ITEM 1. BUSINESS
GENERAL
EOG Resources, Inc. (the "Company"), a Delaware corporation organized in 1985, is engaged, either directly or through a marketing subsidiary with regard to domestic operations or through various subsidiaries with regard to international operations, in the exploration for, and the development, production and marketing of, natural gas and crude oil primarily in major producing basins in the United States, as well as in Canada and Trinidad and, to a lesser extent, selected other international areas. The Company's principal producing areas are further described under "Exploration and Production" below. At December 31, 1999, the Company's estimated net proved natural gas reserves were 3,175 billion cubic feet ("Bcf") and estimated net proved crude oil, condensate and natural gas liquids reserves were 73 million barrels ("MMBbl"). (See "Supplemental Information to Consolidated Financial Statements"). At such date, approximately 54% of the Company's reserves (on a natural gas equivalent basis) was located in the United States, 16% in Canada and 30% in Trinidad. As of December 31, 1999, the Company employed approximately 775 persons, including foreign national employees.
The Company's business strategy is to maximize the rate of return on investment of capital by controlling all operating and capital costs. This strategy enhances the generation of both income and cash flow from each unit of production and allows for the growth of production on a cost-effective basis by optimizing the reinvestment of cash flow. The Company continued to focus its 1999 drilling activity toward natural gas deliverability in addition to natural gas reserve enhancement and to a lesser extent crude oil exploitation. The Company also continues to focus on the cost-effective utilization of advances in technology associated with gathering, processing and interpretation of 3-D seismic data, developing reservoir simulation models and drilling operations through the use of new and/or improved drill bits, mud motors, mud additives, formation logging techniques and reservoir fracturing methods. These advanced technologies are used, as appropriate, throughout the Company to reduce the risks associated with all aspects of oil and gas reserve exploration, exploitation and development. The Company implements its strategy by emphasizing the drilling of internally generated prospects in order to find and develop low cost reserves. Achieving and maintaining the lowest possible operating cost structure are also important goals in the implementation of the Company's strategy.
On August 16, 1999, the Company and Enron Corp. completed the Share Exchange Agreement ("Share Exchange") whereby the Company received 62,270,000 shares of the Company's common stock out of 82,270,000 shares owned by Enron Corp. in exchange for all the stock of the Company's subsidiary, EOGI-India, Inc. Prior to the Share Exchange, the Company made an indirect capital contribution of approximately $600 million in cash, plus certain intercompany receivables, to EOGI-India, Inc. At the time of completion of this transaction, this subsidiary owned, through subsidiaries, all of the Company's assets and operations in India and China. The Company recognized a $575 million tax-free gain on the Share Exchange based on the fair value of the shares received, net of transaction fees of $14 million. Immediately following the Share Exchange, the Company retired the 62,270,000 shares of the Company's common stock received in the transaction. The weighted average basis in the treasury shares retired was first deducted from and fully eliminated existing additional paid in capital with the remaining value deducted from retained earnings. On August 30, 1999, the Company changed its corporate name to "EOG Resources, Inc." from "Enron Oil & Gas Company" and has since made similar changes to its subsidiaries' names.
On July 23, 1999, the Company filed a registration statement with the Securities and Exchange Commission for the public offering of 27,000,000 shares of the Company's common stock. The public offering was completed on August 16, 1999, and the net proceeds were used to repay short-term borrowings used to fund a significant portion of the cash capital contribution in connection with the Share Exchange. As a result of the public offering and the retirement of 62,270,000 shares of the Company's common stock previously mentioned, the number of shares of the Company's common stock issued was reduced to 124,730,000 from 160,000,000 prior to the Share Exchange. As of December 31, 1999, the Company had in its treasury
5,625,446 shares of its common stock issued, reducing the number of shares outstanding to 119,104,554 shares.
Immediately prior to the closing of the Share Exchange, Enron Corp. owned 82,270,000 shares of the Company's common stock, representing approximately 53.5 percent of all of the shares of the Company's common stock that were outstanding. As a result of the closing of the Share Exchange, the sale by Enron Corp. of 8,500,000 shares of the Company's common stock as a selling stockholder in the public offering referred to above, and the completion on August 17, 1999 and August 20, 1999 of the offering of Enron Corp. notes mandatorily exchangeable at maturity into up to 11,500,000 shares of the Company's common stock, Enron Corp's maximum remaining interest in the Company after the automatic conversion of its notes on July 31, 2002, will be under two percent (assuming the notes are exchanged for less than the 11,500,000 shares of the Company's common stock). As a result, beginning with the Share Exchange all transactions with Enron Corp. and its affiliates have been classified as Trade.
Effective as of August 16, 1999, the closing date of the Share Exchange, the members of the board of directors of the Company who were officers or directors of Enron Corp. resigned their positions as directors of the Company.
As a result of the change to the Company's portfolio of assets brought about by the Share Exchange, the Company conducted a re-evaluation of its overall business. As a result of this re-evaluation, some of the Company's projects were no longer deemed central to its business. The Company incurred non-cash charges in connection with the impairment and/or the Company's decision to dispose of such projects of $89 million after-tax. In the United States operating segment, a pre-tax charge of $78 million was recorded to depreciation, depletion and amortization expense for impairment. The carrying values for assets determined to be impaired were adjusted to estimated fair values based on projected future discounted net cash flows for such assets. In the Other operating segment, a pre-tax charge of $36 million was recorded to depreciation, depletion and amortization expense to fully write-off the Company's basis and a pre-tax charge of $19 million was recorded to other income (expense) -- other, net for the estimated exit costs related to the Company's decision to dispose of certain international operations. Net loss for such operations for 1999 excluding these charges was approximately $3 million. In addition, in the fourth quarter, depreciation, depletion and amortization expense of $7 million pre-tax was recorded in the United States operating segment resulting from a reduction in proved reserves related to the Company's decision to defer the development of the Big Piney Madison deep Paleozoic formation methane reserves in Wyoming for the foreseeable future. Starting in 2000, this reserve reduction will increase depreciation, depletion and amortization by approximately $26 million annually. At December 31, 1998, these reserves represented approximately $100 million or 5% of the Company's Standardized Measure of Discounted Future Net Cash Flows as adjusted for the sale of the India and China reserves as a result of the Share Exchange.
On July 28, 1999, the Company executed a series of new credit agreements aggregating $1.3 billion (the "Credit Facilities"). At the same time, the Company cancelled its existing credit facilities totaling $450 million. Of the $1.3 billion, $500 million was set to expire in 364 days (the "Interim Facility"), $400 million was structured as a 364-day revolving credit facility with a one-year term option subsequent to the revolving period and $400 million was structured as a five-year revolving credit facility. The Interim Facility was cancelled subsequent to the completion of the public offering referred to above.
Unless the context otherwise requires, all references herein to the Company include EOG Resources, Inc., its predecessors and subsidiaries, and any reference to the ownership of interests or pursuit of operations in any international areas by the Company recognizes that all such interests are owned and operations are pursued by subsidiaries of EOG Resources, Inc. Unless the context otherwise requires, all references herein to Enron Corp. include Enron Corp., its predecessors and affiliates, other than the Company and its predecessors and subsidiaries.
With respect to information on the Company's working interest in wells or acreage, "net" oil and gas wells or acreage are determined by multiplying "gross" oil and gas wells or acreage by the Company's working interest in the wells or acreage. Unless otherwise defined, all references to wells are gross.
BUSINESS SEGMENTS
The Company's operations are all natural gas and crude oil exploration and production related.
EXPLORATION AND PRODUCTION
NORTH AMERICA OPERATIONS
United States. The Company's principal United States producing areas are the Southwestern Wyoming area, Vernal area of Utah, South Texas area, East Texas area, Mississippi Salt Basin, Offshore Gulf of Mexico area, Southeastern New Mexico area, Val Verde Basin and Midland Basin of West Texas, and Mid Continent area. Properties in these areas comprised approximately 95% of the Company's United States reserves (on a natural gas equivalent basis) and 97% of the Company's United States net natural gas deliverability as of December 31, 1999 and substantially all are operated by the Company.
The Company's other United States natural gas and crude oil producing properties are located primarily in other areas of Texas, Utah, New Mexico, Oklahoma, California, and Kansas.
At December 31, 1999, 85% of the Company's proved United States reserves (on a natural gas equivalent basis) was natural gas and 15% was crude oil, condensate and natural gas liquids. A substantial portion of the Company's United States natural gas reserves is in long-lived fields with well-established production histories. The Company believes that opportunities exist to increase production in many of these fields through continued infill and other development drilling.
Southwestern Wyoming Area. Big Piney, the Company's largest reserve accumulation, is located in Sublette and Lincoln Counties of Southwestern Wyoming. The Company is the holder of the largest productive acreage base in the Big Piney area, with approximately 265,000 net acres under lease. The Company operates approximately 824 natural gas and crude oil wells in this area with an 85% average working interest. Deliveries from the Big Piney area net to the Company averaged 97 million cubic feet ("MMcf") per day of natural gas and 4.2 thousand barrels ("MBbl") per day of crude oil, condensate, and natural gas liquids in 1999. At December 31, 1999, natural gas deliverability net to the Company was approximately 95 MMcf per day.
The principal producing intervals within the Big Piney area are the Almy, Mesaverde and Frontier formations. The Frontier formation, which occurs at 6,500 to 10,000 feet, contains approximately 60% of the Company's Big Piney proved developed reserves. The Company drilled 47 wells in the Big Piney area in 1999 and anticipates an active drilling program will continue for several years.
During 1999, the Company drilled three wells in the Washakie Basin, Sweetwater County, Wyoming. The Cepo Lewis 21-18 and the Powder Mountain 1-13 initially produced at a combined rate of 12 MMcf per day from the Lewis formation, and the Cedar Chest 31-5 initially produced 5 MMcf per day from the Almond formation. The Company owns 20,000 net leasehold acres and 220 square miles of new 3-D seismic, and anticipates an active drilling program in the Washakie Basin for several years. Natural gas deliveries net to the Company in this area averaged approximately 9.1 MMcf per day in 1999, and deliverability at December 31, 1999 was approximately 15 MMcf per day.
Vernal Area. In the Vernal area, located primarily in Uintah County, Utah, the Company operates approximately 334 producing wells and presently controls approximately 66,000 net acres. In 1999, natural gas deliveries net to the Company from the Vernal area averaged 26 MMcf per day. Deliverability at December 31, 1999, was approximately 28 MMcf per day. Production is from the Green River and Wasatch formations located at depths between 4,500 and 8,000 feet. The Company has an average working interest of approximately 61%. Numerous drilling opportunities will be available in this area in 2000.
South Texas Area. The Company's activities in South Texas are focused in the Lobo/Roleta, Frio and Wilcox producing horizons. The principal areas of activity are in the Lobo/Roleta trend which occurs primarily in Webb and Zapata Counties and the Frio trend in Matagorda County. Utilizing newly acquired 3-D seismic in Webb and Zapata Counties, the Company added two significant field extensions in the Pok-A-Dot area. Thirteen wells were drilled and completed during 1999. At December 31, 1999, net deliveries
from these wells were 28 MMcf per day of natural gas. During 1999, Lobo/Roleta net deliverability averaged approximately 39 MMcf per day of natural gas. In Matagorda County, seven wells were completed in 1999 with a combined initial rate of 55 MMcf per day of natural gas and 1 MBbl per day of condensate net to the Company. During 1999, Frio net deliverability averaged approximately 34 MMcf per day of natural gas and 1 MBbl per day of condensate.
The Company operates approximately 429 wells in the South Texas area, and production is primarily from the Lobo, Roleta and Frio sands at depths ranging from 5,000 to 16,000 feet. The Company owns approximately 288,000 net leasehold acres and more than 40,000 net mineral fee acres in this area. Natural gas deliveries net to the Company averaged approximately 142 MMcf per day in 1999. At December 31, 1999, natural gas deliverability from this area net to the Company was approximately 190 MMcf per day. During 1999, the Company drilled 53 wells in the South Texas area, acquired 480 square miles of new 3-D seismic and leased 35,000 net acres. An active drilling program in this area is anticipated to continue for several years.
East Texas Area. The Company's activities in the East Texas area are primarily in the Carthage field, located in Panola County, the North Milton field, located in Harris County and the Stowell/Big Hill area, located in Jefferson and Chambers Counties. Pursuant to a property exchange with OXY USA Inc. ("OXY") in 1999, the Company acquired working interests in 715 wells located primarily in Gregg and Panola Counties.
The Carthage field production is from the Cotton Valley, Travis Peak and Pettit formations. The Company owns approximately 37,000 net operated acres under lease with an average 83% working interest in this area. The Company drilled 17 wells in the Carthage field in 1999 and anticipates an active drilling program will continue for several years. The Company has continued its activity in the North Milton field where it now operates 29 wells and holds a 100% working interest in the acreage. The Company anticipates drilling additional wells during 2000. The Company drilled 4 wells in the Stowell/Big Hill area in 1999 and expects to continue expansion of the program in 2000. During 1999, net deliveries from the East Texas area averaged 76 MMcf per day of natural gas and 2.7 MBbl per day of crude oil, condensate and natural gas liquids. At December 31, 1999, deliverability from the area was approximately 103 MMcf per day of natural gas with 5.9 MBbl per day of crude oil, condensate and natural gas liquids both net to the Company.
Mississippi Salt Basin. The Company's activities in this basin target the Cretaceous (Rodessa, Sligo, Hosston and Selma Chalk) formation. In Mississippi, the Company operates 114 producing wells and owns approximately 47,000 net acres. During 1999, the Company drilled 4 deep Cretaceous and 17 Chalk wells. The Company plans an expanded program in 2000. Net deliveries from the area during 1999 averaged 15 MMcf per day of natural gas and 0.6 MBbl per day of crude oil and condensate. At December 31, 1999, net deliverability from the area was approximately 15 MMcf per day of natural gas and 1.0 MBbl per day of crude oil and condensate.
Offshore Gulf of Mexico Area. Development of the Eugene Island 135 discovery continued with the installation of a second platform and the drilling of one development well in 1999. The Company anticipates drilling one additional step-out well in 2000. At December 31, 1999, net deliverability from the block was approximately 14 MMcf per day of natural gas. During 1999, net production from the Matagorda Island 623 field, where the Company purchased a 19% working interest in 1998, averaged approximately 43 MMcf per day of natural gas. The Company expects to drill two replacement wells in this field during 2000.
During the year, the Company continued to rationalize its primary term acreage position through third-party joint ventures. At December 31, 1999, the Company held an interest in 135 blocks in the Offshore Gulf of Mexico area totaling approximately 342,000 net acres with 78 primary term leases and 57 leases held by production or being developed. Of these 135 blocks, located predominantly in federal waters offshore Texas and Louisiana, 85 are operated by the Company. In 1999, the Company traded its interests in 4 producing blocks in the Matagorda Island and Garden Banks area, and the member interests in an indirect wholly owned limited liability company whose assets included interests in 5 producing blocks in the Matagorda Island area, representing in the aggregate 28 MMcf per day of natural gas production net to the Company, as part of a property exchange with OXY. Natural gas deliveries from this area averaged 127 MMcf per day during 1999, inclusive of the production from the properties traded to OXY, which transaction closed on December 31, 1999.
During 1999, the Company implemented a shift in its Gulf of Mexico strategy from exploration drilling to one of acquisition and exploitation in core areas of the Louisiana and Texas shelf. During 2000, the Company anticipates participating in 5 to 10 wells in this area.
