost quantities natural gas taken minimum amounts gas transportation agreements mcv entered firm natural gas transportation agreements various pipeline companies agreements require mcv pay certain reservation charges order reserve transportation capacity midland cogeneration venture limited partnership notes consolidated financial statements continued mcv incurred reservation charges 2004 2003 2002 355 million 348 million 351 million respectively estimated minimum reservation charges required agreements years 2005 2009 343 million 300 million 216 million 216 million 216 million respectively projections based current commitments gas turbine service agreements service agreement amended alstom commenced january 1 1990 set expire upon earlier completion sixth series major gtg inspections december 31 2009 alstom sold mcv initial inventory spare parts gtgs provided qualified service personnel supporting staff assist mcv perform scheduled inspections gtgs repair gtgs mcv’s request service agreement terminated cause mcv february 2004 alstom disputed mcv’s right terminate cause parties settled dispute agreement terminated february 2004mcv maintenance service parts agreement general electric international inc “geii” commenced july 1 2004 “geii agreement” geii provide maintenance services hot gas path parts mcv’s twelve gtgs including providing initial inventory spare parts gtgs providing qualified service personnel supporting staff assist mcv perform scheduled inspections gtgs repair gtgs mcv’s request terms conditions similar mcv alstom service agreement described geii agreement cover four rounds major gtg inspections expected completed year 2015 savings mcv compared service agreement alstom mcv make monthly payments life contract totaling approximately 207 million subject escalations based defined indices geii agreement terminated either party cause convenience termination convenience occur buy amount paid terminating party payments ranging approximately 190 million 9 million based upon number operating hours utilized since commencement geii agreement steam turbine service agreement mcv entered nine year steam turbine maintenance agreement general electric company effective january 1 1995 designed improve unit reliability increase availability minimize unanticipated maintenance costs addition contract includes performance incentives penalties based length scheduled outage number forced outages calendar year effective february 1 2004 mcv ge amended contract extend term august 31 2007 mcv continue making monthly payments life contract total 223 million subject escalation based defined indices parties certain termination rights without incurring penalties damages termination upon termination mcv liable payment services rendered parts provided prior termination site lease december 1987 mcv leased land facility located consumers “site lease” mcv consumers amended restated site lease reflect creation five separate undivided interests site lease june 1 1990 pursuant overall lease transaction mcv assigned undivided interests site lease owner trustees turn subleased undivided interests back mcv five separate site subleases site lease term commenced december 29 1987 ends december 31 2035 including two renewal options five years rental site lease 6 million per annum including two fiveyear renewal terms midland cogeneration venture limited partnership notes consolidated financial statements continued 8 contingencies property taxes 1997 mcv filed property tax appeal city midland michigan tax tribunal contesting mcv’s 1997 property taxes subsequently mcv filed appeals contesting property taxes tax years 1998 2004 michigan tax tribunal trial held tax years 19972000 appeals tax years 20012004 held abeyance january 23 2004 michigan tax tribunal issued decision mcv’s tax appeal city midland tax years 1997 2000 issued several orders correcting errors initial decision together “mtt decision” mcv management estimated mtt decision result refund mcv tax years 1997 2000 least approximately 353 million taxes plus 96 million interest december 31 2004 mtt decision appealed michigan appellate court city midland mcv filed crossappeal michigan appellate court mcv management cannot predict outcome legal proceedings mcv recognized stated refunds net approximately 161 million deferred expenses earnings time nox allowances united states environmental protection agency “us epa” approved state michigan’s state implementation plan “sip” includes interstate nox budget allowance trading program administered us epa beginning 2004 nox allowance permits source emit one ton nox seasonal control period 2004 may 31 september 30 nox allowances may bought sold unused allowances may “banked” future use certain limitations mcv estimates excess nox allowances sell program consumers given notice mcv believes ownership nox allowances program belong least part consumers mcv initiated dispute resolution process pursuant ppa resolve issue parties entered standstill agreement deferring resolution dispute however either party may terminate standstill agreement time reinstate ppa’s dispute resolution provisions mcv management cannot predict outcome issue december 31 2004 mcv sold 1200 tons 2004 allowances 27 million recorded “accounts payable accrued liabilities” pending resolution ownership credits environmental issues july 12 2004 michigan department environmental quality “deq” air quality division issued mcv “letter violation” asserting mcv violated air use permit install 20902 “pti” exceeding carbon monoxide emission limit unit 14 gtg duct burner failing maintain certain records required format july 13 2004 deq water division issued mcv “notice letter” asserting mcv violated national pollutant discharge elimination system permit discharging heated process waste water storm water system failure document inspections minor infractions “alleged npdes violations” mcv declared duct burners unavailable operational use reduces generation capability facility approximately 100 mw assessing duct burner issue begun corrective action address deq’s assertions mcv disagrees certain deq’s assertions mcv filed responses deq letters july august 2004 december 13 2004 deq informed mcv pursuing escalated enforcement action mcv regarding alleged violations mcv’s pti deq also stated alleged violations deemed federally significant placed mcv united states environmental protection agency’s high priority violators list “hpvl” deq mcv pursuing voluntary settlement matter satisfy state federal requirements remove mcv hpvl settlement likely involve fine midland cogeneration venture limited partnership notes consolidated financial statements continued deq time stated fine seek impose time mcv management cannot predict financial impact outcome issues however mcv believes resolved issues associated alleged npdes violations expect mdeq actions npdes matter 9 voluntary severance program july 2004 mcv announced voluntary severance program “vsp” employees union nonunion employees subject certain eligibility requirements vsp entitled participating employees upon termination lump sum payment based upon number years service maximum 52 weeks wages nineteen employees elected participate vsp mcv recorded 17 million severance costs “operating expenses” related nineteen employees 10 retirement benefits postretirement health care plans 1992 mcv established defined cost postretirement health care plans “plans” cover fulltime employees excluding key management plans provide health care credits utilized purchase medical plan coverage pay qualified health care expenses participants become eligible benefits retire attainment age 65 upon qualified disability retirement 10 years service retire age 55 older plans granted retroactive benefits employees hired prior january 1 1992 prior service cost amortized expense fiveyear period mcv annually funds current year service interest cost well amortization prior service cost qualified nonqualified trusts mcv accounts retiree medical benefits accordance sfas 106 “employers accounting postretirement benefits pensions” standard required full accrual costs years employee renders service mcv date full eligibility accumulated benefit obligation plans 49 million december 31 2004 33 million december 31 2003 measurement date plans december 31 2004 medicare prescription drug improvement modernization act 2003 “act” signed law december 2003 act expanded medicare include first time coverage prescription drugs december 31 2003 based upon fasb staff position sfas 1061 “employers accounting postretirement benefits pensions” mcv elected defer financial recognition legislation issuance final accounting guidance final sfas 1062 issued second quarter 2004 supersedes sfas 1061 mcv adopted period adoption standard impact mcv’s financial position mcv consider plans actuarially equivalent plans benefits provided eligible participants annual ongoing nature readily exhaustible lumpsum amount available use discretion participant midland cogeneration venture limited partnership notes consolidated financial statements continued following table reconciles change plans’ benefit obligation change plan assets reflected balance sheet december 31 thousands net periodic postretirement health care cost years ending december 31 included following components thousands assumed health care cost trend rates significant effect amounts reported health care plans onepercentagepoint change assumed health care cost trend rates would following effects thousands midland cogeneration venture limited partnership notes consolidated