Item 1. -- "Business -- Product Markets and Major Customers". Prices for natural gas and, to a lesser extent, oil are subject to substantial seasonal fluctuations and prices for each are subject to substantial fluctuations as a result of numerous other factors.
Since December 31, 1998, we have not filed any estimates of total proved net crude oil or natural gas reserves with any federal authority or agency other than the SEC. See Note 20 in our consolidated financial statements appearing elsewhere in this report for certain additional information concerning our proved reserves.
PRODUCTIVE WELLS AND ACREAGE
As of December 31, 1999, we had working interests in 1,811 gross (1,796 net) active oil wells. The following table sets forth certain information with respect to our developed and undeveloped acreage as of December 31, 1999.
- ------------ (1) Developed acres are acres spaced or assigned to productive wells. (2) Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves. (3) Less than 10% of total net undeveloped acres are covered by leases that expire from 2000 through 2003. (4) Does not include 9,000 acres covered by a farmout from Chevron, in which we own a 50% interest. (5) Does not include 29,000 gross (28,000 net) acres under a seismic option.
DRILLING ACTIVITIES
Certain information with regard to our drilling activities during the years ended December 31, 1999, 1998 and 1997 is set forth below:
See Item 1. - "Business -- Acquisition and Exploitation" and -- "Productive Wells and Acreage" for additional information regarding exploitation activities, including waterflood patterns, workovers and recompletions.
PRODUCTION AND SALES
The following table presents certain information with respect to crude oil and natural gas production attributable to our properties, the revenue derived from the sale of such production, average sales prices received and average production costs during the three years ended December 31, 1999, 1998 and 1997.
PAA PROPERTIES
See description of PAA's properties under Item 1. -- "Business -- Midstream Activities".
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Texas Securities Litigation. On November 29, 1999, a class action lawsuit was filed in the United States District Court for the Southern District of Texas entitled Di Giacomo v. Plains All American Pipeline, et al. The suit alleged that Plains All American Pipeline, L.P. and certain of the general partner's officers and directors violated federal securities laws, primarily in connection with unauthorized trading by a former employee. An additional nineteen cases were filed in the Southern District of Texas, some of which name the general partner and us as additional defendants. Plaintiffs allege that the defendants are liable for securities fraud violations under Rule 10b-5 and Section 20(a) of the Securities Exchange Act of 1934 and for making false registration statements under Sections 11 and 15 of the Securities Act of 1933. The court has consolidated all subsequently filed cases under the first filed action described above. Two unopposed motions are currently pending to appoint lead plaintiffs. These motions ask the court to appoint two distinct lead plaintiffs to represent two different plaintiff classes: (1) purchasers of our common stock and options and (2) purchasers of PAA's common units. Once lead plaintiffs have been appointed, the plaintiffs will file their consolidated amended complaints. No answer or responsive pleading is due until thirty days after a consolidated amended complaint is filed.
Delaware Derivative Litigation. On December 3, 1999, two derivative lawsuits were filed in the Delaware Chancery Court, New Castle County, entitled Susser v. Plains All American Inc., et al and Senderowitz v. Plains All American Inc., et al. These suits, and three others which were filed in Delaware subsequently, named the general partner, its directors and certain of its officers as defendants, and allege that the defendants breached the fiduciary duties that they owed to Plains All American Pipeline, L.P. and its unitholders by failing to monitor properly the activities of its employees. The derivative complaints allege, among other things, that Plains All American Pipeline has been harmed due to the negligence or breach of loyalty of the officers and directors that are named in the lawsuits. These cases are currently in the process of being consolidated. No answer or responsive pleading is due until these cases have been consolidated and a consolidated complaint has been filed.
We intend to vigorously defend the claims made in the Texas securities litigation and the Delaware derivative litigation. However, there can be no assurance that we will be successful in our defense or that these lawsuits will not have a material adverse effect on our financial position or results of operation.
On July 9, 1987, Exxon Corporation ("Exxon") filed an interpleader action in the United States District Court for the Middle District of Florida, Exxon Corporation v. E. W. Adams, et al., Case Number 87-976-CIV-T-23-B. This action was filed by Exxon to interplead royalty funds as a result of a title controversy between certain mineral owners in a field in Florida. One group of mineral owners, John W. Hughes, et al. (the "Hughes Group"), filed a counterclaim against Exxon alleging fraud, conspiracy, conversion of funds, declaratory relief, federal and Florida RICO, breach of contract and accounting, as well as challenging the validity of certain oil and natural gas leases owned by Exxon, and seeking exemplary and treble damages. In March 1993, but effective November 1, 1992, Calumet Florida Inc. ("Calumet"), our wholly-owned subsidiary, acquired all of Exxon's leases in the field affected by this lawsuit. In order to address those counterclaims challenging the validity of certain oil and natural gas leases, which constitute approximately 10% of the land underlying this unitized field, Calumet filed a motion to join Exxon as plaintiff in the subject lawsuit, which was granted July 29, 1994. In August 1994, the Hughes Group amended its counterclaim to add Calumet as a counter-defendant. Exxon and Calumet filed a motion to dismiss the counterclaims. On March 22, 1996, the Court granted Exxon's and Calumet's motion to dismiss the counterclaims alleging fraud, conspiracy, and federal and Florida RICO violations and challenging the validity of certain of our oil and natural gas leases but denied such motion as to the counterclaim alleging conversion of funds. We have reached an agreement in principle to settle with the Hughes group. In consideration for full and final settlement, and dismissal with prejudice, we have agreed to pay to the Hughes group the total sum of $100,000. We and Exxon have filed motions for summary judgment with respect to the claims of the remaining parties. The court has not yet set a date for hearing of these motions. The trial date is currently scheduled in June 2000.