Southeastern New Mexico Area. The Company's activities in this area have been concentrated in Lea and Eddy Counties in New Mexico. Production is primarily from the Bone Springs, Wolfcamp, Chester, Morrow, and Atoka formations. Natural gas deliveries for 1999 averaged 35 MMcf per day and deliveries of crude oil, condensate and natural gas liquids averaged 2.3 MBbl per day both net to the Company. At year end 1999, deliverability, net to the Company, was approximately 42 MMcf per day of natural gas and 2.0 MBbl per day of crude oil, condensate and natural gas liquids. The Company holds 93,000 net acres and has an average working interest of approximately 70%. Significant drilling activity is planned in 2000 for this area.
Val Verde Basin. The Company's activities in this area have been concentrated in Crockett, Terrell and Val Verde Counties in Texas. The Company holds approximately 51,000 net acres and now operates approximately 325 natural gas wells in this area in which it owns a 90% average working interest. Production is from the Canyon sands and Strawn limestone at depths from 5,500 to 12,500 feet. At December 31, 1999, natural gas deliverability net to the Company was approximately 20 MMcf per day. The Company plans to test several Val Verde basin prospects in 2000.
Midland Basin. The Company's activities in this area have been concentrated in Upton and Reagan Counties in Texas. Production is primarily from the Wolfcamp and Strawn formations. In 1999, deliveries net to the Company averaged 11 MMcf per day of natural gas and approximately 2.4 MBbl per day of crude oil, condensate and natural gas liquids. At December 31, 1999, deliverability net to the Company was approximately 14 MMcf per day of natural gas and 3.3 MBbl per day of crude oil, condensate and natural gas liquids. The Company holds approximately 40,000 net acres and has an average working interest of approximately 95%. The Company expects to drill numerous wells in this area during 2000.
Mid Continent Area. The Company's activities in the Mid-Continent area are concentrated in the Oklahoma and Texas panhandles and in the deeper Anadarko Basin. During 1999, the Company drilled 57 natural gas wells in the Oklahoma panhandle and 5 natural gas wells in the Texas panhandle. The Company controls over 400,000 acres in the Oklahoma panhandle including certain exploration rights on approximately 320,000 acres by virtue of a Farmout Agreement obtained as a part of the property exchange with OXY closed on December 31, 1999, and 27,000 acres in the Texas panhandle. Production from these areas is primarily from the Morrow, Toronto, and Council Grove formations. Net deliveries from the panhandle areas averaged approximately 34 MMcf per day of natural gas during 1999. At December 31, 1999 net deliveries from the panhandle areas were approximately 42 MMcf per day of natural gas and 0.3 MBbl per day of crude oil and condensate.
During 1999, the Company also drilled 39 wells in other areas of the Anadarko Basin. Deliveries from this area, net to the Company, averaged approximately 39 MMcf per day of natural gas and 0.3 MBbl per day of crude oil, condensate and natural gas liquids in 1999. The Company anticipates an active Mid-Continent drilling program for several years.
Canada. The Company is engaged in the exploration for and the development, production and marketing of natural gas, natural gas liquids and crude oil in Western Canada, principally in the provinces of Alberta, Saskatchewan, and Manitoba. The Company conducts operations from offices in Calgary, Alberta, and produces natural gas and crude oil from five major areas. The Sandhills area in southwestern Saskatchewan is the Company's largest single natural gas producing area in Canada. In 1999, 254 wells were drilled in the area and additional acreage and wells were acquired in the area resulting in deliverability of approximately 51 MMcf per day net to the Company at December 31, 1999. The Blackfoot area in southeastern Alberta is the second largest natural gas producing area in Canada for the Company. In 1999, 78 new wells were drilled and numerous recompletions, workovers and facility optimizations were carried out resulting in deliverability of approximately 36 MMcf per day and 0.8 MBbl per day of crude oil and condensate net to the Company at December 31, 1999. Total Canadian natural gas deliverability net to the Company at December 31, 1999 was approximately 131 MMcf per day, and the Company held approximately 522,000 net undeveloped acres in Canada. Total Canadian natural gas deliveries net to the Company for 1999
averaged approximately 115 MMcf per day. The Company expects to maintain an active drilling program in Western Canada for several years.
OUTSIDE NORTH AMERICA OPERATIONS
The Company has producing operations offshore Trinidad and is evaluating exploration, exploitation and development opportunities in selected other international areas.
Trinidad. In November 1992, the Company was awarded a 95% working interest concession in the South East Coast Consortium ("SECC") Block offshore Trinidad, encompassing three undeveloped fields, previously held by three government-owned energy companies. The Kiskadee and Ibis fields have since been developed, and the Oilbird field is anticipated to be developed within the next several years. Existing surplus processing and transportation capacity at the Pelican field facilities owned and operated by Trinidad and Tobago government-owned companies is being used to process and transport the production. Natural gas is being sold into the local market under a take-or-pay agreement with the National Gas Company of Trinidad and Tobago. In 1999, deliveries net to the Company averaged 123 MMcf per day of natural gas, which includes 21 MMcf per day of gas balancing volumes relating to a field allocation agreement and 2.4 MBbl per day of crude oil and condensate.
In 1996, the Company signed a production sharing contract with the Government of Trinidad and Tobago for the Modified U(a) Block where the Company holds a 100% working interest. The contract committed the Company to the acquisition of 3-D seismic data and the drilling of three wells. The first well, Osprey, was drilled in 1998 and was successful, encountering over 400 feet of net pay. This is the largest exploration discovery in the Company's history. The Company has booked 675 Bcfe of proved reserves in this discovery. During the fourth quarter of 1999, the Company drilled an unsuccessful exploration well, the Motmot, and in the first quarter of 2000, the Tanager well was determined to be unsuccessful. These wells fulfilled the drilling obligations on the block. At December 31, 1999, the Company held approximately 144,000 net undeveloped acres in Trinidad.
In January 2000, the Company signed a 15-year natural gas supply contract for over 60 MMcf per day with the National Gas Company of Trinidad and Tobago. This natural gas will supply a 1,850 metric ton per day anhydrous ammonia plant that is to be constructed by Caribbean Nitrogen Company Limited, a Trinidadian company in which the Company has a 16% interest. Negotiations are currently underway to obtain financing for the plant.
Venezuela. The Company was awarded exploration, exploitation and development rights for a block offshore the eastern state of Sucre, Venezuela in early 1996. The Company signed agreements with the government of Venezuela and other participants associated with a concession awarded in the Gulf of Paria East. The Company holds an initial 90% working interest in the joint venture and acts as operator. One exploratory well was drilled during 1998 and encountered hydrocarbons. The Company is presently seeking a party to complete the remaining commitment under the concession and during 1999 impaired the carrying value to reflect the Company's estimate of fair value.
Other International. The Company continues to evaluate other selected conventional natural gas and crude oil opportunities outside North America primarily by pursuing exploitation opportunities in countries where indigenous natural gas and crude oil reserves have been identified.
MARKETING
Wellhead Marketing. The Company's North America wellhead natural gas production is currently being sold on the spot market and under long-term natural gas contracts at market responsive prices. In many instances, the long-term contract prices closely approximate the prices received for natural gas being sold on the spot market. Wellhead natural gas volumes from Trinidad are sold at prices that are based on a fixed price schedule with annual escalations. Prior to the Share Exchange and under terms of the production sharing contracts, natural gas volumes in India were sold to a nominee of the Government of India at a price linked to a basket of world market fuel oil quotations with floor and ceiling limits.
Substantially all of the Company's wellhead crude oil and condensate is sold under various terms and arrangements at market responsive prices.
Other Marketing. EOG Resources Marketing, Inc. ("EOGM"), a wholly owned subsidiary of the Company, is a marketing company engaging in various marketing activities. Both the Company and EOGM contract to provide, under short and long-term agreements, natural gas to various purchasers and then aggregate the necessary supplies for the sales with purchases from various sources including third-party producers, marketing companies, pipelines or from the Company's own production and arrange for any necessary transportation to the points of delivery. In addition, EOGM has purchased and constructed several small gathering systems in order to facilitate its entry into the gathering business on a limited basis. Both the Company and EOGM utilize other short and long-term hedging and trading mechanisms including sales and purchases utilizing NYMEX-related commodity market transactions. These marketing activities have provided an effective balance in managing a portion of the Company's exposure to commodity price risks for both natural gas and crude oil and condensate wellhead prices. (See "Other Matters - Risk Management").
WELLHEAD VOLUMES AND PRICES, AND LEASE AND WELL EXPENSES
The following table sets forth certain information regarding the Company's wellhead volumes of and average prices for natural gas per thousand cubic feet ("Mcf"), crude oil and condensate, and natural gas liquids per barrel ("Bbl"), and average lease and well expenses per thousand cubic feet equivalent ("Mcfe" - natural gas equivalents are determined using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of crude oil, condensate or natural gas liquids) delivered during each of the three years in the period ended December 31:
- - ---------------
(1) Includes 48 MMcf per day in 1998 and 1997 delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended. Delivery obligations were terminated in December 1998.
(2) See "Business -- General" regarding the Share Exchange.
(3) Includes an average equivalent wellhead value of $1.53 per Mcf in 1998 and $1.73 per Mcf in 1997 for the volumes described in note (1), net of transportation costs.
COMPETITION
The Company actively competes for reserve acquisitions and exploration/exploitation leases, licenses and concessions, frequently against companies with substantially larger financial and other resources. To the extent the Company's exploration budget is lower than that of certain of its competitors, the Company may be disadvantaged in effectively competing for certain reserves, leases, licenses and concessions. Competitive factors include price, contract terms, and quality of service, including pipeline connection times and distribution efficiencies. In addition, the Company faces competition from other producers and suppliers, including competition from other world wide energy supplies, such as natural gas from Canada.
REGULATION
United States Regulation of Natural Gas and Crude Oil Production. Natural gas and crude oil production operations are subject to various types of regulation, including regulation in the United States by state and federal agencies.
United States legislation affecting the oil and gas industry is under constant review for amendment or expansion. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations which, among other things, require permits for the drilling of wells, regulate the spacing of wells, prevent the waste of natural gas and liquid hydrocarbon resources through proration and restrictions on flaring, require drilling bonds and regulate environmental and safety matters. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability.
A substantial portion of the Company's oil and gas leases in the Big Piney area and in the Gulf of Mexico, as well as some in other areas, are granted by the federal government and administered by the Bureau of Land Management (the "BLM") and the Minerals Management Service (the "MMS"), both federal agencies. Operations conducted by the Company on federal oil and gas leases must comply with numerous statutory and regulatory restrictions concerning the above and other matters. Certain operations must be conducted pursuant to appropriate permits issued by the BLM and the MMS.
BLM and MMS leases contain relatively standardized terms requiring compliance with detailed regulations and, in the case of offshore leases, orders pursuant to the Outer Continental Shelf Lands Act (which are subject to change by the MMS). Such offshore operations are subject to numerous regulatory requirements, including the need for prior MMS approval for exploration, development, and production plans, stringent engineering and construction specifications applicable to offshore production facilities, regulations restricting the flaring or venting of production, and regulations governing the plugging and abandonment of offshore wells and the removal of all production facilities. Under certain circumstances, the MMS may require operations on federal leases to be suspended or terminated. Any such suspension or termination could adversely affect the Company's interests.
The MMS has issued a notice of proposed rulemaking in which it proposes to amend its regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases. This proposed rule would modify the valuation procedures for both arm's length and non-arm's length crude oil transactions to decrease reliance on oil posted prices and assign a value to crude oil that, in the opinion of the MMS, better reflects its market value, establish a new MMS form for collecting differential data, and amend the valuation procedure for the sale of federal royalty oil. The Company cannot predict what action the MMS will take on this matter, nor can it predict how the Company will be affected by any change to this regulation.
The MMS recently issued a final rule to clarify the types of costs that are deductible transportation costs for purposes of royalty valuation of production sold off the lease. In particular, the MMS will not allow deduction of costs associated with marketer fees, cash out and other pipeline imbalance penalties, or long-term storage fees. The rule is under court review in two suits brought by oil and gas trade associations. The Company cannot predict what, if any, effect the new rule will have on its operations.
Sales of crude oil, condensate and natural gas liquids by the Company are made at unregulated market prices.
The transportation and sale for resale of natural gas in interstate commerce are regulated pursuant to the Natural Gas Act of 1938 (the "NGA") and the Natural Gas Policy Act of 1978 (the "NGPA"). These statutes are administered by the Federal Energy Regulatory Commission (the "FERC"). Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act of 1989 deregulated natural gas prices for all "first sales" of natural gas, which includes all sales by the Company of its own production. All other sales of natural gas by the Company, such as those of natural gas purchased from third parties, remain jurisdictional sales subject to a blanket sales certificate under the NGA, which has flexible terms and conditions. Consequently, all of the Company's sales of natural gas currently may be made at market prices, subject to applicable contract provisions. The Company's jurisdictional sales, however, are subject to the future possibility of greater federal oversight, including the possibility the FERC might prospectively impose more restrictive conditions on such sales.
Since 1985, the FERC has endeavored to enhance competition in natural gas markets by making natural gas transportation more accessible to natural gas buyers and sellers on an open and nondiscriminatory basis. These efforts culminated in Order No. 636 and various rehearing orders ("Order No. 636"), which mandate a fundamental restructuring of interstate natural gas pipeline sales and transportation services, including the "unbundling" by interstate natural gas pipelines of the sales, transportation, storage, and other components of their service, and to separately state the rates for each unbundled service. The courts have largely affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines, although certain appeals remain pending and the FERC continues to review and modify its open access regulations. Order No. 636 does not directly regulate the Company's activities, but has an indirect effect because of its broad scope. Order No. 636 has ended interstate pipelines' traditional role as wholesalers of natural gas, and substantially increased competition in natural gas markets. In spite of this uncertainty, Order No. 636 may enhance the Company's ability to market and transport its natural gas production, although it may also subject the Company to more restrictive pipeline imbalance tolerances and greater penalties for violation of such tolerances.
The Company owns, directly or indirectly, certain natural gas pipelines that it believes meet the traditional tests the FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction under the NGA. State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels as the pipeline restructuring under Order No. 636 is implemented. For example, the Texas Railroad Commission has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. The Company's gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services.
The Company's natural gas gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement, and management of facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. The Company cannot predict what effect, if any, such legislation might have on its operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
The FERC recently began a broad review of its transportation regulations, including how they operate in conjunction with state proposals for retail gas marketing restructuring, whether to eliminate cost-of-service rates for short-term transportation, whether to allocate all short-term capacity on the basis of competitive auctions, and whether changes to its long-term transportation policies may also be appropriate to alleviate a market bias toward short-term contracts. This review culminated in part with the FERC's issuance of Order No. 637 on February 9, 2000.
Order No. 637 revises the FERC's current regulatory framework for purposes of improving the efficiency of the market and providing captive pipeline customers with the opportunity to reduce their cost of holding long-term pipeline capacity while continuing to protect against the exercise of market power. Order No. 637
revises FERC pricing policy by waiving price ceilings for short-term released capacity for a two year period and permitting pipelines to file for peak/off-peak and term differentiated rate structures. Order No. 637 does not, however, require the allocation of all short-term capacity on the basis of competitive auctions -- as had been proposed by the FERC. Order No. 637 adopts changes in regulations relating to scheduling procedures, capacity segmentation and pipeline penalties to improve the competitiveness and efficiency of the interstate pipeline grid. It also narrows pipeline customers' right of first refusal to remove economic biases in the current rule, while still protecting captive customers' ability to resubscribe to long-term capacity. Finally, it improves the FERC's reporting requirements to provide more transparent pricing information and permit more effective monitoring of the market.