financial statements continued assumptions used accounting postretirement health care plan follows longterm rate return plan assets established based mcv’s expectations asset returns investment mix plan reliance historical asset returns plans expected returns various asset categories blended derive one longterm assumption plan assets citizens bank appointed trustee “trustee” plan trustee serves investment consultant responsibility providing financial information general guidance mcv benefits committee trustee shall invest assets plan separate investment options accordance instructions communicated trustee time mcv benefit committee mcv benefits committee fiduciary investment selection responsibility plan mcv benefits committee consists mcv officers excluding president chief executive officer mcv target allocation 80 equities 20 debt instruments investments emphasis total growth return moderate risk level mcv benefits committee reviews performance plan investments quarterly based longterm investment horizon applicable benchmarks rebalancing investment portfolio discretion mcv benefits committee mcv’s plan’s weightedaverage asset allocations asset category follows december 31 contributions mcv expects contribute approximately 4 million plan 2005 retirement savings plans mcv sponsors defined contribution retirement plan covering employees terms plan mcv makes contributions plan either five ten percent employee’s eligible annual compensation dependent upon employee’s age mcv also sponsors 401k savings plan employees contributions costs plan based matching employee’s savings maximum level 2004 2003 2002 mcv contributed 14 million 13 million 12 million respectively plans supplemental retirement benefits mcv provides supplemental retirement postretirement health care excess benefit plans key management plans qualified plans internal revenue code therefore earnings trusts maintained mcv fund plans taxable partners trust assets included assets mcv 11 partners’ equity related party transactions following table summarizes nature amount mcv’s partner’s equity interest profits losses mcv december 31 2004 nature amount related party midland cogeneration venture limited partnership notes consolidated financial statements continued transactions agreements existed partners affiliates december 31 2004 2003 2002 twelve month periods ended december 31 thousands footnotes partners’ equity related party transactions 1 alanna’s capital stock pledged secure mcv’s obligation lease overall lease transaction documents el paso corporation exhibit list december 31 2004 exhibit identified filed part report exhibits incorporated reference prior filing designated “” exhibits designated incorporated herein reference prior filing indicated exhibits designated “” constitute management contract compensatory plan arrangement required filed exhibit report pursuant item 14c form 10k undertaking hereby undertake pursuant regulation sk item 601b paragraph 4 iii furnish securities exchange commission upon request constituent instruments defining rights holders longterm debt consolidated subsidiaries filed herewith reason total amount securities authorized instruments exceed 10 percent total consolidated assets signatures pursuant requirements section 13 15d securities exchange act 1934 amended el paso corporation duly caused report signed behalf undersigned thereunto duly authorized th day march 2005 el paso corporation registrant douglas l foshee douglas l foshee president chief executive officer pursuant requirements securities exchange act 1934 amended report signed following persons behalf el paso corporation capacities dates indicated el paso corporation exhibit index december 31 2004 exhibit identified filed part report exhibits incorporated reference prior filing designated “” exhibits designated incorporated herein reference prior filing indicated exhibits designated “” constitute management contract compensatory plan arrangement required filed exhibit report pursuant item 14c form 10knanitem 15 exhibits financial statement schedules following documents filed part report 1 financial statements following consolidated financial statements included part ii item 8 report exhibit index follows signature page report hereby incorporated herein reference sets forth list exhibits filed herewith includes identifies management contracts compensatory plans arrangements required filed exhibits form 10k item 601 b10iii regulation sk undertaking hereby undertake pursuant regulation sk item 601b paragraph 4 iii furnish securities exchange commission upon request constituent instruments defining rights holders longterm debt consolidated subsidiaries filed herewith reason total amount securities authorized instruments exceed 10 percent total consolidated assets signatures pursuant requirements section 13 15d securities exchange act 1934 el paso corporation duly caused report signed behalf undersigned thereunto duly authorized 28th day february 2007 el paso corporation douglas l foshee douglas l foshee president chief executive officer pursuant requirements securities exchange act 1934 report signed following persons behalf el paso corporation capacities dates indicated el paso corporation exhibit index december 31 exhibit identified filed part report exhibits filed report designated “” exhibits designated incorporated herein reference prior filing indicated exhibits designated “” constitute management contract compensatory plan arrangementitem 15 exhibits financial statement schedules following documents filed part report 1 financial statements following consolidated financial statements included part ii item 8 report page reports independent registered public accounting firms consolidated statements income consolidated balance sheets consolidated statements cash flows consolidated statements stockholders’ equity consolidated statements comprehensive income notes consolidated financial statements 2 financial statement schedules supplementary information required submitted schedule ii valuation qualifying accounts 3 exhibits exhibit index follows signature page report hereby incorporated herein reference sets forth list exhibits filed herewith includes identifies management contracts compensatory plans arrangements required filed exhibits form 10k item 601 b10iii regulation sk undertaking hereby undertake pursuant regulation sk item 601b paragraph 4 iii furnish securities exchange commission upon request constituent instruments defining rights holders longterm debt consolidated subsidiaries filed herewith reason total amount securities authorized instruments exceed 10 percent total consolidated assets signatures pursuant requirements section 13 15d securities exchange act 1934 el paso corporation duly caused report signed behalf undersigned thereunto duly authorized 28th day february 2008 pursuant requirements securities exchange act 1934 report signed following persons behalf el paso corporation capacities dates indicated el paso corporation exhibit index december 31 2007 exhibit identified filed part report exhibits filed report designated “” exhibits designated incorporated herein reference prior filing indicated exhibits designated “” constitute management contract compensatory plan arrangementitem 15 exhibits financial statement schedules following documents filed part report 1 financial statements following consolidated financial statements included part ii item 8 report exhibit index follows signature page report hereby incorporated herein reference sets forth list exhibits filed herewith includes identifies management contracts compensatory plans arrangements required filed exhibits form 10k item 601 b10iii regulation sk undertaking hereby undertake pursuant regulation sk item 601b paragraph 4 iii furnish securities exchange commission upon request constituent instruments defining rights holders longterm debt consolidated subsidiaries filed herewith reason total amount securities authorized instruments exceed 10 percent total consolidated assets signatures pursuant requirements section 13 15d securities exchange act 1934 el paso corporation duly caused report signed behalf undersigned thereunto duly authorized 2nd day march 2009 pursuant requirements securities exchange act 1934 report signed following persons behalf el paso corporation capacities dates indicated el paso corporation exhibit index december 31 2008 exhibit identified filed part report exhibits filed report designated “” exhibits designated incorporated herein reference prior filing indicated exhibits designated “” constitute management contract compensatory plan arrangementitem 15 exhibits financial statement schedules following documents filed part report 1 financial statements following consolidated financial statements included part ii item 8 report exhibit index follows signature page report hereby incorporated herein reference sets forth list exhibits filed herewith includes identifies management contracts compensatory plans arrangements required filed exhibits form 10k item 601 b10iii regulation sk agreements included exhibits report intended provide information regarding terms provide factual disclosure information us parties agreements may contain representations warranties parties agreements including us solely benefit parties applicable agreements • instances treated categorical statements fact rather way allocating risk one parties statements prove inaccurate • may qualified disclosures made party connection negotiation applicable agreement disclosures necessarily reflected agreement • may apply standards materiality way different may viewed material certain investors • made date applicable agreement date dates may specified agreement subject recent developments accordingly representations warranties may describe actual state affairs date made time undertaking hereby undertake pursuant regulation sk item 601b paragraph 4 iii furnish securities exchange commission upon request constituent instruments defining rights holders longterm debt consolidated subsidiaries filed herewith reason total amount securities authorized instruments exceed 10 percent total consolidated assets signatures pursuant requirements section 13 15d securities exchange act 1934 el paso corporation duly caused report signed behalf undersigned thereunto duly authorized 1st day march 2010 pursuant requirements securities exchange act 1934 report signed following persons behalf el paso corporation capacities dates indicated el paso corporation exhibit index december 31 2009 exhibit identified filed part report exhibits filed report designated “” exhibits designated incorporated herein reference prior filing indicated exhibits designated “” constitute management contract compensatory plan arrangementitem 15 exhibits financial statement schedules following documents filed part report 1 financial statements following consolidated financial statements included part ii item 8 report exhibit index follows signature page report hereby incorporated herein reference sets forth list exhibits filed herewith includes identifies management contracts compensatory plans arrangements required filed exhibits form 10k item 601 b10iii regulation sk agreements included exhibits report intended provide information regarding terms provide factual disclosure information us parties agreements may contain representations warranties parties agreements including us solely benefit parties applicable agreements • instances treated categorical statements fact rather way allocating risk one parties statements prove inaccurate • may qualified disclosures made party connection negotiation applicable agreement disclosures necessarily reflected agreement • may apply standards materiality way different may viewed material certain investors • made date applicable agreement date dates may specified agreement subject recent developments accordingly representations warranties may describe actual state affairs date made time undertaking hereby undertake pursuant regulation sk item 601b paragraph 4 iii furnish securities exchange commission upon request constituent instruments defining rights holders longterm debt consolidated subsidiaries filed herewith reason total amount securities authorized instruments exceed 10 percent total consolidated assets signatures pursuant requirements section 13 15d securities exchange act 1934 el paso corporation duly caused report signed behalf undersigned thereunto duly authorized 28th day february 2011 pursuant requirements securities exchange act 1934 report signed following persons behalf el paso corporation capacities dates indicated el paso corporation exhibit index december 31 2010 exhibit identified filed part report exhibits filed report designated “” exhibits designated incorporated herein reference prior filing indicated exhibits designated “” constitute management contract compensatory plan arrangementitem 15 exhibits financial statement schedules following documents filed part report 1 financial statements following consolidated financial statements included part ii item 8 report 2 financial statement schedules supplementary information required submitted schedule ii valuation qualifying accounts exhibit index follows signature page report hereby incorporated herein reference sets forth list exhibits filed herewith includes identifies management contracts compensatory plans arrangements required filed exhibits form 10k item 601 b10iii regulation sk agreements included exhibits report intended provide information regarding terms provide factual disclosure information us parties agreements may contain representations warranties parties agreements including us solely benefit parties applicable agreements • instances treated categorical statements fact rather way allocating risk one parties statements prove inaccurate • may qualified disclosures made party connection negotiation applicable agreement disclosures necessarily reflected agreement • may apply standards materiality way different may viewed material certain investors • made date applicable agreement date dates may specified agreement subject recent developments accordingly representations warranties may describe actual state affairs date made time c financial statements 50percentorlessowned investees undertaking hereby undertake pursuant regulation sk item 601b paragraph 4 iii furnish securities exchange commission upon request constituent instruments defining rights holders longterm debt consolidated subsidiaries filed herewith reason total amount securities authorized instruments exceed 10 percent total consolidated assets report independent registered public accounting firm board directors stockholders citrus corp opinion accompanying consolidated balance sheets related consolidated statements income comprehensive income stockholders’ equity cash flows present fairly material respects financial position citrus corp subsidiaries “company” december 31 2011 december 31 2010 results operations cash flows three years period ended december 31 2011 conformity accounting principles generally accepted united states america financial statements responsibility company’s management responsibility express opinion financial statements based audits conducted audits statements accordance standards public company accounting oversight board united states standards require plan perform audit obtain reasonable assurance whether financial statements free material misstatement audit includes examining test basis evidence supporting amounts disclosures financial statements assessing accounting principles used significant estimates made management evaluating overall financial statement presentation believe audits provide reasonable basis opinion pricewaterhousecoopers llp houston texas february 24 2012 citrus corp subsidiaries consolidated balance sheets accompanying notes integral part consolidated financial statements citrus corp subsidiaries consolidated statements income accompanying notes integral part consolidated financial statements citrus corp subsidiaries consolidated statements stockholders’ equity accompanying notes integral part consolidated financial statements citrus corp subsidiaries consolidated statements cash flows accompanying notes integral part consolidated financial statements citrus corp subsidiaries notes consolidated financial statements 1 corporate structure citrus corp citrus holding company formed 1986 owns 100 percent membership interest florida gas transmission company llc florida gas 100 percent stock citrus energy services inc cesi collectively company december 31 2011 stock citrus owned 50 percent el paso citrus holdings inc epch whollyowned subsidiary el paso corporation el paso 50 percent crosscountry citrus llc ccc whollyowned subsidiary crosscountry energy llc crosscountry indirect subsidiary southern union company southern union florida gas openaccess interstate natural gas pipeline extending south texas gulf coast region united states south florida engaged interstate transmission natural gas subject jurisdiction federal energy regulatory commission ferc florida gas’ pipeline system primarily receives natural gas producing basins along louisiana texas gulf coast mobile bay offshore gulf mexico transports natural gas florida market see note 3 proposed transfer southern union’s equity interest citrus related litigation information related southern union’s intent merge energy transfer equity lp ete company evaluated subsequent events february 24 2012 date financial statements issued 2 summary significant accounting policies matters basis presentation company’s consolidated financial statements prepared accordance accounting principles generally accepted united states america gaap principles consolidation consolidated financial statements include accounts citrus whollyowned subsidiaries significant intercompany accounts transactions eliminated consolidation use estimates preparation financial statements conformity gaap requires management make estimates assumptions affect reported amounts assets liabilities disclosure contingent assets liabilities date financial statements reported amounts revenues expenses reporting period actual results could differ estimates regulatory accounting company subject regulation certain state federal authorities company’s accounting policies conform authoritative guidance accordance accounting requirements ratemaking practices regulatory authorities accounting policies allow company defer expenses revenues balance sheet regulatory assets liabilities probable expenses revenues allowed ratemaking process period different period would reflected consolidated statement income unregulated company deferred assets liabilities flow results operations period amounts included rates recovered refunded customers certain allowable regulatory deferrals phasein costs prohibited gaap consequence certain phasein costs florida gas’ phase iii expansion deferred gaapbasis reporting deferred future recovery ratemaking purposes management’s assessment probability recovery pass regulatory assets liabilities requires judgment interpretation