We, in the ordinary course of business, are a claimant and/or a defendant in various other legal proceedings in which our exposure, individually and in the aggregate, is not considered material.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the security holders, through solicitation of proxies or otherwise, during the fourth quarter of the fiscal year covered by this report.
EXECUTIVE OFFICERS OF THE COMPANY
Information regarding our executive officers is presented below. All executive officers hold office until their successors are elected and qualified.
Greg L. Armstrong, President and Chief Executive Officer Officer Since 1981
Mr. Armstrong, age 41, has been President, Chief Executive Officer and a director since 1992. He was President and Chief Operating Officer from October to December 1992, and Executive Vice President and Chief Financial Officer from June to October 1992. He was Senior Vice President and Chief Financial Officer from 1991 to June 1992, Vice President and Chief Financial Officer from 1984 to 1991, Corporate Secretary from 1981 to 1988, and Treasurer from 1984 to 1987.
William C. Egg, Jr., Executive Vice President Officer Since 1984
Mr. Egg, age 48, has been Executive Vice President and Chief Operating Officer-Upstream since May 1998. He was Senior Vice President from 1991 to 1998. He was Vice President-Corporate Development from 1984 to 1991 and Special Assistant-Corporate Planning from 1982 to 1984.
Cynthia A. Feeback, Vice President - Accounting Officer Since 1993 and Assistant Treasurer
Ms. Feeback, age 42, has been Vice President and Assistant Treasurer since May 1999. She was Assistant Treasurer, Controller and Principal Accounting Officer of the Company from May 1998 to May 1999. She was Controller and Principal Accounting Officer from 1993 to 1998. She was Controller from 1990 to 1993 and Accounting Manager from 1988 to 1990.
Jim G. Hester, Vice President - Business Development Officer Since 1999 and Acquisitions
Mr. Hester, age 40, has been Vice President -- Business Development and Acquisitions since May 1999. He was Manager of Business Development and Acquisitions from 1997 to May 1999, Manager of Corporate Development from 1995 to 1997 and Manager of Special Projects from 1993 to 1995. He was Assistant Controller from 1991 to 1993, Accounting Manager from 1990 to 1991 and Revenue Accounting Supervisor from 1988 to 1990.
Phillip D. Kramer, Executive Vice President, Chief Officer Since 1987 Financial Officer and Treasurer
Mr. Kramer, age 44, has been Executive Vice President, Chief Financial Officer and Treasurer since May 1998. He was Senior Vice President and Chief Financial Officer from May 1997 to May 1998. He was Vice President and Chief Financial Officer from 1992 to 1997, Vice President and Treasurer from 1988 to 1992, Treasurer from 1987 to 1988, and Controller from 1983 to 1987.
Michael R. Patterson, Vice President and General Counsel Officer Since 1985
Mr. Patterson, age 52, has been Vice President and General Counsel since 1985 and Corporate Secretary since 1988.
Harry N. Pefanis, Executive Vice President Officer Since 1988
Mr. Pefanis, age 42, has been Executive Vice President-Midstream since May 1998. He was Senior Vice President from February 1996 to May 1998. He had been Vice President-Products Marketing since 1988. From 1987 to 1988 he was Manager of Products Marketing. From 1983 to 1987 he was Special Assistant for Corporate Planning. Mr. Pefanis is also President and Chief Operating Officer of Plains All American Inc.
Mary O. Peters, Vice President - Administration and Officer Since 1991 Human Resources
Ms. Peters, age 51, has been Vice President-Administration and Human Resources since 1991. She was Manager of Office Administration from 1984 to 1991.
PART II
Item 5.
Item 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
Our common stock is listed and traded on the American Stock Exchange under the symbol "PLX". The number of stockholders of record of the common stock as of March 15, 2000 was 1,133.
The following table sets forth the range of high and low closing sales prices for the common stock as reported on the American Stock Exchange Composite Tape for the periods indicated below.
We have not paid cash dividends on shares of our common stock since our inception and do not anticipate paying any cash dividends on our common stock in the foreseeable future. In addition, we are restricted by provisions of the indentures governing the issue of $275.0 million 10.25% Senior Subordinated Notes Due 2006 (the "10.25% Notes") and prohibited by our $225.0 million revolving credit facility from paying dividends on our common stock.