While Order No. 637, and any subsequent FERC action will affect the Company only indirectly, the Order and related inquiries are intended to further enhance competition in natural gas markets, while maintaining adequate consumer protections.
The Company cannot predict the effect that any of the aforementioned orders or the challenges to such orders will ultimately have on the Company's operations. Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, the FERC and the courts. The Company cannot predict when or whether any such proposals or proceedings may become effective. It should also be noted that the natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less regulated approach currently being pursued by the FERC will continue indefinitely.
Environmental Regulation. Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, affect the Company's operations and costs as a result of their effect on natural gas and crude oil exploration, development and production operations and could cause the Company to incur remediation or other corrective action costs in connection with a release of regulated substances, including crude oil, into the environment. Compliance with such laws and regulations has not had a material adverse effect on the Company's operations or financial condition. It is not anticipated, based on current laws and regulations, that the Company will be required in the near future to expend amounts that are material in relation to its total exploration and development expenditure program in order to comply with each environmental law and regulation, but inasmuch as such laws and regulations are frequently changed, the Company is unable to predict the ultimate cost of compliance.
Canadian Regulation. In Canada, the petroleum industry is subject to extensive controls and operates under various provincial and federal legislation and regulations governing land tenure, royalties, taxes, production rates, operational standards, environmental protection, health and safety, exports and other matters. The Company operates within this regulatory framework and continues to monitor and evaluate the impact of the regulatory regime when determining parameters for engaging in oil and gas activities and investments in Canada. The price of natural gas and crude oil in Canada has been deregulated and is determined by market conditions and negotiations between buyers and sellers in a North American market place. The North American Free Trade Agreement supports the on-going cross-border commercial transactions of the natural gas and crude oil business.
Various matters relating to the transportation and export of natural gas continue to be subject to regulation by provincial agencies and federally, by the National Energy Board; however, the North American Free Trade Agreement may have reduced the risk of altering existing cross-border commercial transactions through the assurance of fair implementation of regulatory changes, minimal disruption of contractual arrangements and the prohibition of discriminatory order restrictions and export taxes.
Canadian governmental regulations may have a material effect on the economic parameters for engaging in oil and gas activities in Canada and may have a material effect on the advisability of investments in Canadian oil and gas drilling activities. The Company is monitoring political, regulatory and economic developments in Canada.
Other International Regulation. The Company's exploration and production operations outside North America are subject to various types of regulations imposed by the respective governments of the countries in
which the Company's operations are conducted, and may affect the Company's operations and costs within that country. The Company currently has operations offshore Trinidad.
RELATIONSHIP BETWEEN THE COMPANY AND ENRON CORP.
On August 16, 1999, the Company and Enron Corp. closed the Share Exchange in which the Company acquired 62,270,000 shares of the Company's common stock out of 82,270,000 shares then owned by Enron Corp., and in return Enron Corp. received all of the stock of EOGI-India, Inc., a subsidiary of the Company. EOGI-India, Inc. owned, through subsidiaries, all of the Company's assets and operations in India and China, and had received from the Company an indirect $600 million cash capital contribution, plus certain intercompany receivables, prior to the exchange. On the closing of the Share Exchange, all of Enron Corp.'s officers and directors then serving as Company directors resigned from the Company's board. Following the closing of the Share Exchange, Enron Corp. sold 8,500,000 shares of Company stock pursuant to a public offering in which the Company also sold 27,000,000 shares of its common stock. Subsequent to the closing of the Share Exchange and the common stock offering, Enron Corp. sold securities that are mandatorily exchangeable at maturity into a minimum of 9,746,250 EOG shares and a maximum of 11,500,000 EOG shares, the latter being an amount equal to all of Enron Corp.'s remaining shares in the Company. The maturity date for these securities is July 31, 2002.
The Company and Enron Corp. have in the past entered into material transactions and agreements incident to their respective businesses. Such transactions and agreements have related to, among other things, the purchase and sale of natural gas and crude oil and hedging and trading activities. Many of these agreements are still in place, and the Company and Enron Corp. may enter into similar types of transactions and agreements in the future. The Company intends that the terms of any future transactions and agreements with Enron Corp. will be at least as favorable to the Company as could be obtained from other third parties.
OTHER MATTERS
Energy Prices. Since the Company is primarily a natural gas company, it is more significantly impacted by changes in natural gas prices than in the prices for crude oil, condensate or natural gas liquids. During recent periods, domestic natural gas has been priced significantly below parity with crude oil and condensate based on the energy equivalency of, and differences in transportation and processing costs associated with, the respective products. This imbalance in parity has been primarily driven by, among other things, a supply of domestic natural gas volumes in excess of demand requirements. The Company is unable to predict when this supply imbalance may be resolved due to the significant impacts of factors such as general economic conditions, technology developments, weather and other international energy supplies over which the Company has no control.
Average North America wellhead natural gas prices have fluctuated, at times rather dramatically, during the last three years. These fluctuations resulted in an increase in the average wellhead natural gas price for North America received by the Company of 15% from 1996 to 1997, a decrease of 15% from 1997 to 1998, and an increase of 11% from 1998 to 1999. Wellhead natural gas volumes from Trinidad are sold at prices that are based on a fixed schedule with periodic escalations. Due to the many uncertainties associated with the world political environment, the availabilities of other world wide energy supplies and the relative competitive relationships of the various energy sources in the view of the consumers, the Company is unable to predict what changes may occur in natural gas prices in the future.
Substantially all of the Company's wellhead crude oil and condensate is sold under various terms and arrangements at market responsive prices. Crude oil and condensate prices also have fluctuated during the last three years. Due to the many uncertainties associated with the world political environment, the availabilities of other world wide energy supplies and the relative competitive relationships of the various energy sources in the view of the consumers, the Company is unable to predict what changes may occur in crude oil and condensate prices in the future.
Risk Management. The Company engages in price risk management activities from time to time primarily for non-trading and to a lesser extent for trading purposes. Derivative financial instruments
(primarily price swaps and costless collars) are utilized for non-trading purposes to hedge the impact of market fluctuations of natural gas and crude oil market prices on net income and cash flow.
At December 31, 1999, the Company had outstanding crude oil commodity price swap transactions, designated as hedges, covering approximately 0.5 MMBbl of crude oil and condensate for 2000. The fair value of the positions was a negative $2 million at December 31, 1999.
At December 31, 1999, based on the Company's tax position and the portion of the Company's anticipated natural gas volumes for 2000 for which prices have not, in effect, been hedged using NYMEX-related commodity market transactions and long-term marketing contracts, the Company's net income and current operating cash flow sensitivities to changing natural gas prices are approximately $18 million (or $.15 per share) and $28 million, respectively, for each $.10 per Mcf change in average wellhead natural gas prices. The Company is not impacted as significantly by changing crude oil prices for those volumes not otherwise hedged. The Company's net income and current operating cash flow sensitivities are approximately $5 million (or $.04 per share) and $8 million, respectively, for each $1.00 per barrel change in average wellhead crude oil prices.
Tight Gas Sand Tax Credits (Section 29) and Severance Tax Exemption. United States federal tax law provides a tax credit for production of certain fuels produced from nonconventional sources (including natural gas produced from tight formations), subject to a number of limitations. Fuels qualifying for the credit must be produced from a well drilled or a facility placed in service after November 5, 1990 and before January 1, 1993, and must be sold before January 1, 2003.
The credit, which is currently approximately $.52 per million British thermal units ("MMBtu") of natural gas, is computed by reference to the price of crude oil, and is phased out as the price of crude oil exceeds $23.50 in 1980 dollars (adjusted for inflation) with complete phaseout if such price exceeds $29.50 in 1980 dollars (similarly adjusted). Under this formula, the commencement of phaseout would be triggered if the average price for crude oil rose above approximately $48 per barrel in current dollars. Significant benefits from the tax credit have accrued and continue to accrue to the Company since a portion (and in some cases a substantial portion) of the Company's natural gas production from new wells drilled after November 5, 1990, and before January 1, 1993, on the Company's leases in several of the Company's significant producing areas qualify for this tax credit. The Company entered into an arrangement with a third party whereby certain Section 29 credits were sold by the Company to the third party, and payments for such credits will be received on an as-generated basis.
Natural gas production from wells spudded or completed after May 24, 1989 and before September 1, 1996 in tight formations in Texas qualifies for a ten-year exemption, ending August 31, 2001, from severance taxes, subject to certain limitations. In 1995, the drilling qualification period was extended in a modified and somewhat reduced form from September 1996 through August 2002. In 1999, the drilling qualification period was extended eight years through August 2010. Consequently, new qualifying production will be added prospectively to that presently qualified.
Other. All of the Company's natural gas and crude oil activities are subject to the risks normally incident to the exploration for and development and production of natural gas and crude oil, including blowouts, cratering and fires, each of which could result in damage to life and property. Offshore operations are subject to usual marine perils, including hurricanes and other adverse weather conditions, and governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. In accordance with customary industry practices, insurance is maintained by the Company against some, but not all, of the risks. Losses and liabilities arising from such events could reduce revenues and increase costs to the Company to the extent not covered by insurance.
The Company's operations outside of North America are subject to certain risks, including expropriation of assets, risks of increases in taxes and government royalties, renegotiation of contracts with foreign governments, political instability, payment delays, limits on allowable levels of production and currency exchange and repatriation losses, as well as changes in laws, regulations and policies governing operations of foreign companies generally.
CURRENT EXECUTIVE OFFICERS OF THE REGISTRANT
The current executive officers of the Company and their names and ages are as follows (all positions are with the Company unless otherwise noted):
Mark G. Papa was elected Chairman of the Board and Chief Executive Officer in August 1999, President and Chief Executive Officer and Director of the Company in September 1998, President and Chief Operating Officer in September 1997, President in December 1996 and was President -- North America Operations from February 1994 to September 1998. From May 1986 through January 1994, Mr. Papa served as Senior Vice President -- Operations. Mr. Papa joined Belco Petroleum Corporation, a predecessor of the Company, in 1981.
Edmund P. Segner, III became President and Chief of Staff and Director of the Company in August 1999. He became Vice Chairman and Chief of Staff of the Company in September 1997. Mr. Segner was a director of the Company from January 1997 to October 1997. Mr. Segner joined Enron Corp. in 1988 and was Executive Vice President and Chief of Staff.
Loren M. Leiker joined the Company in April 1989 as Senior Vice President, Exploration. He was elected Executive Vice President, Exploration in May 1998 and Executive Vice President, Exploration and Development in February 2000.
Gary L. Thomas was elected Executive Vice President, North America Operations in May 1998. He was previously Senior Vice President and General Manager of the Company's Midland Division. Mr. Thomas joined a predecessor of the Company in July 1978.
Barry Hunsaker, Jr. has been Senior Vice President and General Counsel since he joined the Company in May 1996. Prior to joining the Company, Mr. Hunsaker was a partner in the law firm of Vinson & Elkins L.L.P.
Walter C. Wilson joined the Company in November 1987 and has been Senior Vice President and Chief Financial Officer since May 1991.
Timothy K. Driggers was elected Vice President and Controller of the Company in October 1999. He was Assistant Controller of Enron Corp. from October 1998 through September 1999. Mr. Driggers held management positions in the Financial Planning and Reporting Department of the Company from August 1995 through September 1998. Prior to joining the Company, Mr. Driggers was a Senior Audit Manager at Arthur Andersen LLP.
ITEM 2.
ITEM 2. PROPERTIES
OIL AND GAS EXPLORATION AND PRODUCTION PROPERTIES AND RESERVES
Reserve Information. For estimates of the Company's net proved and proved developed reserves of natural gas and liquids, including crude oil, condensate and natural gas liquids, see "Supplemental Information to Consolidated Financial Statements."
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth in Supplemental Information to Consolidated Financial Statements represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and liquids, including crude oil, condensate and natural gas liquids, that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers normally vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based.
In general, the volume of production from oil and gas properties owned by the Company declines as reserves are depleted. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration, exploitation and development activities, the proved reserves of the Company will decline as reserves are produced. Volumes generated from future activities of the Company are therefore highly dependent upon the level of success in finding or acquiring additional reserves and the costs incurred in so doing. The Company's estimates of reserves filed with other federal agencies agree with the information set forth in Supplemental Information to Consolidated Financial Statements.
Acreage. The following table summarizes the Company's developed and undeveloped acreage at December 31, 1999. Excluded is acreage in which the Company's interest is limited to owned royalty, overriding royalty and other similar interests.
Producing Well Summary. The following table reflects the Company's ownership in gas and oil wells located in Texas, the Gulf of Mexico, Oklahoma, New Mexico, Utah, Wyoming, and various other states, Canada and Trinidad at December 31, 1999. Gross gas and oil wells include 222 with multiple completions.
Drilling and Acquisition Activities. During the years ended December 31, 1999, 1998 and 1997 the Company spent approximately $467 million, $779 million and $701 million, respectively, for exploratory and development drilling and acquisition of leases and producing properties. The Company drilled, participated in the drilling of or acquired wells as set out in the table below for the periods indicated:
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* Includes the acquisition of additional interests in certain wells in which the Company previously owned an interest.
All of the Company's drilling activities are conducted on a contract basis with independent drilling contractors. The Company owns no drilling equipment.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
The Company and its subsidiaries and related companies are named defendants in numerous lawsuits and named parties in numerous governmental proceedings arising in the ordinary course of business. While the outcome of lawsuits or other proceedings against the Company cannot be predicted with certainty, management does not expect these matters to have a material adverse effect on the financial condition or results of operations of the Company.
On July 21, 1999, two stockholders of the Company filed separate lawsuits purportedly on behalf of the Company against Enron Corp. and those individuals who were then directors of the Company, alleging that Enron Corp. and those directors breached their fiduciary duties of good faith and loyalty in approving the Share Exchange. The lawsuits seek to rescind the transaction or to receive monetary damages and costs and expenses, including reasonable attorneys' and experts' fees. The Company, Enron Corp. and the individual defendants believe the lawsuits are without merit and intend to vigorously contest them.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the fourth quarter of 1999.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS
The following table sets forth, for the periods indicated, the high and low sales prices per share for the common stock of the Company, as reported on the New York Stock Exchange Composite Tape, and the amount of cash dividends paid per share.
As of February 15, 2000, there were approximately 410 record holders of the Company's common stock, including individual participants in security position listings. There are an estimated 26,600 beneficial owners of the Company's common stock, including shares held in street name.
The Company currently intends to continue to pay quarterly cash dividends on its outstanding shares of common stock. However, the determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, the financial condition, funds from operations, level of exploration, exploitation and development expenditure opportunities and future business prospects of the Company.
RECENT SALES OF UNREGISTERED SECURITIES
On December 10, 1999, the Company sold in a private placement 100,000 shares of Series A Fixed Rate Cumulative Perpetual Senior Preferred Stock, par value $.01 per share, liquidation preference $1,000 per share (the "Series A Stock") to Lehman Brothers Inc., Banc of America Securities LLC and Goldman, Sachs & Co., as initial purchasers, for resale to "qualified institutional buyers" (as defined in Rule 144A under the Securities Act of 1933, as amended (the "Securities Act")) and to a limited number of institutional "accredited investors" (as defined in Rule 501(a)(1), (2), (3) or (7) under the Securities Act), at the aggregate offering price of approximately $98,000,000. The Company has entered into a registration rights agreement with the initial purchasers for the benefit of the holders of Series A Stock wherein the Company has agreed (1) to use its reasonable best efforts to file with the Commission, within 150 days after the initial issuance of the Series A Stock (which would be May 8, 2000), a registration statement with respect to an offer to exchange shares of the Series A Stock for shares of fixed rate cumulative perpetual senior preferred stock of the Company with substantially identical terms to the Series A Stock (the "Exchange Stock"), except that the Exchange Stock will not contain terms with respect to, among other matters, the transfer restrictions under the Securities Act, or the payment of additional dividends under certain circumstances relating to the Company's obligations under the registration rights agreement and (2) to use its reasonable best efforts to cause such registration statement to be declared effective under the Securities Act within 180 days after the initial issuance of the Series A Stock (which would be June 7, 2000). Promptly after such registration
statement has been declared effective, the Company intends to offer the Exchange Stock in exchange for surrender of the Series A Stock. For each share of Series A Stock validly tendered to the Company pursuant to the exchange offer and not validly withdrawn by the holder thereof, the holder of such share of Series A Stock will receive a share of the Exchange Stock having a liquidation preference equal to the liquidation preference of the tendered Series A Stock. In the event that applicable law or interpretations of the staff of the Commission do not permit the Company to effect the exchange offer, or in certain other circumstances, the Company has agreed to use its reasonable best efforts to cause to become effective a shelf registration statement with respect to the resale of the Series A Stock.