laws regulatory commission orders reason company ceases meet criteria application regulatory accounting treatment part operations regulatory assets liabilities related portions ceasing meet criteria would eliminated consolidated balance sheet included consolidated statement income period discontinuance regulatory accounting treatment occurs see note 12 regulatory assets note 13 deferred credits citrus corp subsidiaries notes consolidated financial statements property plant equipment additions ongoing additions property plant equipment stated cost florida gas capitalizes constructionrelated direct labor material costs well indirect construction costs indirect construction costs primarily include labor related costs departments associated supporting construction activities largely based upon results periodic time studies management reviews time allocations provide estimate time spent supporting construction projects cost replacements betterments extend useful life property plant equipment also capitalized cost repairs replacements minor property plant equipment items charged expense incurred retirements ordinary retirements property plant equipment occur original cost less salvage value removed charge accumulated depreciation amortization gain loss recorded entire regulated operating units property plant equipment retired sold original cost less salvage value related accumulated depreciation amortization accounts removed resulting gain loss recorded earnings depreciation company amortized portion investment florida gas property excess historical cost acquisition adjustment straightline basis annual composite rate 16 percent based upon estimated useful life pipeline system florida gas computed depreciation expense using straightline method annual composite rate 221 percent 257 percent 278 percent years ended december 31 2011 2010 2009 respectively depreciation rates decreased effective april 1 2010 based settlement florida gas’ rate case see note 4 regulatory matters additional information allowance funds used construction afudc recognition afudc utility accounting practice calculations guidelines prescribed ferc capitalized part cost utility plant represents cost capital invested construction workinprogress afudc segregated two component parts borrowed funds equity funds allowance borrowed funds included accompanying statements income reduction interest expense totaled 181 million 505 million 132 million years ended december 31 2011 2010 2009 respectively allowance equity funds used construction including related amounts gross equity afudc tax basis totaled 603 million 1394 million 601 million years ended december 31 2011 2010 2009 respectively afudc equity funds included income accompanying statements income asset impairment loss recognized carrying amount longlived asset used operations recoverable exceeds fair value carrying amount longlived asset recoverable exceeds sum undiscounted cash flows expected result use eventual disposition asset longlived asset tested recoverability whenever events changes circumstances indicate carrying amount may recoverable cash equivalents cash equivalents consist highly liquid investments readily convertible cash original maturities three months less accounts receivable allowance doubtful accounts company manages trade credit risks minimize exposure uncollectible trade receivables prospective existing customers reviewed creditworthiness based upon preestablished standards customers meet minimum standards required provide additional credit support company considers many factors including historical customer collection experience general specific economic trends known specific issues related individual customers sectors transactions might impact collectability increases allowance recorded component operating expenses reductions allowance recorded receivables written subsequently collected past due receivable balances writtenoff company’s efforts unsuccessful collecting amount due unrecovered accounts receivable charged allowance doubtful accounts nil years ended december 31 2011 2010 2009 respectively citrus corp subsidiaries notes consolidated financial statements following table presents relative contribution company’s total operating revenue customer comprised least ten percent operating revenues periods presented revenues individual third party affiliate customers exceeding 10 percent total revenues approximately 59 percent 53 percent 54 percent total revenue years ended december 31 2011 2010 2009 respectively company following transportation receivables customers dates indicated 1 formerly referred florida power light company concentration customers electric natural gas utility industries concentrations customers may impact company’s overall exposure credit risk either positively negatively customers may similarly affected changes economic conditions credit losses incurred receivables industries compare favorably losses experienced company’s receivable portfolio whole company also concentration customers located southeastern united states primarily within state florida receivables generally collateralized time specifically identified customers perceived credit risk required provide prepayments deposits forms security company florida gas sought additional assurances customers due credit concerns customer deposits totaling 15 million 15 million prepayments 49000 62000 december 31 2011 2010 respectively company’s management believes portfolio florida gas’ receivables includes regulated electric utilities regulated local distribution companies municipalities minimal credit risk materials supplies materials supplies stated lower weighted average cost market value materials transferred warehouses priced weighted average cost materials supplies include spare parts critical pipeline system operations natural gas imbalances natural gas imbalances occur result differences volumes natural gas received delivered imbalances due shippers operators valued appropriate index price natural gas imbalances settled cash made inkind subject terms florida gas’ tariff generally impact earnings fuel tracker fuel tracker cumulative balance owed florida gas customers owed florida gas customers gas used operation system including costs incurred operation electric compression gas lost system otherwise unaccounted customers pursuant florida gas’ tariff related contracts provide fuel florida gas based specified percentages customers’ natural gas volumes delivered pipeline percentages designed match actual fuel consumed moving natural gas florida gas’ facilities difference volumes provided versus fuel consumed reflected fuel tracker regulatory liability recorded accompanying consolidated balance sheets net volumes natural gas owed customers collectively whenever fuel due customers prior recovery based contractual specific tariff provisions regulatory asset recorded natural gas owed customers valued market surcharge invoiced recover refund previous collections changes balances effect net income florida gas citrus corp subsidiaries notes consolidated financial statements unamortized debt premium discount expense company amortizes premiums discounts expenses incurred connection issuance longterm debt consistent terms respective debt instrument environmental expenditures environmental expenditures relate existing condition caused past operations contribute current future revenue generation expensed environmental expenditures relating current future revenues expensed capitalized appropriate liabilities recorded environmental assessments andor cleanups probable costs reasonably estimated remediation obligations discounted timing future cash flow streams predictable see note 14 commitments contingencies revenues transportation natural gas based capacity reservation charges commodity usage charges reservation revenues based contracted rates capacity reserved customers recognized monthly revenues commodity usage charges also recognized monthly based volumes natural gas delivered florida gas subject ferc regulations revenues collected pendency rate proceeding may required ferc refunded final order florida gas establishes reserves potential refunds appropriate nil 308 million potential rate refunds december 31 2011 2010 respectively see note 4 regulatory matters accumulated comprehensive loss main components comprehensive income loss relate company net earnings unrealized gain loss hedging activities information see note 7 comprehensive income fair value measurement fair value price would received sell asset paid transfer liability orderly transaction market participants measurement date company utilizes market data assumptions market participants would use pricing asset liability including assumptions nonperformance risk primarily comprised credit risk company’s credit risk counterparty credit risk risks inherent inputs applicable valuation techniques company places weight current market information concerning credit risk eg current credit default swap rates opposed historical information eg historical default probabilities credit ratings inputs readily observable market corroborated generally unobservable company endeavors utilize best available information including valuation techniques maximize use observable inputs minimize use unobservable inputs threetier fair value hierarchy prioritizes inputs used measure fair value follows • level 1 observable inputs quoted prices active markets identical assets liabilities • level 2 observable inputs quoted prices similar assets liabilities active markets ii quoted prices