On December 14, 1999, we sold in a private placement 50,000 shares of our Series F Preferred Stock for $50.0 million. Each share of the Series F Preferred Stock has a stated value of $1,000 per share and bears a dividend of 10% per annum. Dividends are payable semi-annually in either cash or additional shares of Series F Preferred Stock at our option and are cumulative from the date of issue. Dividends paid in additional shares of Series F Preferred Stock are limited to an aggregate of six dividend periods. Each share of Series F Preferred Stock is convertible into 81.63 shares of common stock (an initial effective conversion price of $12.25 per share) and in certain circumstances may be converted at our option into common stock if the average trading price for any sixty-day trading period is equal to or greater than $21.60 per share. After December 15, 2003, the Series F Preferred Stock is redeemable at our option at 110% of stated value through December 15, 2004, and at declining amounts thereafter. If not previously redeemed or converted, the Series F Preferred Stock is required to be redeemed in 2007.
On April 1, 1999, we paid a dividend on our Series E Preferred Stock for the period from October 1, 1998 through March 31, 1999. The dividend amount of approximately $4.1 million was paid by issuing 8,209 additional shares of the Series E Preferred Stock. On September 9, 1999, 3,408 shares of Series E Preferred Stock, including accrued dividends, were converted into 98,613 shares of common stock at a conversion price of $18.00 per share. On October 1, 1999, we paid a cash dividend of approximately $4.2 million on the Series E Preferred Stock for the period April 1, 1999 through September 30, 1999.
On March 22, 2000, our Board of Directors declared cash dividends on our Series D Preferred Stock, Series F Preferred Stock and Series G Preferred Stock, all of which are payable on April 3, 2000 to holders of record on March 23, 2000. The dividend amount of $350,000 on the Series D Preferred Stock is for the period January 1, 2000 through March 31, 2000. The dividend amount of $1,475,000 on the Series F Preferred Stock is for the period December 15, 1999 (the date of original issuance) through March 31, 2000. The dividend amount of $4,219,000 for the Series G Preferred Stock is for the period October 1, 1999 through March 31, 2000.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA (IN THOUSANDS, EXCEPT FOR PER SHARE DATA)
The following selected historical financial information was derived from, and is qualified by reference to our consolidated financial statements, including the notes thereto, appearing elsewhere in this report. The selected financial data should be read in conjunction with the consolidated financial statements, including the notes thereto, and "Item 7.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
We are an independent energy company that acquires, exploits, develops, explores and produces crude oil and natural gas. Through our majority ownership in PAA, we are also engaged in the midstream activities of marketing, transportation, terminalling and storage of crude oil. For financial statement purposes, the assets, liabilities and earnings of PAA are included in our consolidated financial statements, with the public unitholders' interest reflected as a minority interest. Our upstream crude oil and natural gas activities are focused in California in the Los Angeles Basin, the Arroyo Grande Field, and the Mt. Poso Field, offshore California in the Point Arguello Field, the Sunniland Trend of South Florida and the Illinois Basin in southern Illinois. Our midstream activities are concentrated in California, Texas, Oklahoma, Louisiana and the Gulf of Mexico.
1999 ACQUISITIONS
On May 12, 1999, PAA completed the acquisition of Scurlock Permian LLC and certain other pipeline assets from Marathon Ashland Petroleum LLC. Including working capital adjustments and closing and financing costs, the cash purchase price was approximately $141.7 million. The assets, liabilities and results of operations of the Scurlock acquisition are included in our consolidated financial statements effective May 1, 1999.
Scurlock, previously a wholly-owned subsidiary of Marathon Ashland Petroleum, is engaged in crude oil transportation, gathering and marketing, and owns approximately 2,300 miles of active pipeline, numerous storage terminals and a fleet of more than 250 trucks.
On July 1, 1999, we acquired Chevron's interests in Point Arguello. The interests acquired include Chevron's 26% working interest in the Point Arguello Unit and associated onshore processing facilities, Chevron's right to participate in surrounding leases and certain fee acreage onshore. The acquisition, which was funded from our working capital, has an effective date of July 1, 1999.
On July 15, 1999, PAA completed the acquisition of the West Texas gathering system from Chevron Pipe Line Company for approximately $36.0 million, including transaction costs. The assets acquired include approximately 450 miles of crude oil transmission mainlines, approximately 400 miles of associated gathering and lateral lines, and approximately 2.9 million barrels of tankage located along the system.
UNAUTHORIZED TRADING LOSSES
In November 1999, we discovered that a former employee of PAA had engaged in unauthorized trading activity, resulting in losses of approximately $162.0 million ($174.0 million, including estimated associated costs and legal expenses). Approximately $7.1 million of the unauthorized trading loss was recognized in 1998 and the remainder in 1999. As a result, we have restated our 1998 financial information. Normally, as PAA purchases crude oil, it establishes a margin by selling crude oil for physical delivery to third-party users or by entering into a future delivery obligation with respect to futures contracts. The employee in question violated PAA's policy of maintaining a position that is substantially balanced between crude oil purchases and sales or future delivery obligations. The unauthorized trading and associated losses resulted in a default of certain covenants under PAA's credit facilities and significant short-term cash and letter of credit requirements. See "Capital Resources, Liquidity and Financial Condition".