On December 22, 1999, the Company sold in a private placement 500 shares of Series C Flexible Money Market Cumulative Preferred Stock, par value $.01 per share, liquidation preference $100,000 per share (the "Series C Stock") to Lehman Brothers Inc., as initial purchaser, for resale to "qualified institutional buyers" (as defined in Rule 144A under the Securities Act) and to a limited number of institutional "accredited investors" (as defined in Rule 501(a)(1), (2), (3) or (7) under the Securities Act), at the aggregate offering price of approximately $49,000,000. The Company has entered into a registration rights agreement with the initial purchaser for the benefit of the holders of Series C Stock wherein the Company has agreed (1) to use its reasonable best efforts to file with the Commission, within 150 days after the initial issuance of the Series C Stock (which would be May 20, 2000), a registration statement with respect to an offer to exchange shares of the Series C Stock for shares of money market cumulative preferred stock of the Company with substantially identical terms to the Series C Stock (the "Exchange Stock"), except that the Exchange Stock will not contain terms with respect to, among other matters, the transfer restrictions under the Securities Act or the payment of additional dividends under certain circumstances relating to the Company's obligations under the registration rights agreement and (2) to use its reasonable best efforts to cause such registration statement to be declared effective under the Securities Act within 180 days after the initial issuance of the Series C Stock (which would be June 19, 2000). Promptly after such registration statement has been declared effective, the Company intends to offer the Exchange Stock in exchange for surrender of the Series C Stock. For each share of Series C Stock validly tendered to the Company pursuant to the exchange offer and not validly withdrawn by the holder thereof, the holder of such share of Series C Stock will receive a share of the Exchange Stock having a liquidation preference equal to the liquidation preference of the tendered Series C Stock. In the event that applicable law or interpretations of the staff of the Commission do not permit the Company to effect the exchange offer, or in certain other circumstances, the Company has agreed to use its reasonable best efforts to cause to become effective a shelf registration statement with respect to the resale of the Series C Stock.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
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(1) See Note 16 to the Consolidated Financial Statements.
(2) See "Item 1. Business -- General" regarding the Share Exchange.
(3) Includes benefits of approximately $8 million, $12 million, $12 million, $16 million and $22 million in 1999, 1998, 1997, 1996 and 1995, respectively, relating to tight gas sand federal income tax credits.
(4) Includes a benefit of $2 million related to the final audit assessments of India taxes for certain prior years, a benefit of $3.8 million related to reduced deferred franchise taxes, and $3.5 million related to Venezuela deferred tax benefits.
(5) Includes a benefit of $15 million primarily associated with the refiling of certain Canadian tax returns and the sale of certain international assets and subsidiaries.
(6) Includes a benefit of $9 million primarily associated with a reassessment of deferred tax requirements and the successful resolution on audit of Canadian income taxes for certain prior years.
(7) Includes a benefit of approximately $14 million associated with the successful resolution on audit of federal income taxes for certain prior years.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following review of operations for each of the three years in the period ended December 31, 1999 should be read in conjunction with the consolidated financial statements of the Company and notes thereto beginning with page.
RESULTS OF OPERATIONS
Net Operating Revenues. Wellhead volume and price statistics for the specified years were as follows:
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(1) Includes 48 MMcf per day in 1998 and 1997 delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended. Delivery obligations were terminated in December 1998.
(2) See "Item 1. Business -- General" regarding the Share Exchange.
(3) Includes an average equivalent wellhead value of $1.53 per Mcf in 1998 and $1.73 per Mcf in 1997 for the volumes detailed in note (1), net of transportation costs.
(4) Includes natural gas, crude oil, condensate and natural gas liquids.
1999 compared to 1998. During 1999, net operating revenues increased $31 million to $801 million. Total wellhead revenues of $823 million increased by $68 million, or 9%, as compared to 1998.
Average wellhead natural gas prices for 1999 were approximately 9% higher than the comparable period in 1998 increasing net operating revenues by approximately $55 million. Average wellhead crude oil and condensate prices were up by 35% increasing net operating revenues by $37 million. Revenues from the sale of natural gas liquids increased $3 million primarily due to higher wellhead prices. Wellhead natural gas volumes were approximately 3% lower than the comparable period in 1998 decreasing net operating revenues by nearly $21 million. The decrease in volumes is primarily due to the transfer of producing properties in the Share Exchange and decreased deliveries in Trinidad. (See "Item 1. Business -- General" for a discussion of the Share Exchange.) Production in Trinidad decreased 16 MMcf per day due primarily to decreased nominations and the temporary shut-in of a well in accordance with the terms of a field allocation agreement. North America wellhead natural gas production was approximately 1% lower than the comparable period in 1998. Wellhead crude oil and condensate volumes were 5% lower than in 1998 decreasing net operating revenues by $6 million. The decrease is primarily attributable to the Share Exchange and decreased deliveries in Trinidad.
Gains (losses) on sales of reserves and related assets and other, net totaled a loss of $1 million during 1999 compared to a net gain of $18 million in 1998. The difference is due primarily to an $8 million loss in 1999 related to the anticipated disposition of certain international assets compared to a $27 million gain on sale of certain South Texas properties, partially offset by a $14 million provision for loss on certain physical natural gas contracts in 1998.
Other marketing activities associated with sales and purchases of natural gas, natural gas and crude oil price hedging and trading transactions, and margins related to the volumetric production payment (in 1998) decreased net operating revenue by $21 million during 1999, compared to a $4 million reduction in 1998.
1998 compared to 1997. During 1998, net operating revenues decreased $14 million to $769 million. Total wellhead revenues of $755 million decreased by $74 million, or 9%, as compared to 1997.
Average wellhead natural gas prices for 1998 were approximately 14% lower than the comparable period in 1997 reducing net operating revenues by approximately $104 million. Average wellhead crude oil and condensate prices were down by 34% worldwide decreasing net operating revenues by $60 million. Revenues from the sale of natural gas liquids decreased $6 million primarily due to lower wellhead prices. Wellhead natural gas volumes were approximately 9% higher than the comparable period in 1997 increasing net operating revenues by nearly $62 million. Natural gas production in India increased 38 MMcf per day from the Tapti and Panna fields, which did not commence deliveries until late in the second quarter of 1997 and the first quarter of 1998, respectively. Production in Trinidad increased 26 MMcf per day due primarily to additional volumes above the current contract level relating to gas balancing volumes pursuant to a field allocation agreement. North America wellhead natural gas production was approximately 2% higher than the comparable period in 1997. Wellhead crude oil and condensate volumes were 24% higher than in 1997 increasing net operating revenues by $34 million. Production from the Panna and Mukta fields in India more than doubled as a result of the ongoing development program and shut-down of crude oil production in the second quarter of 1997 to allow for the conversion from temporary to permanent production facilities. North America crude oil and condensate volumes increased 17% due primarily to higher levels of liquids production in South Texas and offshore.
Other marketing activities associated with sales and purchases of natural gas, natural gas and crude oil price hedging and trading transactions, and margins related to the volumetric production payment decreased net operating revenue by $4 million during 1998, compared to a $61 million reduction in 1997, representing an improvement of $57 million.
Operating Expenses
1999 compared to 1998. During 1999, operating expenses of $783 million were approximately $127 million higher than the $656 million incurred in 1998.
Lease and well expenses decreased $7 million to $92 million primarily due to the effects of the Share Exchange, fewer workovers, the effects of a warm winter and a continuing focus on controlling operating costs in all areas of Company operations. Exploration expenses of $53 million and dry hole expenses of $12 million decreased $13 million and $11 million, respectively, from 1998 primarily due to implementation of cost provisions of certain new service agreements in North America. Impairment of unproved oil and gas properties of $32 million remained essentially flat compared to 1998. Depreciation, depletion and amortization ("DD&A") expense increased approximately $145 million to $460 million in 1999 primarily due to charges of $15 million pursuant to a change in the Company's strategy related to certain offshore operations in the second quarter and an impairment of various North America properties in the fourth quarter, and non-recurring charges of $114 million related primarily to assets determined no longer central to the Company's business in the third quarter. General and administrative ("G&A") expenses were $14 million higher than in 1998 due to non-recurring costs of $5 million related to the potential sale of the Company, $4 million related to personnel expenses and $9 million related to the completion of the Share Exchange partially offset by a reduction of $4 million resulting from the discontinuance of the India and China operations as a result of the Share Exchange.
Total operating costs per unit of production, which include lease and well, DD&A, G&A, taxes other than income and interest expense, increased 34% to $1.87 per thousand cubic feet equivalent ("Mcfe") in 1999 from $1.40 per Mcfe in 1998. This increase is primarily due to a higher per unit rate of DD&A expense, G&A expenses and interest expense, partially offset by a lower per unit rate of lease and well expense. Excluding the aforementioned charges of $15 million and $114 million in DD&A expense and $14 million in G&A expenses, the per unit operating costs for the Company were $1.51 per Mcfe. The adjusted per unit operating costs were $0.11 higher compared to $1.40 per Mcfe for the comparable period in 1998 primarily due to a higher per unit rate of interest as a result of higher debt levels and a higher per unit rate of DD&A expense.
1998 compared to 1997. During 1998, operating expenses of $656 million were approximately $65 million higher than the $591 million incurred in 1997.
Lease and well expenses increased $3 million to $99 million primarily due to commencement of operations in China. Exploration expenses of $66 million and dry hole expenses of $23 million increased $8 million and $5 million, respectively, from 1997 primarily due to increased exploratory drilling and other exploration activities in North America. Impairment of unproved oil and gas properties increased $5 million to $32 million resulting from a full year of impairment recorded on unproved leases acquired in 1997 in North America. DD&A expense increased approximately $37 million to $315 million in 1998 primarily reflecting a higher per unit rate in North America and increased worldwide production volumes. G&A expenses were $15 million higher than in 1997 due to expanded worldwide operations. Taxes other than income were down by approximately $8 million from the prior year primarily due to lower state severance taxes associated with decreased wellhead revenues in the United States.
Total operating costs per unit of production, which include lease and well, DD&A, G&A, taxes other than income and interest expense, increased 2% to $1.40 per Mcfe in 1998 from $1.37 per Mcfe in 1997. This increase is primarily due to a higher per unit rate of interest expense, DD&A expense and G&A expenses, partially offset by a lower per unit rate of lease and well expense and taxes other than income.
Other Income (Expense). The other income of $611 million for 1999 included a $575 million net gain from the Share Exchange (See Note 7 to the Consolidated Financial Statements), a $59.6 million gain on the sale of 3.2 million options owned by the Company to purchase Enron Corp. common stock (See Note 3 to the Consolidated Financial Statements), and a $19.4 million charge for estimated exit costs related to the Company's decision to dispose of certain international assets.
Interest Expense. The increase in net interest expense of $13 million from 1998 to 1999 and $21 million from 1997 to 1998 primarily reflects a higher level of debt outstanding due to expanded worldwide operations and common stock repurchases. (See Note 4 to the Consolidated Financial Statements).
Income Taxes. Income tax provision decreased approximately $5 million for 1999 as compared to 1998 and decreased approximately $37 million for 1998 as compared to 1997 primarily due to lower pre-tax income year to year after removing the gain on the Share Exchange which is non-taxable.
CAPITAL RESOURCES AND LIQUIDITY
Cash Flow. The primary sources of cash for the Company during the three-year period ended December 31, 1999 included funds generated from operations, proceeds from the sales of other assets, selected oil and gas reserves and related assets, funds from new borrowings and proceeds from equity offerings. Primary cash outflows included funds used in operations, exploration and development expenditures, common stock repurchases, dividends paid to Company shareholders, the repayment of debt and cash contributed to transferred subsidiaries in the Share Exchange.
Net operating cash flows of $442 million in 1999 increased approximately $39 million as compared to 1998 due to higher net operating revenues resulting from higher prices net of cash operating expenses and lower current income taxes. Changes in working capital and other liabilities decreased operating cash flows by $18 million as compared to 1998 primarily due to changes in accounts receivable, accrued royalties payable and accrued production taxes caused by fluctuation of commodity prices at each year end. Net investing cash outflows of $363 million in 1999 decreased by $396 million as compared to 1998 due primarily to decreased exploration and development expenditures of $312 million (including producing property acquisitions) and higher proceeds from sales of other assets of $83 million partially offset by lower proceeds from sales of reserves and related assets of $51 million. Changes in Components of Working Capital Associated with Investing Activities included for all periods changes in accounts payable related to the accrual of exploration and development expenditures and changes in inventories which represent materials and equipment used in drilling and related activities. Cash used in financing activities in 1999 was $60 million as compared to cash provided by financing activities of $353 million in 1998. Financing activities in 1999 included funds used in the Share Exchange of $609 million, dividend payments of $17 million, transaction fees of $19 million associated with the Share Exchange and other financing transactions, and net repayment of $152 million of long-term debt, partially offset by net proceeds from equity offerings of $725 million and proceeds from sales of treasury stock of $15 million.
Net operating cash flows of $404 million in 1998 decreased approximately $127 million as compared to 1997 primarily reflecting increased working capital for operating activities, higher interest expense, decreased operating revenues, increased cash operating expenses and increased cash taxes. Changes in working capital and other liabilities decreased operating cash flows by $72 million as compared to 1997 primarily due to the payment of $25 million of income taxes due under the 1997 tax agreement with Enron Corp. and changes in accounts receivable, accrued royalties payable and accrued production taxes caused by fluctuation of commodity prices at each year end. Net investing cash outflows of $760 million in 1998 increased by $63 million as compared to 1997 due primarily to increased exploration and development expenditures of $78 million, partially offset by higher proceeds from sales of reserves and related assets of $24 million. Changes in Components of Working Capital Associated with Investing Activities included for all periods changes in accounts payable related to the accrual of exploration and development expenditures and changes in inventories which represent materials and equipment used in drilling and related activities. Cash provided by financing activities in 1998 was $353 million as compared to $168 million in 1997. Financing activities in 1998 included the net issuance of $402 million of long-term debt primarily to fund exploration and development activities, to repurchase shares of the Company's common stock and to pay cash dividends. Share repurchases in 1998 totaled $26 million as compared to repurchases of $99 million in 1997. Dividend payments were approximately $19 million in each year.
Discretionary cash flow, a frequently used measure of performance for exploration and production companies, is generally derived by adjusting net income to eliminate the effects of depreciation, depletion and amortization, impairment of unproved oil and gas properties, deferred income taxes, gains on sales of oil and gas reserves and related assets, certain other non-cash amounts, except for amortization of deferred revenue and exploration and dry hole costs. The Company generated discretionary cash flow of approximately $476 million in 1999, $463 million in 1998, and $508 million in 1997.