identical similar assets liabilities markets active require significant adjustment based unobservable inputs iii valuations based pricing models discounted cash flow methodologies similar techniques significant inputs eg interest rates yield curves etc derived principally observable market data corroborated observable market data substantially full term assets liabilities • level 3 unobservable inputs including valuations based pricing models discounted cash flow methodologies similar techniques least one significant model assumption input unobservable inputs used extent observable inputs available reflect company’s assumptions market participants would use pricing assets liabilities unobservable inputs based best information available circumstances might include company’s data assets liabilities classified entirety based lowest level input significant fair value measurement company’s assessment significance particular input fair value measurement requires judgment may affect valuation assets liabilities placement within fair value hierarchy citrus corp subsidiaries notes consolidated financial statements see note 9 benefits postretirement benefit plans plan assets additional information regarding assets company measured nonrecurring basis derivatives hedging activities derivatives recognized consolidated balance sheets fair value date derivative contract entered company designates derivative hedge fair value recognized asset liability unrecognized firm commitment fair value hedge ii hedge forecasted transaction variability cash flows received paid conjunction recognized asset liability cash flow hedge iii instrument held trading nonhedging purposes trading economic hedging instrument derivatives treated fair value hedge effective portion changes fair value recorded adjustment hedged item ineffective portion fair value hedge recognized earnings short cut method assessing effectiveness used upon termination fair value hedge debt instrument resulting gain loss amortized earnings maturity date debt instrument derivatives treated cash flow hedge effective portion changes fair value recorded accumulated comprehensive loss related hedged items impact earnings ineffective portion cash flow hedge reported currentperiod earnings upon termination cash flow hedge resulting gain loss amortized earnings maturity date hedged forecasted transactions derivatives treated trading economic hedging instruments changes fair value reported currentperiod earnings fair value determined based upon quoted market prices pricing models using assumptions market participants would use december 31 2011 2010 company hedges place amortizing previously terminated cash flow hedges asset retirement obligations aros legal obligations associated retirement longlived assets recorded fair value time obligations incurred reasonable estimate fair value made present value techniques used reflect assumptions removal remediation costs inflation profit margins third parties would demand settle amount future obligation company include market risk premium unforeseeable circumstances fair value estimates premium could reliably estimated upon initial recognition liability costs capitalized part longlived asset allocated expense useful life related asset liability accreted present value period accretion recorded operating expense corresponding increase carrying amount liability extent company permitted collect reflected financials amounts previously collected customers expensed amounts serve reduce would reflected capitalized costs initial establishment aro company records aro accretion amortization expenses excess current recoveries regulatory asset based probability recovery rates future rate cases information see note 6 asset retirement obligations income taxes income taxes accounted asset liability method deferred tax assets liabilities recognized estimated future tax consequences attributable differences financial statement carrying amounts existing assets liabilities respective tax bases deferred tax assets liabilities measured using enacted tax rates effect year temporary differences expected recovered settled effect deferred tax assets liabilities change tax rate recognized income period includes enactment date valuation allowances established necessary reduce deferred tax assets amounts likely realized determination company’s provision income taxes requires significant judgment use estimates interpretation application complex tax laws significant judgment required assessing timing amounts deductible taxable items reserves established despite management’s belief company’s tax return positions fully supportable management believes certain positions may successfully challenged facts circumstances change reserves adjusted provision income taxes see note 10 taxes income retirement plans employers required recognize balance sheets overfunded underfunded status defined benefit postretirement plans measured difference fair value plan assets accumulated postretirement benefit obligation overfunded plan recognized asset underfunded plan recognized liability employers must recognize change funded status plan year change occurs accumulated comprehensive loss stockholders’ equity citrus corp subsidiaries notes consolidated financial statements company recognized net periodic benefit expense extent amounts recorded rates difference recorded regulatory asset liability unrecognized prior service costs benefits gains andor losses recorded change accumulated comprehensive loss rather regulatory asset regulatory liability reflecting amounts due customers respectively see note 9 benefits additional related information new accounting principles accounting principles yet adopted december 2011 financial accounting standards board fasb issued authoritative guidance enhances current disclosures offsetting asset liabilities guidance requires entities disclose gross information net information instruments transactions eligible offset statement financial position instruments transactions subject agreement similar master netting arrangement guidance effective annual interim reporting periods beginning january 1 2013 company expect guidance materially impact consolidated financial statements june 2011 fasb issued authoritative guidance changes company may present comprehensive income guidance allows entities elect present items net income comprehensive income one continuous statement two separate consecutive statements eliminates current option report comprehensive income components statement changes equity entity also required present face financial statements reclassification adjustments items reclassified comprehensive income net income statement components net income components comprehensive income presented guidance effective beginning fiscal year begins december 15 2011 interim annual periods thereafter early adoption permitted december 2011 fasb issued authoritative guidance defers presentation requirements reclassification adjustments allow fasb time redeliberate requirements company expect guidance materially impact consolidated financial statements guidance requires change placement previously disclosed information may 2011 fasb issued authoritative guidance fair value measurements clarifies existing concepts eliminates wording differences gaap international financial reporting standards ifrs limited cases changes principles achieve convergence gaap ifrs guidance provides consistent definition fair value common requirements measurement disclosure fair value gaap ifrs also expands disclosures fair value measurements estimated using significant unobservable level 3 inputs guidance effective periods beginning december 15 2011 company currently evaluating impact guidance expect materially impact consolidated financial statements citrus corp subsidiaries notes consolidated financial statements 3 proposed transfer southern union’s equity interest citrus related litigation july 19 2011 southern union entered second amended restated agreement plan merger ete sigma acquisition corporation whollyowned subsidiary ete merger sub amended amendment 1 thereto dated september 14 2011 second amended merger agreement second amended merger agreement modifies certain terms agreement plan merger entered southern union ete merger sub june 15 2011 amended july 4 2011 second amended merger agreement provides merger sub southern union merger southern union continuing surviving corporation merger result merger southern union become whollyowned subsidiary ete addition ete energy transfer partners lp whollyowned subsidiary ete etp parties amended restated agreement plan merger dated july 19 2011 amended amendment 1 thereto dated september 14 2011 citrus merger agreement citrus merger agreement provides southern union crosscountry pepl holdings llc whollyowned subsidiary cce acquisition llc whollyowned subsidiary southern union citrus etp acquisition llc citrus etp whollyowned subsidiary etp become parties joinder time immediately prior closing merger upon becoming party citrus merger agreement southern union assume obligations rights ete citrus merger agreement crosscountry merged citrus etp crosscountry surviving whollyowned subsidiary etp citrus merger received stockholder approval december 9 2011 february 16 2012 parties filed missouri public service commission mpsc nonunanimous stipulation agreement stipulation among southern union ete mpsc staff pursuant stipulation parties recommend mpsc issue order finding subject conditions therein merger sub southern union detrimental public interest authorizing