RESULTS OF OPERATIONS
For the year ended December 31, 1999, we reported a net loss of $25.3 million, or $2.05 per share on total revenue of $4.8 billion as compared to a net loss of $62.3 million, or $3.99 per share on total revenue of $1.3 billion in 1998. For the year ended December 31, 1997, we reported net income of $14.3 million or $0.85 per share ($0.77 per share diluted), on total revenue of $862.2 million.
The net losses for the years ended December 31, 1999 and 1998 include the following nonrecurring items:
. $166.4 million of unauthorized trading losses; . a $16.5 million gain on the segment of the All American Pipeline linefill that was sold in 1999; . a $9.8 million gain related to the sale of units by PAA; . restructuring expense of $1.4 million; and . an extraordinary loss of $0.5 million related to the early extinguishment of debt (net of minority interest and tax benefit).
. $7.1 million of unauthorized trading losses; . a $109.0 million after-tax ($173.9 million pre-tax) reduction in carrying cost of oil and natural gas due to low crude oil prices at December 31, 1998; and . a $37.5 million after-tax ($60.8 million pre-tax) gain associated with the initial public offering of PAA.
Excluding these nonrecurring items we would have reported net income of approximately $17.0 million and $8.4 million in 1999 and 1998, respectively. EBITDA increased 73% in 1999 to $139.1 million from the $80.3 million reported in 1998 and 103% from the $68.4 million reported in 1997. Cash flow from operations (net income before noncash items) was $70.4 million, $42.0 million and $46.2 million in 1999, 1998 and 1997, respectively. EBITDA and cash flow from operations also exclude the nonrecurring items discussed above. Net cash used in operating activities was $76.0 million for the year ended December 31, 1999, compared to net cash provided by operating activities of $37.6 million for 1998 and $30.3 million for 1997.
Upstream Results
The following table sets forth certain of our upstream operating information for the periods presented:
Total oil equivalent production increased approximately 6% to an average of 23,400 BOE per day over the 1998 level of 22,100 BOE per day and 16% above the 1997 level of 20,200 BOE per day. The volume increase in 1999 is primarily associated with our ongoing acquisition and exploitation activities, offset somewhat by decreased production from certain of our other properties. The offshore California Point Arguello Unit, which we acquired from Chevron in July 1999, accounted for approximately 2,200 BOE per day of the increase. Net daily production from our onshore California properties increased to approximately 15,600 BOE per day in 1999, up 1,800 BOE per day, or 13% over 1998 and 39% over 1997. Excluding production from the Mt. Poso Field, which we acquired in December 1998, California production was up 6% from 1998. The increase in 1998 as compared to 1997 is partially attributable to the acquisition of the Arroyo Grande Field in the fourth quarter of 1997. Net daily production for our Gulf Coast properties averaged approximately 2,600 BOE per day in 1999,
compared to 4,800 BOE per day in 1998 and 5,300 BOE per day in 1997. The Gulf Coast production decrease is due to mechanical downtime and the effects of natural decline. This is our most volatile area in terms of maintaining production levels. Net daily production in the Illinois Basin averaged 3,000 BOE per day during 1999, 3,500 BOE per day in 1998 and 3,600 BOE per day in 1997.
Oil and natural gas revenues were $116.2 million in 1999, an increase of 13% over 1998 due to higher prices and increased production volumes. Oil and natural gas revenues decreased to $102.8 million in 1998 as compared to $109.4 million in 1997 due to decreased product prices which offset increased production volumes. Our average product price, which represents a combination of fixed and floating price sales arrangements and incorporates location and quality discounts from the benchmark NYMEX prices, averaged $13.61 per BOE in 1999, 7% higher than the price received in 1998 and 8% lower than the price received in 1997. The NYMEX benchmark WTI crude oil price averaged $19.25 per barrel in 1999, $14.43 per barrel in 1998, and $20.63 per barrel in 1997. Financial swap and collar arrangements and futures transactions that we entered into to hedge production are included in our average product prices. These transactions had the effect of decreasing the overall average price we received by $1.30 per BOE in 1999, increasing the price by $2.98 per BOE in 1998 and decreasing the price by $1.26 per BOE in 1997. We maintained hedges on approximately 63% of our crude oil production throughout 1999 at an average NYMEX WTI crude oil price of approximately $18.00 per barrel. We routinely hedge a portion of our crude oil production. See "-- Capital Resources, Liquidity and Financial Condition -- Changing Crude Oil and Natural Gas Prices" and Item 7a.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
We are exposed to various market risks, including volatility in crude oil commodity prices and interest rates. To manage our exposure, we monitor our inventory levels, current economic conditions and our expectations of future commodity prices and interest rates when making decisions with respect to risk management. We do not enter into derivative transactions for speculative trading purposes. Substantially all of our derivative contracts are exchanged or traded with major financial institutions and the risk of credit loss is considered remote.