Exploration and Development Expenditures. The table below sets out components of actual exploration and development expenditures for the years ended December 31, 1999, 1998 and 1997, along with those budgeted for the year 2000.
Exploration and development expenditures decreased $312 million in 1999 as compared to 1998 primarily due to a reduced level of service industry costs as well as reduced spending on the North America, Trinidad and India drilling and acquisition program. Producing property acquisitions decreased $166 million primarily in North America. Drilling and facilities expenditures declined by $101 million in 1999 primarily due to implementation of cost provisions of certain new service agreements in North America and effects of the Share Exchange.
Exploration and development expenditures increased $78 million in 1998 as compared to 1997 primarily due to the third quarter 1998 acquisition of producing properties in the Gulf of Mexico for $156 million. Unproved leasehold acquisitions decreased $41 million primarily in North America. Drilling and facilities expenditures declined by approximately $25 million in 1998 as decreased activity in North America and lower expenditures in India were partially offset by new drilling in Trinidad and Venezuela. While development activities continued in India, expenditures in 1998 were less than in 1997 due to 1997 expenditures associated with the installation of permanent production facilities. (See "Business -- Exploration and Production" for additional information detailing the specific geographic locations of the Company's drilling programs and "Outlook" below for a discussion related to 2000 exploration and development expenditure plans).
Hedging Transactions. The Company's 1999 NYMEX-related natural gas and crude oil commodity price swaps closed with "other marketing revenue" decreases of $7 million and $3 million pretax, respectively. At December 31, 1999, there were open crude oil commodity price swaps for 2000 covering approximately 548 MBbl of crude oil at a weighted average price of $19.23 per barrel. There were no open natural gas commodity price swaps.
Financing. The Company's long-term debt-to-total-capital ratio was 47% as of December 31, 1999 and 1998.
During 1999, total long-term debt decreased $153 million to $990 million following the issuance of two series of preferred stock with combined face value of $150 million and the subsequent use of approximately $147 million of net proceeds received therefrom to reduce commercial paper and bank debt borrowings. (See Notes 4 and 6 to the Consolidated Financial Statements). The estimated fair value of the Company's long-term debt at December 31, 1999 and 1998 was $933 million and $1,141 million, respectively, based upon quoted market prices and, where such prices were not available, upon interest rates currently available to the Company at year end. The Company's debt is primarily at fixed interest rates. At December 31, 1999, a 1% change in interest rates would result in a $46 million change in the estimated fair value of the fixed rate obligations. (See Note 14 to the Consolidated Financial Statements).
Prior to August 16, 1999, the Company engaged in various transactions with Enron Corp. that were characteristic of a consolidated group under common control. Accordingly, the Company maintained reciprocal agreements with Enron Corp. that provided for the borrowing by the Company of up to $200 million and investing by the Company of surplus funds of up to $200 million at market-based interest rates. Advances from Enron Corp. of $200 million were outstanding at December 31, 1998, and such balances were classified as long-term based on the Company's intent and ability to ultimately replace such amounts with other long- term debt. The reciprocal agreements terminated on August 16, 1999 upon the closing of the Share Exchange. There were no investments with Enron Corp. at December 31, 1998 or 1999. (See Note 4 to the Consolidated Financial Statements).
Outlook. Uncertainty continues to exist as to the direction of future North America natural gas and crude oil price trends, and there remains a rather wide divergence in the opinions held by some in the industry. This divergence in opinion is caused by various factors including improvements in the technology used in drilling and completing crude oil and natural gas wells that are tending to mitigate the impacts of fewer crude oil and natural gas wells being drilled, improvements being realized in the availability and utilization of natural gas storage capacity and warmer than normal weather experienced in 1999 and to date in 2000. However, the continually increasing recognition of natural gas as a more environmentally friendly source of energy along with the availability of significant domestically sourced supplies should result in further increases in demand and a supporting/strengthening of the overall natural gas market over time. Being primarily a natural gas producer, the Company is more significantly impacted by changes in natural gas prices than by changes in crude oil and condensate prices. (See "Business -- Other Matters -- Energy Prices"). At December 31, 1999, based on the Company's tax position and the portion of the Company's anticipated natural gas volumes for 2000 for which prices have not, in effect, been hedged using NYMEX-related commodity market transactions and long-term marketing contracts, the Company's net income and current operating cash flow sensitivities to changing natural gas prices are approximately $18 million (or $.15 per share) and $28 million, respectively, for each $.10 per Mcf change in average wellhead natural gas prices. The Company is not impacted as significantly by changing crude oil prices for those volumes not otherwise hedged. The Company's net income and current operating cash flow sensitivities are approximately $5 million (or $.04 per share) and $8 million, respectively, for each $1.00 per barrel change in average wellhead crude oil prices.
The Company plans to continue to focus a substantial portion of its exploration and development expenditures in its major producing areas in North America. However, based on the continuing uncertainty associated with North America natural gas prices and as a result of the overall success realized in Trinidad, the Company anticipates expending a portion of its available funds in the further development of opportunities outside North America. In addition, the Company expects to conduct limited exploratory activity in other areas outside of North America and will continue to evaluate the potential for involvement in other exploitation type opportunities. (See "Business -Exploration and Production" for additional information detailing the specific geographic locations of the related drilling programs). Budgeted 2000 expenditures are anticipated to be managed within the range of $500-$525 million, addressing the continuing uncertainty with regard to the future of the North America natural gas and crude oil and condensate price environment. Budgeted expenditures for 2000 are structured to maintain the flexibility necessary under the Company's continuing strategy of funding North America exploration, exploitation, development and acquisition activities primarily from available internally generated cash flow.
The level of exploration and development expenditures may vary in 2000 and will vary in future periods depending on energy market conditions and other related economic factors. Based upon existing economic and market conditions, the Company believes net operating cash flow and available financing alternatives in 2000 will be sufficient to fund its net investing cash requirements for the year. However, the Company has significant flexibility with respect to its financing alternatives and adjustment of its exploration, exploitation, development and acquisition expenditure plans if circumstances warrant. While the Company has certain continuing commitments associated with expenditure plans related to operations in Trinidad, such commitments are not anticipated to be material when considered in relation to the total financial capacity of the Company.
Environmental Regulations. Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to protection of the environment, may affect the Company's operations and costs as a result of their effect on natural gas and crude oil exploration, exploitation, development and production operations. Compliance with such laws and regulations has not had a material adverse effect on the Company's operations or financial condition. It is not anticipated, based on current laws and regulations, that the Company will be required in the near future to expend amounts that are material in relation to its total exploration and development expenditure program by reason of environmental laws and regulations. However, inasmuch as such laws and regulations are frequently changed, the Company is unable to predict the ultimate cost of compliance.
NEW ACCOUNTING PRONOUNCEMENT -- SFAS NO. 133
In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133 -- "Accounting for Derivative Instruments and Hedging Activities" effective for fiscal years beginning after June 15, 1999. In June 1999, the FASB issued SFAS No. 137, which delays the effective date of SFAS No. 133 for one year, to fiscal years beginning after June 15, 2000. SFAS No. 133, as amended by SFAS No. 137, cannot be applied retroactively and must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts that were issued, acquired or substantively modified after a transition date to be selected by the Company of either December 31, 1997 or December 31, 1998.
The statement establishes accounting and reporting standards requiring that every derivative instrument be recorded in the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the statements of income and requires a company to formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment.
The Company has not yet quantified the impacts of adopting SFAS No. 133 on its financial statements and has not determined the timing of adoption. Based on the Company's current level of derivative and hedging activities, the Company does not expect the impact of adoption to be material.
YEAR 2000
The Company did not experience any significant operational difficulties or incur any significant expenses in connection with the Year 2000 issue. The Company will continue to monitor all critical systems for any incidents of delayed complications or disruptions and problems encountered through third parties with whom the Company deals so that they may be timely addressed.
INFORMATION REGARDING FORWARD LOOKING STATEMENTS
This Annual Report on Form 10-K includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical facts, including, among others, statements regarding the Company's future financial position, business strategy, budgets, reserve information, projected levels of production, exploration and development expenditures, projected costs and plans and objectives of management for future operations, are forward-looking statements. The Company typically uses words such as "expect," "anticipate," "estimate," "strategy," "intend," "plan" and "believe" or the negative of those terms or other variations of them or by comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning future operating results or the ability to generate income or cash flows are forward-looking statements. Although the Company believes its expectations reflected in forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will be achieved. Important factors that could cause actual results to differ materially from the expectations reflected in the forward-looking statements include, among others: timing and extent of changes in commodity prices for crude oil, natural gas and related products and interest rates; extent of the Company's success in discovering, developing, marketing and producing reserves and in acquiring oil and gas properties; political developments around the world; and financial market conditions.
In light of these risks, uncertainties and assumptions, the events anticipated by the Company's forward-looking statements might not occur. The Company undertakes no obligations to update or revise its forward-looking statements, whether as a result of new information, future events or otherwise.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's exposure to interest rate risk and commodity price risk is discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Capital Resources and Liquidity -- Financing" and "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Capital Resources and Liquidity -- Outlook," respectively. The Company's exposure to foreign currency exchange rate risks and other market risks is insignificant.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required hereunder is included in this report as set forth in the "Index to Financial Statements" on page.
ITEM 9.
ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this Item regarding directors is set forth in the Proxy Statement under the caption entitled "Election of Directors," and is incorporated herein by reference.
See list of "Current Executive Officers of the Registrant" in Part I located elsewhere herein.
There are no family relationships among the officers listed, and there are no arrangements or understandings pursuant to which any of them were elected as officers. Officers are appointed or elected annually by the Board of Directors at its first meeting following the Annual Meeting of Shareholders, each to hold office until the corresponding meeting of the Board in the next year or until a successor shall have been elected, appointed or shall have qualified.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is set forth in the Proxy Statement under the caption "Compensation of Directors and Executive Officers," and is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this Item is set forth in the Proxy Statement under the captions "Election of Directors" and "Compensation of Directors and Executive Officers," and is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item is set forth in the Proxy Statement under the caption "Certain Transactions," and is incorporated herein by reference.
PART IV
ITEM 14.
ITEM 14. FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE, EXHIBITS AND REPORTS ON FORM 8-K
(A)(1) AND (2) FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE
See "Index to Financial Statements" set forth on page.
(A)(3) EXHIBITS
See pages E-1 through E-4 for a listing of the exhibits.
(B) REPORTS ON FORM 8-K
The Company filed a Report on Form 8-K on August 31, 1999, to report the Share Exchange on August 16, 1999, in Item 2 -- Acquisition or Disposition of Assets, the change of the Company's name on August 30, 1999, in Item 5 -- Other Events, and pro forma financial information in Item 7 -- Financial Statements, Pro Forma Financial Information and Exhibits.
EOG RESOURCES, INC.
Other financial statement schedules have been omitted because they are inapplicable or the information required therein is included elsewhere in the consolidated financial statements or notes thereto.
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING
The following consolidated financial statements of EOG Resources, Inc. and its subsidiaries were prepared by management, which is responsible for their integrity, objectivity and fair presentation. The statements have been prepared in conformity with generally accepted accounting principles and, accordingly, include some amounts that are based on the best estimates and judgments of management.
Arthur Andersen LLP, independent public accountants, was engaged to audit the consolidated financial statements of EOG Resources, Inc. and its subsidiaries and issue a report thereon. In the conduct of the audit, Arthur Andersen LLP was given unrestricted access to all financial records and related data including minutes of all meetings of shareholders, the Board of Directors and committees of the Board. Management believes that all representations made to Arthur Andersen LLP during the audit were valid and appropriate.
The system of internal controls of EOG Resources, Inc. and its subsidiaries is designed to provide reasonable assurance as to the reliability of financial statements and the protection of assets from unauthorized acquisition, use or disposition. This system includes, but is not limited to, written policies and guidelines including a published code for the conduct of business affairs, conflicts of interest and compliance with laws regarding antitrust, antiboycott and foreign corrupt practices policies, the careful selection and training of qualified personnel, and a documented organizational structure outlining the separation of responsibilities among management representatives and staff groups.
The adequacy of financial controls of EOG Resources, Inc. and its subsidiaries and the accounting principles employed in financial reporting by the Company are under the general oversight of the Audit Committee of the Board of Directors. No member of this committee is an officer or employee of the Company. The independent public accountants and internal auditors have direct access to the Audit Committee and meet with the committee from time to time to discuss accounting, auditing and financial reporting matters. It should be recognized that there are inherent limitations to the effectiveness of any system of internal control, including the possibility of human error and circumvention or override. Accordingly, even an effective system can provide only reasonable assurance with respect to the preparation of reliable financial statements and safeguarding of assets. Furthermore, the effectiveness of an internal control system can change with circumstances.
It is management's opinion that, considering the criteria for effective internal control over financial reporting and safeguarding of assets which consists of interrelated components including the control environment, risk assessment process, control activities, information and communication systems, and monitoring, the Company maintained an effective system of internal control as to the reliability of financial statements and the protection of assets against unauthorized acquisition, use or disposition during the year ended December 31, 1999.
Houston, Texas March 2, 2000
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To EOG Resources, Inc.:
We have audited the accompanying consolidated balance sheets of EOG Resources, Inc. (formerly Enron Oil & Gas Company, a Delaware corporation) and subsidiaries as of December 31, 1999 and 1998, and the related consolidated statements of income and comprehensive income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1999. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and the schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of EOG Resources, Inc. and subsidiaries as of December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The financial statement schedule listed in the index to financial statements is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Houston, Texas March 2, 2000
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
The accompanying notes are an integral part of these consolidated financial statements.
EOG RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS (IN THOUSANDS)
ASSETS
The accompanying notes are an integral part of these consolidated financial statements.
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
The accompanying notes are an integral part of these consolidated financial statements.
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
The accompanying notes are an integral part of these consolidated financial statements.
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation. The consolidated financial statements of EOG Resources, Inc., formerly Enron Oil & Gas Company (the "Company") include the accounts of all domestic and foreign subsidiaries. All material intercompany accounts and transactions have been eliminated. Certain reclassifications have been made to the consolidated financial statements for prior years to conform with the current presentation.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.
Cash and Cash Equivalents. The Company records as cash equivalents all highly liquid short-term investments with original maturities of three months or less. The Company had approximately $23 million of outstanding checks payable classified as accounts payable at December 31, 1999.
Oil and Gas Operations. The Company accounts for its natural gas and crude oil exploration and production activities under the successful efforts method of accounting.
Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. Amortization of any remaining costs of such leases begins at a point prior to the end of the lease term depending upon the length of such term. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized over the average holding period. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.
Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of natural gas and crude oil, are capitalized.
Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. Estimated future dismantlement, restoration and abandonment costs (classified as long-term liabilities), net of salvage values, are taken into account. Certain other assets are depreciated on a straight-line basis. Periodically, or when circumstances indicate that an asset may be impaired, the Company compares expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on the Company's estimate of future crude oil and natural gas prices and operating costs and anticipated production from proved reserves are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.
Inventories, consisting primarily of tubular goods and well equipment held for use in the exploration for, and development and production of natural gas and crude oil reserves, are carried at cost with adjustments made from time to time to recognize changes in value.
Natural gas revenues are recorded on the entitlement method based on the Company's percentage ownership of current production. Each working interest owner in a well generally has the right to a specific percentage of production, although actual production sold may differ from an owner's ownership percentage.
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Under entitlement accounting, a receivable is recorded when underproduction occurs and a payable when overproduction occurs.