undertaking merger related transactions office public counsel indicated oppose stipulation southern union ete requested mpsc consider stipulation expeditiously merger expected close first quarter 2012 subject receipt mpsc approval satisfaction closing conditions crosscountry principal citrus corp capital stock agreement csa filed complaint delaware court chancery epch parent el paso seeking declaratory judgment citrus merger el paso contends trigger provisions csa would require southern union provide el paso right first refusal concerning citrus complaint filed crosscountry following exchange letters el paso southern union regarding terms csa following filing declaratory judgment action el paso filed thirdparty complaint southern union ete etp alleging among things breach csa el paso currently seeking enjoin closing citrus merger rather seeks rescission citrus merger completed alternatively damages trial currently set april 2012 described preceding paragraph el paso crosscountry parties litigation regarding effect certain planned transactions respective ownership interests company recently management company determined provide company’s independent auditors updated written management representations regarding company’s previously issued financial statements connection independent auditor’s response request consent incorporation reference audit report previously issued financial statements registration statement filing third party although management representation letter provided connection issuance company’s accompanying financial statements management determine provide updating written management representations connection future issuance independent auditor’s consent request consent incorporation reference independent auditor’s audit report company’s financial statements filing company owners determination would limit company’s ability comply reporting requirements undertake certain transactions could certain circumstances limit ability owner company comply reporting requirements undertake certain transactions 4 regulatory matters march 24 2011 ferc authorized phase viii expansion project go service florida gas placed project service april 1 2011 total project costs approximately 25 billion including capitalized equity debt costs date florida gas entered longterm firm transportation service agreements shippers 25year terms accounting approximately 74 percent available expansion capacity september 3 2010 florida gas filed settlement ferc full resolution issues set hearing rate proceeding administrative law judge certified settlement december 21 2010 settlement approved ferc february 24 2011 became effective april 1 2011 settlement results increase certain florida gas’ rate schedules decrease rate schedules compared rates effect prior april 1 2010 portion decrease effective october 1 2010 may 27 2011 florida gas refunded 439 million customers excess payments collected service march 31 2011 including interest 08 million citrus corp subsidiaries notes consolidated financial statements 5 affiliate transactions following table provides summary affiliate transactions periods presented 1 represents transportation services purchased southern natural gas company southern subsidiary el paso connection phase iii expansion completed early 1995 florida gas currently contracted firm capacity 100000 mcfd southern’s system august 31 2013 2 primarily includes corporate service charges southern union 3 primarily includes activities operational administrative services performed panhandle eastern pipe line company lp indirect whollyowned subsidiary southern union subsidiaries behalf company december 31 2011 2010 company current net accounts payable affiliated companies 112 million 113 million respectively relating services company pay cash dividends stockholders years ended december 31 2011 2010 2009 primarily due ongoing phase viii expansion capital requirements company received sponsor capital contributions stockholders 200 million year ended december 31 2010 2011 company received sponsor contributions 74 million stockholders form loans net repayments see note 8 debt obligations additional information regarding loans 6 asset retirement obligations company’s recorded aros primarily related owned offshore lines end useful life underlying assets company legally contractually required abandon place remove asset aro required recorded legal obligation retire asset exists obligation reasonably estimated although number assets company’s system subject agreements regulations give rise aro upon company’s discontinued use assets aros recorded assets indeterminate removal abandonment date given expected continued use assets proper maintenance replacement individual component assets continue replaced pipeline system continue operation long supply demand natural gas exists based widespread use natural gas industrial power generation activities management expects supply demand exist foreseeable future company place rigorous repair maintenance program keeps pipeline system good working order therefore although individual assets pipeline system may replaced pipeline system remain intact indefinitely following table general description aros associated longlived assets december 31 2011 december 31 2011 company 260000 legally restricted funds reflected assets consolidated balance sheet purpose settling aros company also aros totaling 290000 reflected current liabilities consolidated balance sheets expected settled 2012 citrus corp subsidiaries notes consolidated financial statements following table reconciliation carrying amount aro liability periods presented changes assumptions regarding timing amount probabilities associated expected cash flows well difference actual versus estimated costs result change amount liability recognized 7 comprehensive income loss deferred gains losses connection termination following derivative instruments previously accounted cash flow hedges form part comprehensive income amounts amortized terms hedged debt december 31 2011 approximately 05 million net aftertax losses accumulated comprehensive loss related interest rate hedges expected amortized interest expense next twelve months table provides summary comprehensive income loss periods presented citrus corp subsidiaries notes consolidated financial statements 8 debt obligations following table sets forth debt obligations citrus florida gas dates indicated december 31 2011 company scheduled longterm debt payments excluding unamortized debt discount follows florida gas revolving credit agreement maximum available capacity 279 million 2007 florida gas revolver matures august 16 2012 december 31 2011 amount drawn 2007 florida gas revolver 234 million weighted average interest rate 063 percent based london interbank offered rate libor plus 036 percent facility fee 009 percent citrus revolving credit facility maximum available capacity 186 million 2007 citrus revolver matures august 16 2012 december 31 2011 amount drawn 2007 citrus revolver 181 million weighted average interest rate 063 percent based libor plus 036 percent facility fee 009 percent march 31 2011 citrus entered promissory note stockholder promissory notes stockholders 150 million stockholder promissory notes final maturity date march 31 2014 principal payments required prior maturity date bear interest rate equal onemonth eurodollar rate plus credit spread 15 percent amounts may redrawn periodically notes temporarily fund capital expenditures debt retirements working capital needs december 31 2011 amount drawn promissory note 37 million net repayments citrus primarily utilized proceeds purpose funding phase viiirelated expenditures estimated fair values 2007 florida gas revolver 2007 citrus revolver december 31 2011 approximately 99 percent carrying values estimated fair value amounts longterm debt obtained citrus corp subsidiaries notes consolidated financial statements independent parties based upon market quotations similar debt interest rates currently available judgment required interpreting market data develop estimates fair value accordingly estimates determined december 31 2011 2010 necessarily indicative amounts company could realized current market exchanges company expects refinance florida gas’ 250 million senior notes due july 2012 extend maturity refinance 2007 citrus revolver 2007 florida gas revolver due august 2012 alternatively company successful efforts company may choose retire debt upon maturity utilizing combination cash flows operations utilizing available funds existing sponsor loans stockholders requesting additional sponsor loans stockholders altering timing controllable expenditures among things company obtained commitment letters stockholders make additional sponsor loans event repayment senior notes revolvers necessary however company reasonably believes based investment grade credit ratings general financial condition successful historical access capital debt markets market expectations regarding company’s future earnings cash flows able refinance andor retire obligations applicable acceptable terms prior maturity july 2010 florida gas issued 500 million 545 percent senior notes due july 15 2020 offering price 99826 per 100 principal 350 million 400 percent senior notes due july 15 2015 offering price 99982 per 100 principal florida gas utilized net proceeds partially fund phase viii expansion project general corporate purposes included repayment portion florida gas’ outstanding debt july 19 2010 florida gas made 986 million distribution citrus ii repaid 83 million outstanding