Commodity Price Risk. The fair value of outstanding derivative commodity instruments and the change in fair value that would be expected from a 10 percent adverse price change are shown in the table below (in millions):
DECEMBER 31, --------------------------------------- 1999 1998 ------------------ ------------------ 10% 10% ADVERSE ADVERSE FAIR PRICE FAIR PRICE VALUE CHANGE VALUE CHANGE ------- --------- -------- -------- Crude Oil: Futures contracts $ - $(2.8) $ 1.8 $(0.3) Swaps and options contracts (21.9) (6.1) 16.9 (4.3)
The fair values of the futures contracts are based on quoted market prices obtained from the NYMEX. The fair value of the swaps are estimated based on quoted prices from independent reporting services compared to the contract price of the swap and approximate the gain or loss that would have been realized if the contracts had been closed out at year end. All hedge positions offset physical positions exposed to the cash market; none of these offsetting physical positions are included in the above table. Price-risk sensitivities were calculated by assuming an across-the-board 10 percent adverse change in prices regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10 percent change in prompt month crude oil prices, the fair value of our derivative portfolio would typically change less than that shown in the table due to lower volatility in out-month prices.
Interest Rate Risk. Our debt instruments are sensitive to market fluctuations in interest rates. The table below presents principal payments and the related weighted average interest rates by expected maturity dates for debt outstanding at December 31, 1999. Our variable rate debt bears interest at LIBOR plus the applicable margin. The average interest rates presented below are based upon rates in effect at December 31, 1999. The carrying value of variable rate bank debt approximates fair value as interest rates are variable, based on prevailing market rates. The fair value of fixed rate debt was based on quoted market prices based on trades of subordinated debt. The fair value of the Redeemable Preferred Stock approximates its liquidation value at December 31, 1999.
At December 31, 1998, the carrying value of all variable rate bank debt and the Redeemable Preferred Stock of $184.7 million and $88.5 million, respectively, approximated the fair value and liquidation value, respectively, at that date. The carrying value and fair value of the fixed rate debt was $200.0 million and $202.0 million, respectively, at that date.
Interest rate swaps and collars are used to hedge underlying debt obligations. These instruments hedge specific debt issuances and qualify for hedge accounting. The interest rate differential is reflected as an adjustment to interest expense over the life of the instruments. At December 31, 1999, we had interest rate swap and collar arrangements for an aggregate notional principal amount of $240.0 million, which positions had an aggregate value of approximately $1.0 million as of such date. These instruments are based on LIBOR margins and generally provide for a floor of 5% and a ceiling of 6.5% for $90.0 million of debt and a floor of 6% and a ceiling of 8% for $125.0 million of debt. In August 1999, we terminated our swap arrangements on an aggregate notional principal amount of $175.0 million and we received consideration in the amount of approximately $10.8 million.
At December 31, 1998, we had interest rate swap arrangements for an aggregate notional principal amount of $200.0 million and would have been required to pay approximately $3.3 million to terminate the instruments at that date.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required here is included in the report as set forth in the "Index to Financial Statements" on page.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information regarding our directors will be included in the proxy statement for the 2000 annual meeting of stockholders (the "Proxy Statement") to be filed within 120 days after December 31, 1999, and is incorporated herein by reference. Information with respect to our executive officers is presented in Part I, Item 4 of this report.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Information regarding executive compensation will be included in the Proxy Statement and is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information, if any, regarding beneficial ownership of the common stock will be included in the Proxy Statement and is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information regarding certain relationships and related transactions will be included in the Proxy Statement and is incorporated herein by reference.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) (1) AND (2) FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
See "Index to Consolidated Financial Statements" set forth on Page.