Gains and losses associated with the sale of in place natural gas and crude oil reserves and related assets are classified as net operating revenues in the consolidated statements of income and comprehensive income based on the Company's strategy of continuing such sales in order to maximize the economic value of its assets.
Accounting for Price Risk Management. The Company engages in price risk management activities from time to time primarily for non-trading and to a lesser extent for trading purposes. Derivative financial instruments (primarily price swaps and costless collars) are utilized selectively for non-trading purposes to hedge the impact of market fluctuations on natural gas and crude oil market prices. Hedge accounting is utilized in non-trading activities when there is a high degree of correlation between price movements in the derivative and the item designated as being hedged. Gains and losses on derivative financial instruments used for hedging purposes are recognized as revenue in the same period as the hedged item. Gains and losses on hedging instruments that are closed prior to maturity are deferred in the consolidated balance sheets. In instances where the anticipated correlation of price movements does not occur, hedge accounting is terminated and future changes in the value of the derivative are recognized as gains or losses using the mark-to-market method of accounting. Derivative and other financial instruments utilized in connection with trading activities, primarily price swaps and call options, are accounted for using the mark-to-market method, under which changes in the market value of outstanding financial instruments are recognized as gains or losses in the period of change. The cash flow impact of derivative and other financial instruments used for non- trading and trading purposes is reflected as cash flows from operating activities in the consolidated statements of cash flows.
Capitalized Interest Costs. Certain interest costs have been capitalized as a part of the historical cost of unproved oil and gas properties and in work in progress for exploratory drilling and related facilities with significant cash outlays.
Income Taxes. The Company accounts for income taxes under the provisions of SFAS No. 109 -- "Accounting for Income Taxes." SFAS No. 109 requires the asset and liability approach for accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases (See Note 8 "Income Taxes").
Foreign Currency Translation. For subsidiaries whose functional currency is deemed to be other than the U.S. dollar, asset and liability accounts are translated at year-end exchange rates and revenue and expenses are translated at average exchange rates prevailing during the year. Translation adjustments are included as a separate component of shareholders' equity. Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period.
Net Income Per Share. In accordance with the provisions of SFAS No. 128 -- "Earnings per Share," basic net income per share is computed on the basis of the weighted-average number of common shares outstanding during the periods. Diluted net income per share is computed based upon the weighted-average number of common shares plus the assumed issuance of common shares for all potentially dilutive securities. (See Note 10 "Net Income Per Share Available to Common" for additional information to reconcile the difference between the Average Number of Common Shares outstanding for basic and diluted net income per share).
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
2. NATURAL GAS AND CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS NET OPERATING REVENUES
Natural gas revenues, trade for 1999, 1998 and 1997 are net of costs of natural gas purchased for sale related to natural gas marketing activities of $44.6 million, $44.8 million and $73.6 million, respectively. Natural gas revenues, associated for 1999, 1998 and 1997 are net of costs of natural gas purchased for sale related to natural gas marketing activities of $13.5 million, $51.0 million and $47.7 million, respectively.
In March 1995, in a series of transactions with Enron Corp. and an affiliate of Enron Corp., the Company exchanged all of its fuel supply and purchase contracts and related price swap agreements associated with a Texas City cogeneration plant (the "Cogen Contracts") for certain natural gas price swap agreements of equivalent value issued by the affiliate that are designated as hedges (the "Swap Agreements"). Such Swap Agreements were closed on March 31, 1995. As a result of the transactions, the Company was relieved of all performance obligations associated with the Cogen Contracts. The Company realized net operating revenues and received corresponding cash payments of approximately $91 million during the period extending through December 31, 1999, under the terms of the closed Swap Agreements. The estimated fair value of the Swap Agreements was approximately $81 million at the date the Swap Agreements were received in exchange for the Cogen Contracts. The net effect of this series of transactions resulted in increases in net operating revenues and cash receipts for the Company during 1995 and 1996 of approximately $13 million and $7 million, respectively, with offsetting decreases in 1998 and 1999 versus that anticipated under the Cogen Contracts.
3. OTHER ASSETS
In December 1997, the Company and Enron Corp. entered into an Equity Participation and Business Opportunity Agreement. Among other things, under the agreement, Enron Corp. granted to the Company options to purchase 3.2 million shares of Enron Corp. common stock at a price of $39.1875 per share which was the closing price of the stock on the date that the agreement was approved by the Board of Directors of the Company. Other Assets at December 31, 1998 includes $23.3 million or $7.29 per share representing the estimated fair value of the Enron Corp. stock options at the date of grant. Such estimated fair value was determined using the Black-Scholes option-pricing model with the following weighted-average assumptions at the date the options were issued: (1) dividend yield of 2.5%, (2) expected volatility of 17.5%, (3) risk-free interest rate of 5.85%, and (4) expected average life of 4.0 years. Receipt of the options represented a capital contribution from Enron Corp. and, accordingly, the fair value received, net of tax effects of $8.2 million, was credited to Additional Paid In Capital.
During the first and second quarters of 1999, the Company sold the 3.2 million options to purchase common stock of Enron Corp. In the first quarter of 1999, the Company sold 1.6 million options at an average price of $24.81 ($64.00 Enron Corp. stock price equivalent), realizing net proceeds of $40 million and a gain of $28 million pre-tax ($18 million after-tax). Early in the second quarter, the Company sold the remaining 1.6 million options at an average price of $27.07 ($66.26 Enron Corp. stock price equivalent), realizing net proceeds of $43 million and a gain of $32 million pre-tax ($21 million after-tax). The gain on sale of the options is included in other income (expense) - other, net in the Consolidated Statements of Income and Comprehensive Income. These transactions were completed prior to Enron Corp. effecting a two-for-one stock split.
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
4. LONG-TERM DEBT
Long-Term Debt at December 31 consisted of the following:
During 1999, the Company entered into two new credit facilities with domestic and foreign banks which provide for an aggregate of $800 million in long-term committed credit, with $400 million expiring in 2000 and $400 million expiring in 2004, and concurrently cancelled the existing $450 million facility. With respect to the $400 million expiring in 2000, the Company may, at its option, extend the final maturity date of any advances made under the facility by one full year from the expiration date of the facility, effectively qualifying such debt as long-term. Advances under both agreements bear interest, at the option of the Company, based upon a base rate or a Eurodollar rate. At December 31, 1999, there were no advances outstanding under either of these agreements.
Commercial paper and short-term funding from uncommitted credit facilities provide financing for various corporate purposes and bear interest based upon market rates. Commercial paper and uncommitted credit are classified as long-term debt based on the Company's intent and ability to ultimately replace such amounts with other long-term debt. (See Note 14 "Price and Interest Rate Risk Management").
The 6.00% to 6.70% Notes due 2004 to 2028 were issued through public offerings and have effective interest rates of 6.14% to 6.83%. The Subsidiary Debt due 2001 bears interest at variable market-based rates and is guaranteed by the Company.
At December 31, 1999, the aggregate annual maturities of long-term debt outstanding were less than $1.0 million for 2000, $105 million for 2001, none for 2002 and 2003 and $100 million for 2004.
See Note 14 "Price and Interest Rate Risk Management."
Shelf Registration. The Company may sell from time to time up to an aggregate of approximately $88 million in debt securities and/or common stock pursuant to an effective "shelf" registration statement filed with the Securities and Exchange Commission.
Financing Arrangements With Enron Corp. Prior to August 16, 1999, the Company engaged in various transactions with Enron Corp. that were characteristic of a consolidated group under common control. Accordingly, the Company maintained reciprocal agreements with Enron Corp. that provided for the borrowing by the Company of up to $200 million and investing by the Company of surplus funds of up to $200 million at market-based interest rates. Advances from Enron Corp. of $200 million were outstanding at December 31, 1998, and such balances were classified as long-term based on the Company's intent and ability
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
to ultimately replace such amounts with other long-term debt. The reciprocal agreements terminated on August 16, 1999 upon the closing of the Share Exchange. There were no investments with Enron Corp. at December 31, 1998 or 1999. (See Note 14 "Price and Interest Rate Risk Management").
Fair Value Of Long-Term Debt. At December 31, 1999 and 1998, the Company had $990 million and $1,143 million, respectively, of long-term debt which had fair values of approximately $933 million and $1,141 million, respectively. The fair value of long-term debt is the value the Company would have to pay to retire the debt, including any premium or discount to the debtholder for the differential between the stated interest rate and the year-end market rate. The fair value of long-term debt is based upon quoted market prices and, where such quotes were not available, upon interest rates available to the Company at year-end.
5. VOLUMETRIC PRODUCTION PAYMENT
In September 1992, the Company sold a volumetric production payment for $326.8 million to a limited partnership. Under the terms of the production payment, as amended October 1, 1993, the Company conveyed a real property interest in certain natural gas and other hydrocarbons to the purchaser. Deliveries were scheduled at the rate of 50 billion British thermal units per day through March 31, 1999. The Company accounted for the proceeds received in the transaction as deferred revenue, which was amortized into revenue and income as natural gas and other hydrocarbons were produced and delivered during the term of the volumetric production payment agreement. In December 1998, the Company settled the remainder of the contract in cash which was not materially different from the recorded deferred revenue, and delivery obligations were terminated.
6. SHAREHOLDERS' EQUITY
The Board of Directors of the Company has approved an authorization for purchasing and holding in treasury at any time up to 1,000,000 shares of common stock of the Company for the purpose of, but not limited to, meeting obligations associated with the exercise of stock options granted to qualified employees pursuant to the Company's stock option plans. The Board of Directors has also approved the selling from time to time, subject to certain conditions, of put options on the common stock of the Company. The 1,000,000 share limit mentioned above applies to shares held in treasury and unexpired put options outstanding. In February 1997, as amended in February 1998, the Board of Directors authorized the additional purchase of up to an aggregate maximum of 10 million shares of common stock of the Company from time to time in the open market to be held in treasury for the purpose of, but not limited to, fulfilling any obligations arising under the Company's stock option plans and any other approved transactions or activities for which such common stock shall be required. At December 31, 1999 and 1998, 5,625,446 shares and 6,276,156 shares, respectively, were held in treasury under these authorizations. In February 2000, the Board of Directors authorized the purchase of an aggregate maximum of 10 million shares of common stock of the Company which replaced the remaining authorization from February 1998. (See Note 9 "Commitments and Contingencies -- Treasury Shares"). The Company has, from time to time, entered into transactions in which it writes put options on its own common stock. At December 31, 1999, there were no put options outstanding. At December 31, 1998, there were put options outstanding for 175,000 shares of common stock.
On July 23, 1999, the Company filed a registration statement with the Securities and Exchange Commission for the public offering of 27,000,000 shares of the Company's common stock. The public offering was completed on August 16, 1999, and the net proceeds were used to repay short-term borrowings used to fund a significant portion of the cash capital contribution in connection with the Share Exchange Agreement ("Share Exchange") described in Note 7 "Transactions with Enron Corp. and Related Parties." As a result of the public offering and the retirement of the 62,270,000 shares of the Company's common stock received from Enron Corp. in the Share Exchange transaction, the number of shares of the Company's common stock issued was reduced to 124,730,000 from 160,000,000 prior to the Share Exchange.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In December 1999, the Company issued the following two series of preferred stock:
Series A. On December 10, 1999 the Company issued 100,000 shares of Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series A, with a $1,000 Liquidation Preference per share, in a private transaction. Subject to the terms of a registration rights agreement, the Company is required to register these shares for public sale within 150 days of the issuance date. Dividends will be payable on the shares only if declared by the Company's board of directors and will be cumulative. If declared, dividends will be payable at a rate of $71.95 per share, per year on March 15, June 15, September 15, and December 15 of each year beginning March 15, 2000. The dividend rate may only be adjusted in the event that certain amendments are made to the Dividend Received Percentage within the first 18 months of the issuance date. The Company may redeem all or a part of the Series A preferred stock at any time beginning on December 15, 2009 at $1,000 per share, plus accrued and unpaid dividends. The shares may also be redeemable, in whole but not in part, in the event that certain amendments are made to the Dividend Received Percentage. The Series A preferred shares are not convertible into, or exchangeable for, common stock of the Company.
Series C. On December 22, 1999, the Company issued 500 shares of Flexible Money Market Cumulative Preferred Stock, Series C, with a liquidation preference of $100,000 per share, in a private transaction. Subject to the terms of a registration rights agreement, the Company is required to register these shares for public sale within 150 days of the issuance date. Dividends will be payable on the shares only if declared by the Company's board of directors and will be cumulative. The initial dividend rate on the shares will be 6.84% until December 15, 2004 (the "Initial Period-End Dividend Payment Date"). Through the Initial Period-End Dividend Payment Date dividends will be payable, if declared, on March 15, June 15, September 15, and December 15 of each year beginning March 15, 2000. The cash dividend rate for each subsequent dividend period will be determined pursuant to periodic auctions conducted in accordance with certain auction procedures. The first auction date will be December 14, 2004. After December 15, 2004 (unless the Company has elected a "Non-Call Period" for a subsequent dividend period), the Company may redeem the shares, in whole or in part, on any dividend payment date at $100,000 per share upon the payment of accumulated and unpaid dividends. The shares may also be redeemable, in whole but not in part, in the event that certain amendments are made to the Dividend Received Percentage. The Series C preferred shares are not convertible into, or exchangeable for, common stock of the Company.
7. TRANSACTIONS WITH ENRON CORP. AND RELATED PARTIES
On August 16, 1999, the Company and Enron Corp. completed the Share Exchange whereby the Company received 62,270,000 shares of the Company's common stock out of 82,270,000 shares owned by Enron Corp. in exchange for all the stock of the Company's subsidiary, EOGI-India, Inc. Prior to the Share Exchange, the Company made an indirect capital contribution of approximately $600 million in cash, plus certain intercompany receivables, to EOGI-India, Inc. At the time of completion of this transaction, this subsidiary owned, through subsidiaries, all of the Company's assets and operations in India and China. The Company recognized a $575 million tax-free gain on the Share Exchange based on the fair value of the shares received, net of transaction fees of $14 million. Immediately following the Share Exchange, the Company retired the 62,270,000 shares of the Company's common stock received in the transaction. The weighted average basis in the treasury shares retired was first deducted from and fully eliminated existing additional paid in capital with the remaining value deducted from retained earnings. This transaction is a tax-free exchange to the Company. On August 30, 1999, the Company changed its corporate name to "EOG Resources, Inc." from "Enron Oil & Gas Company" and has since made similar changes to its subsidiaries' names.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Immediately prior to the closing of the Share Exchange, Enron Corp. owned 82,270,000 shares of the Company's common stock, representing approximately 53.5 percent of all of the shares of the Company's common stock that were issued and outstanding. As a result of the closing of the Share Exchange, the sale by Enron Corp. of 8,500,000 shares of the Company's common stock as a selling stockholder in the public offering referred to above, and the completion on August 17, 1999 and August 20, 1999 of the offering of Enron Corp. notes mandatorily exchangeable at maturity into up to 11,500,000 shares of the Company's common stock, Enron Corp's maximum remaining interest in the Company after the automatic conversion of its notes on July 31, 2002, will be under two percent (assuming the notes are exchanged for less than the 11,500,000 shares of the Company's common stock). As a result, beginning with the Share Exchange all transactions with Enron Corp. and its affiliates have been classified as Trade.
Effective as of August 16, 1999, the closing date of the Share Exchange, the members of the board of directors of the Company who were officers or directors of Enron Corp. resigned their positions as directors of the Company.