credit agreements iii invested remainder proceeds august 19 2010 florida gas redeemed 325 million 7625 percent senior notes due december 1 2010 debt retirement included accrued interest 54 million 65 million redemption premium terms debt agreements florida gas may incur additional debt refinance maturing obligations refinancing increase aggregate indebtedness thereafter citrus’ florida gas’ consolidated debt exceed specific debt total capitalization ratios defined certain debt instruments incurrence additional indebtedness refinance current maturities would result debt capitalization ratio exceeding limits agreements relating citrus’ florida gas’ debt include among things restrictions sales assets payment dividends well maintenance certain restrictive financial covenants including maximum allowable ratio funded debt total capitalization company subject currently restrictive debt covenant maximum 65 percent consolidated funded debt total capitalization limitation 7488 million total additional indebtedness december 31 2011 december 31 2011 citrus’ debt obligations include construction loan agreement stockholder promissory notes 181 million outstanding revolving credit agreement addition florida gas’ debt obligations florida gas guarantees citrus revolving credit agreement indebtedness however florida gas’ assets pledged collateral aforementioned citrus debt obligations citrus florida gas events default contain commonly used crossdefault provisions event default either citrus florida gas borrowed money obligations excess certain thresholds cured within defined grace periods would cause debt obligations citrus florida gas accelerated december 31 2011 company default debt obligations citrus corp subsidiaries notes consolidated financial statements 9 benefits postretirement benefit plans florida gas postretirement health care life insurance plans postretirement plans cover substantially employees health care plan generally provides cost sharing florida gas retirees form retiree contributions deductibles coinsurance amount florida gas pays annually provide future retiree health care coverage certain plans obligations funded status postretirement benefit liabilities accrued actuarial basis years employee provides services following tables contain information dates indicated obligations funded status florida gas’ postretirement plans 1 underfunded balance recognized deferred creditother offset regulatory asset amounts due customers consolidated balance sheets citrus corp subsidiaries notes consolidated financial statements net periodic benefit cost net periodic benefit cost florida gas’ postretirement benefit plan periods presented includes components noted table estimated prior service credit postretirement plans amortized accumulated comprehensive income net periodic benefit cost 2012 12 million assumptions weightedaverage discount rate used determining benefit obligations 424 percent 552 percent december 31 2011 2010 respectively weightedaverage assumptions used determining net periodic benefit cost periods presented shown table florida gas employs building block approach determining expected longterm rate return plans’ assets proper consideration diversification rebalancing historical markets studied longterm historical relationships equities fixedincome preserved consistent widely accepted capital market principle assets higher volatility generate greater return long run current market factors inflation interest rates evaluated longterm market assumptions determined peer data historical returns reviewed check reasonableness appropriateness assumed health care cost trend rates used measure expected cost benefits covered plans shown table citrus corp subsidiaries notes consolidated financial statements assumed health care cost trend rates significant effect amounts reported healthcare plan onepercentagepoint change assumed health care cost trend rates would following effects plan assets florida gas’ overall investment strategy maintain appropriate balance actively managed investments objective optimizing longterm returns maintaining high standard portfolio quality achieving proper diversification achieve diversity within postretirement benefit plan asset portfolio florida gas targeted following asset allocations equity 25 percent 35 percent fixed income 65 percent 75 percent cash equivalents 0 percent 10 percent target allocations monitored board directors conjunction external investment advisor occasion asset allocations may fluctuate compared guidelines result board directors’ actions fair value florida gas’ postretirement plan assets dates indicated asset category follows 1 fund funds invests primarily diversified portfolio equity fixed income shortterm mutual funds december 31 2011 fund primarily comprised approximately 19 percent largecap us equities 2 percent smallcap us equities 10 percent international equities 55 percent fixed income securities 8 percent cash 6 percent investments december 31 2010 fund primarily comprised approximately 17 percent largecap us equities 4 percent smallcap us equities 10 percent international equities 57 percent fixed income securities 10 percent cash 2 percent investments postretirement plan assets classified level 1 assets within fairvalue hierarchy values based active market quotes see note 2 summary significant accounting policies matters fair value measurement information related framework used company measure fair value postretirement plan asset contributions florida gas expects contribute approximately 22 million postretirement benefit plan 2012 approximately 22 million annually thereafter modified future rate case proceedings citrus corp subsidiaries notes consolidated financial statements benefit payments florida gas’ estimate expected benefit payments reflect expected future service appropriate next five years aggregate five years thereafter shown table medicare prescription drug act provides prescription drug benefit medicare part well federal subsidy sponsors retiree health care benefit plans provide prescription drug benefit least actuarially equivalent medicare part defined contribution plan florida gas sponsors defined contribution savings plan savings plan available employees florida gas provides matching contributions 100 percent first five percent maximum five percent participant’s compensation paid savings plan florida gas’ contributions 100 percent vested five years continuous service florida gas’ contributions savings plan years ended december 31 2011 2010 2009 12 million 10 million 11 million respectively addition florida gas makes employer contributions separate accounts collectively referred profit sharing plan within defined contribution plan contribution amounts five percent compensation florida gas’ contributions 100 percent vested five years continuous service florida gas’ contributions profit sharing plan years ended december 31 2011 2010 2009 16 million 15 million 14 million respectively citrus corp subsidiaries notes consolidated financial statements 10 taxes income following table provides summary current deferred components income tax expense periods presented actual income tax expense differs amount computed applying statutory federal tax rate 35 percent income taxes follows company files consolidated federal income tax return separate stockholders florida gas included consolidated federal income tax return filed citrus pursuant tax sharing agreement citrus florida gas pay share taxes based taxable income generally equal liability florida gas would incurred separate taxpayer 849 million income tax asset consolidated balance sheets december 31 2011 represents carryback portion forecasted 2011 net operating loss tax purposes 2009 2010 primarily resulting 50 bonus depreciation assets placed service 2011 including phase viii assets citrus corp subsidiaries notes consolidated financial statements deferred income taxes result temporary differences financial statement carrying amounts tax basis existing assets liabilities table summarizes principal components company’s deferred tax assets liabilities dates indicated 581 million deferred tax asset carried current consolidated balance sheets represents carryforward portion forecasted 2011 net operating loss tax purposes 2012’s forecasted net income company evaluates tax reserves unrecognized tax benefits recognition measurement derecognition thresholds amount unrecognized tax benefits material impact company’s consolidated financial statements 11 property plant equipment following table provides summary property plant equipment dates indicated amortization expense capitalized computer software costs years ended december 31 2011 2010 2009 citrus corp subsidiaries notes consolidated financial statements 24 million 25 million 17 million respectively computer software costs amortized 10 years expected amortization expense computer software costs years 2012 2016 23 million 23 million 21 million 19 million 18 million respectively 12 regulatory assets principal components company’s regulatory assets dates indicated follows 1 rampup assets regulatory assets florida gas specifically allowed establish ferc certificates authorizing phase iv v expansion projects 13 deferred credits principal components company’s regulatory liabilities dates indicated follows 1 balancing tools regulatory method florida gas recovers refunds net costs operational natural gas balancing pipeline’s system balance deferred charge credit depending timing rate changes operational activities citrus corp subsidiaries notes consolidated financial