(a) (3) EXHIBITS
2(a) Stock Purchase Agreement dated as of March 15, 1998, among Plains Resources Inc., Plains All American Inc. and Wingfoot Ventures Seven Inc. (incorporated by reference to Exhibit 2(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). 3(a) Second Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3(a) to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). 3(b) Bylaws of the Company, as amended to date (incorporated by reference to Exhibit 3(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 3(c) Certificate of Designation, Preference and Rights of Series D Cumulative Convertible Preferred Stock (incorporated by reference to Exhibit 3(c) to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1997). *3(d) Certificate of Designation, Preference and Rights of Series F Cumulative Convertible Preferred Stock. *3(e) Certificate of Designation, Preference and Rights of Series G Cumulative Convertible Preferred Stock. 4 Indenture dated as of March 15, 1996, among the Company, the Subsidiary Guarantors named therein and Texas Commerce Bank National Association, as Trustee for the Company's 10 1/4% Senior Subordinated Notes due 2006, Series A and Series B (incorporated by reference to Exhibit 4(b) to the Company's Form S-3 (Registration No. 333-1851)). 4(a) Indenture dated as of July 21, 1997, among the Company, the Subsidiary Guarantors named therein and Texas Commerce Bank National Association, as Trustee for the Company's 10 1/4% Senior Subordinated Notes due 2006, Series C and Series D (incorporated by reference to Exhibit 4 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1997). 4(b) Specimen Common Stock Certificate (incorporated by reference to Exhibit 4 to the Company's Form S-1 Registration Statement (Reg. No. 33-33986)). 4(c) Purchase Agreement for Stock Warrant dated May 16, 1994, between Plains Resources Inc. and Legacy Resources, Co., L.P. (incorporated by reference to Exhibit 4(d) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1994). 4(d) Warrant dated November 12, 1997, to Shell Land & Energy Company for the purchase of 150,000 shares of Common Stock (incorporated by reference to Exhibit 4(d) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1997). 4(e) Indenture dated as of September 15, 1999, among Plains Resources Inc., the Subsidiary Guarantors named therein and Chase Bank of Texas, National Association, as Trustee (incorporated by reference to Exhibit 4(a) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999). 4(f) Registration Rights Agreement dated as of September 22, 1999, among Plains Resources Inc., the Subsidiary Guarantors named therein, J.P. Morgan Securities Inc. and First Union Capital Markets Corp. (incorporated by reference to Exhibit 4(b) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999). *4(g) Stock Purchase Agreement dated as of December 15, 1999, among Plains Resources Inc. and the purchasers named therein. *4(h) Amendment to Stock Purchase Agreement dated as of December 17, 1999, among Plains Resources Inc. and the purchasers named therein. **10(a) Employment Agreement dated as of March 1, 1993, between the Company and Greg L. Armstrong (incorporated by reference to Exhibit 10(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). **10(b) The Company's 1991 Management Options (incorporated by reference to Exhibit 4.1 to the Company's Form S-8 Registration Statement (Reg. No. 33-43788)). **10(c) The Company's 1992 Stock Incentive Plan (incorporated by reference to Exhibit 4.3 to the Company's Form S-8 Registration Statement (Reg. No. 33-48610)). **10(d) The Company's Amended and Restated 401(k) Plan (incorporated by reference to Exhibit 10(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1996). **10(e) The Company's 1996 Stock Incentive Plan (incorporated by reference to Exhibit 4 to the Company's Form S-8 Registration Statement (Reg. No. 333-06191)).
**10(f) Stock Option Agreement dated August 27, 1996 between the Company and Greg L. Armstrong (incorporated by reference to Exhibit 10(l) to the Company's Annual Report on Form 10-K for the year ended December 31, 1996). **10(g) Stock Option Agreement dated August 27, 1996 between the Company and William C. Egg Jr. (incorporated by reference to Exhibit 10(m) to the Company's Annual Report on Form 10-K for the year ended December 31, 1996). **10(h) First Amendment to the Company's 1992 Stock Incentive Plan (incorporated by reference to Exhibit 10(n) to the Company's Annual Report on Form 10-K for the year ended December 31, 1996). **10(i) Second Amendment to the Company's 1992 Stock Incentive Plan (incorporated by reference to Exhibit 10(b) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1997). 10(j) Fourth Amended and Restated Credit Agreement dated May 22,1998, among the Company and ING (U.S.) Capital Corporation, et. al. (incorporated by reference to Exhibit 10(y) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1998) **10(k) First Amendment to Plains Resources Inc. 1996 Stock Incentive Plan dated May 21, 1998 (incorporated by reference to Exhibit 10(z) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1998) **10(l) Third Amendment to Plains Resources Inc. 1992 Stock Incentive Plan dated May 21, 1998 (incorporated by reference to Exhibit 10(aa) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1998) 10(m) First Amendment to Fourth Amended and Restated Credit Agreement dated as of November 17, 1998, among the Company and ING (U.S.) Capital Corporation, et. al. (incorporated by reference to Exhibit 10(m) to the Company's Annual Report on Form 10-K for the year ended December 31, 1998). 10(n) Second Amendment to Fourth Amended and Restated Credit Agreement dated as of March 15, 1999, among the Company and ING (U.S.) Capital Corporation, et. al. (incorporated by reference to Exhibit 10(n) to the Company's Annual Report on Form 10-K for the year ended December 31, 1998). **10(o) Employment Agreement dated as of November 23, 1998, between Harry N. Pefanis and the Company (incorporated by reference to Exhibit 10(o) to the Company's Annual Report on Form 10-K for the year ended December 31, 1998). 10(p) Purchase and Sale Agreement dated June 4, 1999, by and among the Company, Chevron U.S.A., Inc., and Chevron Pipe Line Company (incorporated by reference to Exhibit 10(h) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1999). 10(q) Third Amendment to Fourth Amended and Restated Credit Agreement dated June 21, 1999, among the Company and ING (U.S.) Capital Corporation, et. al. (incorporated by reference to Exhibit 10(p) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1999). 10(r) Second Amendment to Plains Resources 1996 Stock Incentive Plan dated May 20, 1999 (incorporated by reference to Exhibit 10(q) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1999). 10(s) Fourth Amendment to Fourth Amended and Restated Credit Agreement dated September 15, 1999, among the Company and First Union National Bank, et al. (incorporated by reference to Exhibit 10(q) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999). *10(t) Fifth Amendment to Fourth Amended and Restated Credit Agreement dated December 1, 1999, among the Company and First Union National Bank, et al. *21 Subsidiaries of the Company. *23(a) Consent of PricewaterhouseCoopers LLP. *27(b) Financial Data Schedule for the year ended December 31, 1999.