Business Opportunity Agreement. In December 1997, Enron Corp. and the Company entered into the Equity Participation and Business Opportunity Agreement ("Business Opportunity Agreement") which defined certain obligations that Enron Corp. owed to the Company and relieved Enron Corp. from certain obligations to the Company that it might otherwise have, including the obligation to offer certain business opportunities to the Company. The Business Opportunity Agreement was approved by the Board of Directors of the Company after it was approved unanimously by a special committee of the Board of Directors consisting of the Company's independent directors.
The Business Opportunity Agreement provided generally that, so long as such activities were conducted in compliance with the Business Opportunity Agreement in all material respects, Enron Corp. could pursue business opportunities independently of the Company.
In consideration for the Company's agreements in the Business Opportunity Agreement, Enron Corp. provided valuable consideration to the Company, including options to purchase common stock of Enron Corp., all of which were sold by the Company during 1999 (see Note 3 "Other Assets").
Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues. Prior to the Share Exchange, Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues included revenues from and associated costs paid to various subsidiaries and affiliates of Enron Corp. pursuant to contracts which, in the opinion of management, were no less favorable than could be obtained from third parties. (See Note 2 "Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues"). Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues also included certain commodity price swap and NYMEX-related commodity transactions with Enron Corp. affiliated companies, which in the opinion of management, were no less favorable than could be received from third parties. (See Note 14 "Price and Interest Rate Risk Management").
General and Administrative Expenses. Prior to the Share Exchange, the Company was charged by Enron Corp. for all direct costs associated with its operations. Such direct charges, excluding benefit plan charges (See Note 9 "Commitments and Contingencies -- Employee Benefit Plans"), totaled $10.6 million, $14.2 million and $16.1 million for the years ended December 31, 1999, 1998 and 1997, respectively. Additionally, certain administrative costs not directly charged to any Enron Corp. operations or business segments were allocated to the entities of the consolidated group. Approximately $3.4 million, $5.1 million and $5.3 million was incurred by the Company for indirect general and administrative expenses for 1999, 1998 and 1997, respectively. Management believes that these charges were reasonable.
Financing. See Note 4 "Long-Term Debt -- Financing Arrangements with Enron Corp." for a discussion of financing arrangements with Enron Corp.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
8. INCOME TAXES
The principal components of the Company's net deferred income tax liability at December 31, 1999 and 1998 were as follows:
The components of income (loss) before income taxes were as follows:
Total income tax provision (benefit) was as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The differences between taxes computed at the U.S. federal statutory tax rate and the Company's effective rate were as follows:
In 1997, the Company and Enron Corp. agreed to replace an existing tax allocation agreement with a new tax allocation agreement. In the new agreement, Enron Corp. agreed to refund a $13 million payment made by the Company pursuant to the existing agreement, the Company agreed to release Enron Corp. from the liabilities assumed related to the $13 million payment and the parties agreed to indemnify each other in a manner consistent with a former agreement. Enron Corp. also advanced the Company approximately $50 million to fund certain federal income taxes related to the 1995 taxable year. This advance was scheduled to be repaid in annual installments through January 1, 2001. Final payment to Enron was made on August 16, 1999.
The Company's foreign subsidiaries' undistributed earnings of approximately $275 million at December 31, 1999 are considered to be indefinitely invested outside the U.S. and, accordingly, no U.S. federal or state income taxes have been provided thereon. Upon distribution of those earnings in the form of dividends, the Company may be subject to both foreign withholding taxes and U.S. income taxes, net of allowable foreign tax credits. Determination of any potential amount of unrecognized deferred income tax liabilities is not practicable.
The Company has an alternative minimum tax ("AMT") credit carryforward of $22 million which can be used to offset regular income taxes payable in future years. The AMT credit carryforward has an indefinite carryforward period.
In 1999, the Company entered into an arrangement with a third party whereby certain Section 29 credits were sold by the Company to the third party, and payments for such credits will be received on an as-generated basis. As a result of this transaction, the Company recorded a deferred tax asset representing a tax gain on the sale of the Section 29 credit properties, which will reverse as the operation of such properties are recognized for book purposes.
9. COMMITMENTS AND CONTINGENCIES
Employee Benefit Plans. Employees of the Company were covered by various retirement, stock purchase and other benefit plans of Enron Corp. through August 1999. During each of the years ended December 31, 1999, 1998, and 1997, the Company was charged $4.4 million, $6.4 million and $5.0 million, respectively, for all such benefits, including pension expense totaling $.9 million, $1.3 million and $1.0 million, respectively, by Enron Corp.
Since August 1999, the Company has adopted defined contribution pension plans for most of its employees in the United States. The Company's contributions to these plans are based on various percentages of compensation, and in some instances are based upon the amount of the employees' contributions to the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
plan. From August 31, 1999 to December 31, 1999 the cost of these plans amounted to approximately $1.2 million, a substantial part of which was funded currently.
The Company also has in effect pension and savings plans related to its Canadian and Trinidadian subsidiaries. Activity related to these plans is not material relative to the Company's operations.
Stock Plans
Stock Options. The Company has various stock plans ("the Plans") under which employees of the Company and its subsidiaries and nonemployee members of the Board of Directors have been or may be granted rights to purchase shares of common stock of the Company at a price not less than the market price of the stock at the date of grant. Stock options granted under the Plans vest over a period of time based on the nature of the grants and as defined in the individual grant agreements. Terms for stock options granted under the Plans have not exceeded a maximum term of 10 years.
The Company accounts for the stock options under the provisions and related interpretations of Accounting Principles Board Opinion No. 25 ("APB No. 25") -- "Accounting for Stock Issued to Employees." No compensation expense is recognized for such options. As allowed by SFAS No. 123 -- "Accounting for Stock-Based Compensation" issued in 1995, the Company has continued to apply APB No. 25 for purposes of determining net income and to present the pro forma disclosures required by SFAS No. 123.
The following table sets forth the option transactions under the Plans for the years ended December 31 (options in thousands):
The fair value of each option grant is estimated using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants in 1999, 1998, and 1997, respectively: (1) dividend yield of 0.6%, 0.6% and 0.6%, (2) expected volatility of 28%, 26%, and 27%, (3) risk-free interest rate of 5.9%, 5.1%, and 6.3%, and (4) expected life of 6.0 years, 4.9 years and 5.2 years.
During 1997, in response to extremely competitive conditions for technical personnel, the Company cancelled options issued in 1996 to purchase 1,282,000 shares of common stock at an exercise price of $25.38 per share, and reissued the same number of options with an exercise price of $18.25 per share. The reissue did not involve any executive officers of the Company.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table summarizes certain information for the options outstanding at December 31, 1999 (options in thousands):
The Company's pro forma net income and net income per share of common stock for 1999, 1998 and 1997, had compensation costs been recorded in accordance with SFAS No. 123, are presented below (in millions except per share data):
The effects of applying SFAS No. 123 in this pro forma disclosure should not be interpreted as being indicative of future effects. SFAS No. 123 does not apply to awards prior to 1995, and the extent and timing of additional future awards cannot be predicted.
The Black-Scholes model used by the Company to calculate option values, as well as other currently accepted option valuation models, were developed to estimate the fair value of freely tradable, fully transferable options without vesting and/or trading restrictions, which significantly differ from the Company's stock option awards. These models also require highly subjective assumptions, including future stock price volatility and expected time until exercise, which significantly affect the calculated values. Accordingly, management does not believe that this model provides a reliable single measure of the fair value of the Company's stock option awards.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Restricted Stock. Under the Plans, participants may be granted restricted stock without cost to the participant. The shares granted vest to the participant at various times ranging from one to seven years. Upon vesting, the shares are released to the participants. The following summarizes shares of restricted stock granted:
The fair value of the restricted shares at date of grant has been recorded in shareholders' equity as unearned compensation and is being amortized as compensation expense. Related compensation expense for 1999, 1998 and 1997 was approximately $3.1 million, $1.5 million and $1.0 million, respectively.
Treasury Shares. During 1999, 1998 and 1997, the Company purchased or was tendered 130,000, 1,590,200, and 4,954,344 of its common shares, respectively, and delivered such shares upon the exercise of stock options and awards of restricted stock, except for shares held in treasury at December 31, 1999, 1998 and 1997. The difference between the cost of the treasury shares and the exercise price of the options, net of federal income tax benefit of $1.4 million, $.3 million, and $.5 million for the years 1999, 1998 and 1997, respectively, is reflected as an adjustment to Additional Paid In Capital through August 1999 and Retained Earnings thereafter as a result of the share retirement described in Note 7. In December 1992, as amended in September 1994 and December 1996, the Company commenced a stock repurchase program of up to 1,000,000 shares authorized by the Board of Directors to facilitate the availability of treasury shares of common stock for, but not limited to, the settlement of employee stock option exercises pursuant to the Plans. In February 1997 as amended in February 1998, the Board of Directors authorized the additional purchase of up to 10 million shares for similar purposes. At December 31, 1999 and 1998, 5,625,446 and 6,276,156 shares, respectively, were held in treasury under these authorizations. In February 2000, the Board of Directors authorized the purchase of an aggregate maximum of 10 million shares of common stock of the Company which replaced the remaining authorization from February 1998. (See Note 6 "Shareholders' Equity").
Letters Of Credit. At December 31, 1999 and 1998, the Company had letters of credit and guaranties outstanding totaling approximately $118 million and $127 million, respectively.
Contingencies. On July 21, 1999, two stockholders of the Company filed separate lawsuits purportedly on behalf of the Company against Enron Corp. and those individuals who were then directors of the Company, alleging that Enron Corp. and those directors breached their fiduciary duties of good faith and loyalty in approving the Share Exchange. The lawsuits seek to rescind the transaction or to receive monetary damages and costs and expenses, including reasonable attorneys' and experts' fees. The Company, Enron Corp. and the individual defendants believe the lawsuits are without merit and intend to vigorously contest them. There are various other suits and claims against the Company that have arisen in the ordinary course of business. However, management does not believe these suits and claims will individually or in the aggregate have a material adverse effect on the financial condition or results of operations of the Company. The Company has been named as a potentially responsible party in certain Comprehensive Environmental Response Compensation and Liability Act proceedings. However, management does not believe that any potential assessments resulting from such proceedings will individually or in the aggregate have a materially adverse effect on the financial condition or results of operations of the Company.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
10. NET INCOME PER SHARE AVAILABLE TO COMMON
The difference between the Average Number of Common Shares outstanding for basic and diluted net income per share of common stock is due to the assumed issuance of approximately 1,483,132, 709,000, and 784,000 common shares relating to employee stock options in 1999, 1998 and 1997, respectively.
11. CASH FLOW INFORMATION
On August 16, 1999, the Company and Enron Corp. completed the Share Exchange whereby the Company received 62,270,000 shares of the Company's common stock out of 82,270,000 shares owned by Enron Corp. in exchange for all the stock of the Company's subsidiary, EOGI-India, Inc (see Note 7 "Transactions with Enron Corp. and Related Parties"). Prior to the Share Exchange, the Company made an indirect capital contribution of approximately $600 million in cash, plus certain intercompany receivables, to EOGI-India, Inc. At the time of completion of this transaction, the Company's net investment in EOGI-India, Inc. was $870 million.
On December 31, 1999, the Company completed an exchange agreement with OXY USA Inc. The acquired properties were assigned the net book value of the properties transferred of $88 million, resulting in no gain or loss.
Cash paid for interest and income taxes was as follows for the years ended December 31:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
12. BUSINESS SEGMENT INFORMATION
The Company's operations are all natural gas and crude oil exploration and production related. The Company adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," during the fourth quarter of 1998. SFAS No. 131 establishes standards for reporting information about operating segments in annual financial statements and requires selected information about operating segments in interim financial reports. Operating segments are defined as components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker, or decision making group, in deciding how to allocate resources and in assessing performance. The Company's chief operating decision making group is the Executive Committee, which consists of the Chairman and Chief Executive Officer and other key officers. This group routinely reviews and makes operating decisions related to significant issues associated with each of the Company's major producing areas in the United States and each significant international location. For segment reporting purposes, the major U.S. producing areas have been aggregated as one reportable segment due to similarities in their operations as allowed by SFAS No. 131. Financial information by reportable segment is presented below for the years ended December 31, or at December 31:
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(1) See Note 7 "Transactions with Enron Corp. and Related Parties."
(2) Other includes China operations. See Note 7 "Transactions with Enron Corp. and Related Parties."
(3) Sales activity with a certain purchaser in the United States and Canada segments totaled approximately $98,100 of the consolidated Net Operating Revenues.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
13. OTHER INCOME (EXPENSE), NET
Other income (expense), net consisted of the following for the years ended December 31:
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(1) Includes $102 in 1998 and $2,549 in 1997 from related parties.
(2) Pertains to provisions for doubtful accounts receivable associated with certain international activities.
(3) See Note 3 "Other Assets."
(4) Relates to anticipated costs of abandonment of certain international activity.
14. PRICE AND INTEREST RATE RISK MANAGEMENT
Periodically, the Company enters into certain trading and non-trading activities including NYMEX-related commodity market transactions and other contracts. The non-trading portions of these activities have been designated to hedge the impact of market price fluctuations on anticipated commodity delivery volumes or other contractual commitments.
Trading Activities. In 1999, no trading transactions were executed. Trading activities in 1998 included a revenue increase of $1.1 million related to change in market value of natural gas price swap options exercisable by a counterparty and partially offsetting "buy" price swap positions.
During 1995, the Company entered into a NYMEX-related natural gas price swap covering 73 trillion British thermal units ("TBtu") for the year ended December 31, 1996. This swap contained an option to extend the price swap covering 73 TBtu for each of the years 1997 and 1998 which was exercisable at one time prior to December 31, 1996. The 1996 price swap was closed in the first quarter of 1996. During 1996, this option was restructured into four options each exercisable, in total, at one time by the counterparty before December 31, 1996, 1997, 1998 and 1999 to purchase 37 TBtu of notional natural gas for each of the years 1997, 1998, 1999 and 2000 at an average fixed price of $1.98, $1.98, $1.93 and $1.93 per million British thermal units ("MMBtu"), respectively. The 1997 and 1998 options were subsequently restructured to be exercisable monthly at a price of $2.16 and $2.07 per MMBtu, respectively. These options cover notional volumes averaging 3 TBtu per month during 1997 and 1998. During the fourth quarter of 1996, the 1999 and 2000 options were terminated. In 1996, the Company entered into "buy" NYMEX-related natural gas price swap positions in the same notional quantities and maturities as are covered by the 1997 and 1998 options. The Company recognized a $1.1 million and $3.4 million revenue increase in 1998 and 1997, respectively, related to these trading activities.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table summarizes the estimated fair value of financial instruments held for trading purposes at year-end and the average during the year:
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(1) Estimated fair values have been determined by using available market data and valuation methodologies. Judgment is necessarily required in interpreting market data and the use of different market assumptions or estimation methodologies may affect the estimated fair value amounts.
Interest Rate Swap Agreements and Foreign Currency Contracts. At December 31, 1999 and 1998, a subsidiary of the Company and the Company are parties to offsetting foreign currency and interest rate swap agreements with an aggregate notional principal amount of $210 million. Such swap agreements are scheduled to terminate in 2001. At December 31, 1999 and 1998, the composite fair value of the agreements was not significant based upon termination values obtained from third parties. In November 1998, the Company entered into two interest rate swap agreements having notional values of $100 million each. The agreements were entered into to hedge the base variable interest rates of the Company's commercial paper, uncommitted credit facilities and affiliated borrowings. The Company anticipates having such borrowings outstanding of at least the notional amounts under the swap agreements during the term of the swap agreements. Under the agreements, the Company will pay interest based on fixed rates of approximately 4.96% and 5.01% and receive interest based on the three-month LIBOR calculated on the notional value of the swap agreements. These agreements are scheduled to terminate in November 2000. At December 31, 1999, the composite fair value of these agreements was $2.6 million.