statements principal components company’s deferred credits dates indicated follows 14 commitments contingencies litigation claims florida gas pipeline relocation costs dispute exists florida department transportation florida’s turnpike enterprise fdotfte rights florida gas certain easements agreements associated state road 91 projects among matters receive reimbursement relocation costs incurred florida gas nature scope easements first phase state road 91 projects included replacement approximately 113 miles existing 18 24inch pipelines broward county florida due widening state road 91 fdotfte construction complete new facilities placed service march 2008 dispute among others litigated broward county florida january 27 2011 jury awarded florida gas 827 million rejected damage claims fdotfte may 2 2011 judge issued order entitling florida gas easement 15 feet either side pipelines 75 feet temporary work space judge ruled florida gas entitled approximately 8 million interest addition ruling aspects easement ruled pavement could placed directly florida gas’ pipeline without consent florida gas although florida gas would required relocate pipeline provide consent also denied pending posttrial motions fdotfte filed notice appeal july 12 2011 briefing florida fourth district court appeals 4th dca complete 4th dca granted request fdot expedite appeal oral argument set march 7 2012 amounts ultimately received would primarily reduce florida gas’ property plant equipment costs 2007 action brought fdotfte florida gas orange county florida seeking declaratory judgment existing agreements florida gas liable costs relocation associated fdotfte projects stayed pending resolution broward county florida action april 14 2011 florida gas filed suit fdotfte dragados usa i595 express llc broward county florida seeking injunction damages result construction mechanically stabilized earth wall encroachments florida gas easements judge presided previously discussed fdotfte proceeding assigned case trial expected set third quarter 2012 florida gas continue seek rate recovery future types costs extent reimbursed fdotfte assurance florida gas successful obtaining complete reimbursement relocation costs fdotfte customers timing reimbursement fully compensate florida gas costs citrus corp subsidiaries notes consolidated financial statements liabilities litigation claims addition matters discussed company involved legal tax regulatory proceedings various courts regulatory commissions governmental agencies regarding matters arising ordinary course business company records accrued liabilities litigation claim costs management believes loss probable reasonably estimable management believes least reasonable possibility material loss additional material loss may incurred company discloses estimate possible loss range loss excess amount accrued ii statement estimate cannot made december 31 2011 2010 company recorded litigation claimrelated accrued liabilities 07 million 06 million respectively except matters discussed company material litigation claim contingency matters assessed probable reasonably possible would require disclosure financial statements liquidity capital resources cash generated internal operations constitutes company’s primary source liquidity company’s working capital deficit december 31 2011 5870 million includes current portion longterm debt 6865 million additional sources liquidity working capital purposes may include contributions stockholders new capital market debt availability terms relating liquidity depend upon various factors conditions company’s combined cash flow earnings company’s resulting capital structure conditions financial markets time offerings environmental matters company’s operations subject federal state local laws regulations regarding water quality hazardous solid waste management air quality control environmental matters laws rules regulations require company conduct operations specified manner obtain comply wide variety environmental registrations licenses permits inspections approvals failure comply environmental laws rules regulations may expose company significant fines penalties andor interruptions operations company’s environmental policies procedures designed achieve compliance applicable laws regulations evolving laws regulations claims damages property employees persons environment resulting current past operations may result significant expenditures liabilities future company engages process updating revising procedures ongoing evaluation operations identify potential environmental exposures enhance compliance regulatory requirements florida gas conducts assessment remediation ongoing monitoring soil groundwater impact resulted past waste management practices rio paisano station 11 facilities liability recognized current liabilities deferred credits total amounted 12 million 14 million december 31 2011 2010 respectively amounts discounted uncertainty related timing costs 01 million 01 million 01 million expensed years ended december 31 2011 2010 2009 respectively florida gas recorded estimated costs remediation spent april 1 2010 regulatory asset balance regulatory asset 09 million 10 million december 31 2011 2010 respectively see note 12 regulatory assets future regulatory compliance commitments air quality control august 2010 united states environmental protection agency epa finalized rule requires reductions number pollutants including formaldehyde carbon monoxide certain engines regardless size area sources emit less ten tons per year one hazardous air pollutant hap twentyfive tons per year haps engines less 500 horsepower major sources emit ten tons per year one hap twentyfive tons per year haps compliance required october 2013 anticipated limits adopted rule used future epa rule scheduled finalized 2013 compliance required 2016 future rule expected require reductions formaldehyde carbon monoxide emissions engines greater 500 horsepower major sources citrus corp subsidiaries notes consolidated financial statements nitrogen oxides primary air pollutant natural gasfired engines nitrogen oxide emissions may form ozone atmosphere 2008 epa lowered ozone standard seventyfive parts per billion ppb compliance anticipated 2013 2015 january 2010 epa proposed lowering standard sixty seventy ppb lieu seventyfive ppb standard compliance required 2014 later september 2011 epa decided rescind proposed lower ozone standard begin process implement 75 ppb ozone standard established 2008 january 2010 epa finalized 100 ppb onehour nitrogen dioxide standard rule requires installation new nitrogen dioxide monitors urban communities roadways 2013 new monitoring may result additional nitrogen dioxide nonattainment areas addition ambient air quality modeling may required demonstrate compliance new standard company currently reviewing potential impact august 2010 area source national emissions standards hazardous air pollutants rule implementation 2008 ozone standard new nitrogen dioxide standard operations potential costs associated installation emission control systems existing engines ultimate costs associated activities cannot estimated certainty time company believes based current understanding current proposed rules costs material adverse effect consolidated financial position results operations cash flows commitments contingencies federal pipeline integrity rules december 15 2003 us department transportation issued final rule requiring pipeline operators develop integrity management programs comprehensively evaluate pipelines take measures protect pipeline segments located rule defines high consequence areas hcas rule resulted enactment pipeline safety improvement act 2002 rule required operators identify hcas along pipelines complete baseline integrity assessments comprised inline inspection smart pigging hydrostatic testing direct assessments december 2012 operators required rank risk pipeline segments containing hcas assessments generally conducted higher risk segments first addition system modifications necessary accommodate inline inspections december 31 2011 florida gas completed approximately 96 percent baseline risk assessments required completed december 2012 identification location hcas completed practicable determine certainty total scope required remediation activities prior completion assessments inspections required modifications inspections currently estimated range approximately 30 million 40 million per year 2012 leases company utilizes assets operating leases several areas operations rental expenses amounted 48 million 2011 30 million 2010 32 million 2009 future minimum rental payments company’s various operating leases years 2012 2016 25 million 25 million 29 million 26 million 27 million respectively 67 million total thereafter see note 4 regulatory matters potential contingent matters applicable company signatures pursuant requirements section 13 15d securities exchange act 1934 el paso corporation duly caused report signed behalf undersigned thereunto duly authorized 27th day february 2012 el paso corporation douglas l foshee douglas l foshee president chief executive officer pursuant requirements securities exchange act 1934 report signed following persons behalf el paso corporation capacities dates indicated el paso corporation exhibit index december 31 2011 exhibit identified filed part report exhibits filed report designated “” exhibits designated incorporated herein reference prior filing indicated exhibits designated “” constitute management contract compensatory plan arrangement