________________________ * Filed herewith ** A management contract or compensation plan.
(b) REPORTS ON FORM 8-K
A Current Report on Form 8-K was filed on November 29, 1999, regarding the discovery of unauthorized trading activity by a former employee of PAA, which was expected to result in losses to PAA of approximately $160.0 million.
A Current Report on Form 8-K was filed on December 1, 1999, regarding the execution of agreements with PAA's lenders to provide for a $300.0 million credit facility and the waiver of defaults under certain covenants in its credit facilities which resulted from its unauthorized trading losses, as well as the execution by us of commitment letters for the sale of up to $50.0 million of a new series of preferred stock, the proceeds of which would constitute a portion of the $114.0 million in debt financing which we agreed to provide to PAA.
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.
PLAINS RESOURCES INC.
Date: March 30, 2000 By: /s/ Phillip D. Kramer ------------------------------------------- Phillip D. Kramer, Executive Vice President and Chief Financial Officer (Principal Financial Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Date: March 30, 2000 By: /s/ Greg L. Armstrong --------------------------------------- Greg L. Armstrong, President, Chief Executive Officer and Director (Principal Executive Officer)
Date: March 30, 2000 By: /s/ Jerry L. Dees --------------------------------------- Jerry L. Dees, Director
Date: March 30, 2000 By: /s/ Tom H. Delimitros --------------------------------------- Tom H. Delimitros, Director
Date: March 30, 2000 By: /s/ Cynthia A. Feeback --------------------------------------- Cynthia A. Feeback, Vice President - Accounting And Assistant Treasurer (Principal Accounting Officer)
Date: March 30, 2000 By: /s/ William M. Hitchcock --------------------------------------- William M. Hitchcock, Director
Date: March 30, 2000 By: /s/ Phillip D. Kramer --------------------------------------- Phillip D. Kramer, Executive Vice President and Chief Financial Officer (Principal Financial Officer)
Date: March 30, 2000 By: /s/ Dan M. Krausse --------------------------------------- Dan M. Krausse, Chairman of the Board and Director
Date: March 30, 2000 By: /s/ John H. Lollar --------------------------------------- John H. Lollar, Director
Date: March 30, 2000 By: /s/ Robert V. Sinnott --------------------------------------- Robert V. Sinnott, Director
Date: March 30, 2000 By: /s/ J. Taft Symonds --------------------------------------- J. Taft Symonds, Director
Our annual report to stockholders for the year ended December 31, 1999, and the proxy statement relating to the annual meeting of stockholders will be furnished to stockholders subsequent to the filing of this annual report on Form 10-K. Such documents have not been mailed to stockholders as of the date of this report.
PLAINS RESOURCES INC. INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or notes thereto.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of Plains Resources Inc.
In our opinion, the consolidated financial statements listed in the accompanying index, after the restatement described in Note 3, present fairly, in all material respects, the financial position of Plains Resources Inc. and its subsidiaries at 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. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Houston, Texas March 29, 2000
PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (in thousands, except share data)
See notes to consolidated financial statements.
PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except share data)
See notes to consolidated financial statements.
PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)
See notes to consolidated financial statements.
PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN NON-REDEEMABLE PREFERRED STOCK, COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY (in thousands)
See notes to consolidated financial statements.
PLAINS RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- ORGANIZATION AND BASIS OF PRESENTATION
Organization
We are an independent energy company that acquires, exploits, develops, explores and produces crude oil and natural gas. Through our majority ownership in Plains All American Pipeline, L.P. ("PAA"), we are also engaged in the midstream activities of marketing, transportation, storage and terminalling of crude oil. Our upstream crude oil and natural gas activities are focused in California in the Los Angeles Basin, the Arroyo Grande Field, and the Mt. Poso Field, offshore California in the Point Arguello Field, the Sunniland Trend of South Florida and the Illinois Basin in southern Illinois. Our midstream activities are concentrated in California, Texas, Oklahoma, Louisiana and the Gulf of Mexico.
Basis of Consolidation and Presentation
The consolidated financial statements include the accounts of Plains Resources Inc., our wholly-owned subsidiaries and PAA in which we have an approximate 54% ownership interest, Plains All American Inc., one of our wholly owned subsidiaries, serves as PAA's sole general partner. For financial statement purposes, the assets, liabilities and earnings of PAA are included in our consolidated financial statements, with the public unitholders' interest reflected as a minority interest. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to the prior year statements to conform to the current year presentation.
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles 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 revenues and expenses during the reporting period. Significant estimates made by management include (1) crude oil and natural gas reserves (2) depreciation, depletion and amortization, including future abandonment costs, (3) income taxes and related valuation allowance and (4) accrued liabilities. Although management believes these estimates are reasonable, actual results could differ from these estimates.
Cash and Cash Equivalents. Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less.