Hedging Transactions. With the objective of enhancing the certainty of future revenues, the Company from time to time enters into NYMEX-related commodity price swaps and costless collars. Using NYMEX-related commodity price swaps, the Company receives a fixed price for the respective commodity hedged and pays a floating market price, as defined for each transaction, to the counterparty at settlement.
At December 31, 1999, the Company had outstanding positions covering notional volumes of .5 million barrels ("MMBbl") of crude oil and condensate for 2000. The fair value of these positions was approximately $2 million negative. At December 31, 1999, the Company had closed positions covering notional volumes of approximately 4 TBtu of natural gas for each of the years 2000 through 2005. The Company also had closed positions covering 1.7 MMBbl of crude oil and condensate for the year 2000. At December 31, 1999, the aggregate deferred revenue reduction for 2000, 2001 and thereafter was approximately $12 million, $1 million and $5 million, respectively, and is classified as "Other Assets."
At December 31, 1998, the Company had outstanding positions covering notional volumes of .7 MMBbl of crude oil and condensate for 1999. The fair value of the positions was approximately $4 million. In 1998, the Company closed positions covering notional volumes of approximately 4 TBtu of natural gas for each of the years 1999 through 2005. The Company also recorded closed positions covering 2.2 MMBbl and 1.7 MMBbl of crude oil and condensate for the years 1999 and 2000, respectively. At December 31, 1998, the aggregate deferred revenue reduction for 1999, 2000 and thereafter was approximately $13 million, $12 million and $6 million, respectively, and is classified as "Other Assets."
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table summarizes the estimated fair value of financial instruments and related transactions for non-trading activities at December 31, 1999 and 1998:
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(1) Estimated fair values have been determined by using available market data and valuation methodologies. Judgment is necessarily required in interpreting market data and the use of different market assumptions or estimation methodologies may affect the estimated fair value amounts.
(2) See Note 4 "Long-Term Debt."
Credit Risk. While notional contract amounts are used to express the magnitude of price and interest rate swap agreements, the amounts potentially subject to credit risk, in the event of nonperformance by the other parties, are substantially smaller. The Company does not anticipate nonperformance by the other parties.
15. CONCENTRATION OF CREDIT RISK
Substantially all of the Company's accounts receivable at December 31, 1999 and 1998 result from crude oil and natural gas sales and/or joint interest billings to affiliate and third party companies including foreign state-owned entities in the oil and gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. In determining whether or not to require collateral from a customer or joint interest owner, the Company analyzes the entity's net worth, cash flows, earnings, and credit ratings. Receivables are generally not collateralized. Historical credit losses incurred on receivables by the Company have been immaterial.
16. ACCOUNTING FOR CERTAIN LONG-LIVED ASSETS
As a result of the change to the Company's portfolio of assets brought about by the Share Exchange (see Note 7 "Transactions with Enron Corp. and Related Parties"), the Company conducted a re-evaluation of its overall business. As a result of this re-evaluation, some of the Company's projects were no longer deemed central to its business. The Company recorded non-cash charges in connection with the impairment and/or the Company's decision to dispose of such projects of $133 million pre-tax ($89 million after-tax). In addition, the Company recorded charges of $15 million pre-tax ($10 million after-tax) pursuant to a change in the Company's strategy related to certain offshore operations in the second quarter and an impairment of various North America properties in the fourth quarter to depreciation, depletion and amortization expense. In the United States operating segment, a pre-tax impairment charge of $85 million was recorded to depreciation, depletion and amortization expense. The carrying values for assets determined to be impaired were adjusted to estimated fair values based on projected future discounted net cash flows for such assets. In the Other operating segment, a pre-tax charge of $36 million was recorded to depreciation, depletion and amortization expense to fully write-off the Company's basis and a pre-tax charge of $19 million was recorded to other income (expense) -- other, net for the estimated exit costs related to the Company's decision to dispose of certain international operations. Net loss for the Other operating segment operations for 1999, excluding these charges, was approximately $3 million.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
17. NEW ACCOUNTING PRONOUNCEMENT -- SFAS NO. 133
In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133 -- "Accounting for Derivative Instruments and Hedging Activities" effective for fiscal years beginning after June 15, 1999. In June 1999, the FASB issued SFAS No. 137, which delays the effective date of SFAS No. 133 for one year, to fiscal years beginning after June 15, 2000. SFAS No. 133, as amended by SFAS No. 137, cannot be applied retroactively and must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts that were issued, acquired or substantively modified after a transition date to be selected by the Company of either December 31, 1997 or December 31, 1998.
The statement establishes accounting and reporting standards requiring that every derivative instrument be recorded in the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the statements of income and requires a company to formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment.
The Company has not yet quantified the impacts of adopting SFAS No. 133 on its financial statements and has not determined the timing of adoption. Based on the Company's current level of derivative and hedging activities, the Company does not expect the impact of adoption to be material.
18. SUBSEQUENT EVENT
On February 14, 2000, the Company's Board of Directors declared a dividend of one preferred share purchase right (a "Right" or "Rights Agreement") for each outstanding share of common stock, par value $.01 per share. The Board of Directors has adopted this Rights Agreement to protect stockholders from coercive or otherwise unfair takeover tactics. The dividend was distributed to the stockholders of record on February 24, 2000. Each Right, expiring February 24, 2010, represents a right to buy from the Company one hundredth ( 1/100) of a share of Series E Junior Participating Preferred Stock ("Preferred Share") for $90, once the Rights become exercisable. This portion of a Preferred Share will give the stockholder approximately the same dividend, voting, and liquidation rights as would one share of common stock. Prior to exercise, the Right does not give its holder any dividend, voting, or liquidation rights. If issued, each one hundredth ( 1/100) of a Preferred Share (i) will not be redeemable; (ii) will entitle holders to quarterly dividend payments of $.01 per share, or an amount equal to the dividend paid on one share of common stock, whichever is greater; (iii) will entitle holders upon liquidation either to receive $1 per share or an amount equal to the amount made on one share of common stock, whichever is greater; (iv) will have the same voting power as one share of common stock; and (v) if shares of the Company's common stock are exchanged via merger, consolidation, or a similar transaction, will entitle holders to a per share payment equal to the payment made on one share of common stock.
The Rights will not be exercisable until ten days after the public announcement that a person or group has become an acquiring person ("Acquiring Person") by obtaining beneficial ownership of 15% or more of the Company's common stock, or if earlier, ten business days (or a later date determined by the Company's Board of Directors before any person or group becomes an Acquiring Person) after a person or group begins a tender or exchange offer which, if consummated, would result in that person or group becoming an Acquiring Person. The Board of Directors may reduce the threshold at which a person or a group becomes an Acquiring Person from 15% to not less than 10% of the outstanding common stock.
If a person or group becomes an Acquiring Person, all holders of Rights except the Acquiring Person may, for $90, purchase shares of our common stock with a market value of $180, based on the market price of the common stock prior to such acquisition. If the Company is later acquired in a merger or similar transaction after the Rights become exercisable, all holders of Rights except the Acquiring Person may, for
EOG RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
$90, purchase shares of the acquiring corporation with a market value of $180 based on the market price of the acquiring corporation's stock, prior to such merger.
The Company's Board of Directors may redeem the Rights for $.01 per Right at any time before any person or group becomes an Acquiring Person. If the Board of Directors redeems any Rights, it must redeem all of the Rights. Once the Rights are redeemed, the only right of the holders of Rights will be to receive the redemption price of $.01 per Right. The redemption price will be adjusted if the Company has a stock split or stock dividends of the Company's common stock. After a person or group becomes an Acquiring Person, but before an Acquiring Person owns 50% or more of the Company's outstanding common stock, the Board of Directors may exchange the Rights for common stock or equivalent security at an exchange ratio of one share of common stock or an equivalent security for each such Right, other than Rights held by the Acquiring Person.
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (IN THOUSANDS EXCEPT PER SHARE AMOUNTS UNLESS OTHERWISE INDICATED) (UNAUDITED EXCEPT FOR RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES)
OIL AND GAS PRODUCING ACTIVITIES
The following disclosures are made in accordance with SFAS No. 69 -- "Disclosures about Oil and Gas Producing Activities":
Oil and Gas Reserves. Users of this information should be aware that the process of estimating quantities of "proved," "proved developed" and "proved undeveloped" crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.
Proved reserves represent estimated quantities of natural gas, crude oil, condensate, and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made.
Proved developed reserves are proved reserves expected to be recovered, through wells and equipment in place and under operating methods being utilized at the time the estimates were made.
Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices and production volumes. Canadian reserves, as presented on a net basis, assume prices and royalty rates in existence at the time the estimates were made, and the Company's estimate of future production volumes. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause the Company's share of future production from Canadian reserves to be materially different from that presented.
As a result of the re-evaluation of the Company's portfolio of assets following the Share Exchange, on November 12, 1999 senior management proposed to the Board of Directors ("the Board") of the Company to defer the development of the Big Piney Madison deep Paleozoic formation methane reserves in Wyoming for the foreseeable future. The basis for this recommendation was the substantial capital cost required to develop the project relative to the Company's anticipated spending budget for the next several years as well as the project's anticipated rate of return compared to other investment opportunities currently available to the Company. The Board approved the recommendation. As a result, the 1.2 trillion cubic feet of methane reserves in the formation, which are located on acreage owned by the Company and held by production for the foreseeable future, and which were classified as proved undeveloped reserves at December 31, 1998, were removed as a revision during 1999. At December 31, 1998, these reserves represented approximately
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
$100 million or 5% of the Company's Standardized Measure of Discounted Future Net Cash Flows as adjusted for the sale of the India and China reserves as a result of the Share Exchange.
Estimates of proved and proved developed reserves at December 31, 1999, 1998 and 1997 were based on studies performed by the engineering staff of the Company for reserves in the United States, Canada, Trinidad, India and China (see Note 7 to the Consolidated Financial Statements regarding operations transferred under the Share Exchange). Opinions by DeGolyer and MacNaughton ("D&M"), independent petroleum consultants, for the years ended December 31, 1999, 1998 and 1997 covered producing areas containing 52%, 39% and 54%, respectively, of proved reserves, excluding deep Paleozoic methane reserves in 1998 and 1997, of the Company on a net-equivalent-cubic-feet-of-gas basis. D&M's opinions indicate that the estimates of proved reserves prepared by the Company's engineering staff for the properties reviewed by D&M, when compared in total on a net-equivalent-cubic-feet-of-gas basis, do not differ materially from the estimates prepared by D&M. The deep Paleozoic methane reserves were covered by the opinion of D&M for the year ended December 31 1995. Such estimates by D&M in the aggregate varied by not more than 5% from those prepared by the engineering staff of the Company. All reports by D&M were developed utilizing geological and engineering data provided by the Company.
No major discovery or other favorable or adverse event subsequent to December 31, 1999 is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.
The following table sets forth the Company's net proved and proved developed reserves at December 31 for each of the four years in the period ended December 31, 1999, and the changes in the net proved reserves for each of the three years in the period then ended as estimated by the engineering staff of the Company.
NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
- - ---------------
(1) Billion cubic feet or billion cubic feet equivalent, as applicable.
(2) See Note 7 "Transactions with Enron Corp. and Related Parties."
(3) Other includes proved reserves for China operations only, none of which are proved developed. See Note 7 "Transactions with Enron Corp. and Related Parties."
(4) Includes 1,180 Bcf of proved undeveloped methane reserves contained, along with high concentrations of carbon dioxide and other gases, in deep Paleozoic (Madison) formations in the Big Piney area of Wyoming.
(5) Includes removal of the 1,180 Bcf of proved undeveloped methane reserves mentioned in (4) as a result of the Company's decision to defer the development of the Big Piney Madison deep Paleozoic formation methane reserves in Wyoming for the foreseeable future.
(6) Thousand barrels.
(7) Includes crude oil, condensate and natural gas liquids.
Capitalized Costs Relating to Oil and Gas Producing Activities. The following table sets forth the capitalized costs relating to the Company's natural gas and crude oil producing activities at December 31, 1999 and 1998:
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities. The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in SFAS No. 19 -- "Financial Accounting and Reporting by Oil and Gas Producing Companies."
Acquisition costs include costs incurred to purchase, lease, or otherwise acquire property.
Exploration costs include exploration expenses, additions to exploration wells including those in progress, and depreciation of support equipment used in exploration activities.
Development costs include additions to production facilities and equipment, additions to development wells including those in progress and depreciation of support equipment and related facilities used in development activities.
The following tables set forth costs incurred related to the Company's oil and gas activities for the years ended December 31:
- - ---------------
(1) See Note 7 "Transactions with Enron Corp. and Related Parties."
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Results of Operations for Oil and Gas Producing Activities(1). The following tables set forth results of operations for oil and gas producing activities for the years ended December 31:
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(1) Excludes net revenues associated with other marketing activities, interest charges, general corporate expenses and certain gathering and handling fees for each of the three years in the period ended December 31, 1999. The gathering and handling fees and other marketing net revenues are directly associated with oil and gas operations with regard to segment reporting as defined in SFAS No. 131 -- "Disclosures about Segments of an Enterprise and Related Information," but are not part of Disclosures about Oil and Gas Producing Activities as defined in SFAS No. 69.
(2) See Note 7 "Transactions with Enron Corp. and Related Parties."
(3) Other includes China and other international operations. See Note 7 "Transactions with Enron Corp. and Related Parties."
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves. The following information has been developed utilizing procedures prescribed by SFAS No. 69 and based on crude oil and natural gas reserve and production volumes estimated by the engineering staff of the Company. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.
The future cash flows presented below are based on sales prices, cost rates, and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.
Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Company's crude oil and natural gas reserves for the years ended December 31:
- - ---------------
(1) See Note 7 "Transactions with Enron Corp. and Related Parties."
(2) Other includes the standardized measure for proved reserves for China operations only. See Note 7 "Transactions with Enron Corp. and Related Parties."
(3) Includes approximately $55,316 and $100,294 in 1997 and 1998, respectively, related to the reserves in the Big Piney deep Paleozoic formations, which were removed from proved reserves in 1999.
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Changes in Standardized Measure of Discounted Future Net Cash Flows. The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for each of the three years in the period ended December 31, 1999.
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(1) See Note 7 "Transactions with Enron Corp. and Related Parties."
(2) Other includes China operations only. See Note 7 "Transactions with Enron Corp. and Related Parties."
(3) Includes approximately $222,228, $55,316 and $100,294, in 1996, 1997 and 1998, respectively, related to the reserves in the Big Piney deep Paleozoic formations.
(4) Includes reduction of approximately $172,057, discounted before income taxes, related to the reserves in the Big Piney deep Paleozoic formations.
EOG RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
UNAUDITED QUARTERLY FINANCIAL INFORMATION
SCHEDULE II
EOG RESOURCES, INC.
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997 (IN THOUSANDS)
S-1
EXHIBITS
Exhibits not incorporated herein by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference to the Company's Form S-1 Registration Statement, Registration No. 33-30678, filed on August 24, 1989 ("Form S-1"), or as otherwise indicated.
E-1
E-2
E-3
E-4
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 8th day of March, 2000.
EOG RESOURCES, INC. (Registrant)
By /s/ WALTER C. WILSON ----------------------------------- (Walter C. Wilson) Senior Vice President and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of registrant and in the capacities with EOG Resources, Inc. indicated and on the 8th day of March, 2000.
*By /s/ PATRICIA L. EDWARDS -------------------------------- (Patricia L. Edwards) (Attorney-in-fact for persons indicated)
EXHIBIT INDEX