Inventory. Crude oil inventory is carried at the lower of cost, as adjusted for deferred hedging gains and losses, or market value using an average cost method. Materials and supplies inventory is stated at the lower of cost or market with cost determined on a first-in, first-out method. Inventory at December 31, 1999 includes approximately $37.9 million of crude oil linefill which we began selling in November 1999 (see Note 6).
Inventory consists of the following:
DECEMBER 31, --------------------------- 1999 1998 ------- ------- (IN THOUSANDS)
Crude oil $73,535 $37,702 Materials and supplies 4,814 4,818 ------- ------- $78,349 $42,520 ======= =======
Oil and Natural Gas Properties. We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration, exploitation and development activities are capitalized. Such costs include internal general and administrative costs such as payroll and related benefits and costs directly attributable to employees engaged in acquisition, exploration, exploitation and development activities. General and administrative costs associated with production, operations, marketing and general corporate activities are expensed as incurred. These capitalized costs along with our estimate of future development and abandonment costs, net of salvage values and other considerations, are amortized to expense by the unit-of-production method using engineers' estimates of unrecovered proved oil and natural gas
reserves. The costs of unproved properties are excluded from amortization until the properties are evaluated. Interest is capitalized on oil and natural gas properties not subject to amortization and in the process of development. Proceeds from the sale of oil and natural gas properties are accounted for as reductions to capitalized costs unless such sales involve a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized. Unamortized costs of proved properties are subject to a ceiling which limits such costs to the present value of estimated future cash flows from proved oil and natural gas reserves of such properties reduced by future operating expenses, development expenditures and abandonment costs (net of salvage values), and estimated future income taxes thereon (the "Standardized Measure") (see Note 20).
Crude Oil Pipeline, Gathering and Terminal Assets. Crude oil pipeline, gathering and terminal assets are recorded at cost. Depreciation is computed using the straight-line method over estimated useful lives as follows:
. crude oil pipelines - 40 years; . crude oil pipeline facilities - 25 years; . crude oil terminal and storage facilities - 30 to 40 years; . trucking equipment, injection stations and other - 5 to 10 years; and
Acquisitions and improvements are capitalized; maintenance and repairs are expensed as incurred.
Other Property and Equipment. Other property and equipment is recorded at cost and consists primarily of office furniture and fixtures and computer hardware and software. Acquisitions, renewals, and betterments are capitalized; maintenance and repairs are expensed. Depreciation is provided using the straight-line method over estimated useful lives of three to seven years.
Other Assets. Other assets consist of the following (in thousands):
DECEMBER 31, ------------------- 1999 1998 ------- ------- (RESTATED)
Pipeline linefill $ 17,633 $ 54,511 Deferred tax asset (See Note 11) 67,366 46,356 Land 8,853 8,853 Debt issue costs 35,101 18,668 Other 10,965 8,245 -------- -------- 139,918 136,633 Accumulated amortization (10,151) (4,987) -------- -------- $129,767 $131,646 ======== ========
Pipeline Linefill. Pipeline linefill is recorded at cost and consists of crude oil linefill used to pack a pipeline such that when an incremental barrel enters a pipeline it forces a barrel out at another location. After the sale of the linefill discussed below, we own approximately 1.2 million barrels of crude oil that is used to maintain the vast majority of our minimum operating linefill requirements. Proceeds from the sale and repurchase of pipeline linefill are reflected as cash flows from operating activities in the accompanying consolidated statements of cash flows. Proceeds from the sale of linefill in connection with the segment of the All American Pipeline that we sold are included in investing activities in the accompanying consolidated statements of cash flows (see Note 6).
Costs incurred in connection with the issuance of long-term debt are capitalized and amortized using the straight-line method over the term of the related debt. Debt issue costs at December 31, 1999 include approximately $13.7 million paid in the fourth quarter of 1999 to amend PAA's credit facilities as a result of defaults caused by unauthorized trading losses (see Note 3).
Federal and State Income Taxes. Income taxes are accounted for in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes ("SFAS 109"). SFAS 109 requires recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax bases of assets and liabilities using tax rates in effect for the year in which the differences are expected to reverse.
Revenue Recognition. Gathering and marketing revenues are accrued at the time title to the product sold transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser, and purchases are accrued at the time title to the product purchased transfers to us, which typically occurs upon our receipt of the product. Terminalling and storage revenues are recognized at the time service is performed. Revenues for the transportation of crude oil are recognized based upon regulated and non-regulated tariff rates and the related transported volumes. We recognize oil and gas revenue from our interests in producing wells as oil and gas is produced and sold from those wells.
Hedging. We utilize various derivative instruments, for purposes other than trading, to hedge our exposure to price fluctuations on crude in storage and expected purchases, sales and transportation of crude oil. The derivative instruments consist primarily of futures and option contracts traded on the New York Mercantile Exchange and crude oil swap contracts entered into with financial institutions. We also utilize interest rate swaps and collars to manage the interest rate exposure on our long-term debt.
These derivative instruments qualify for hedge accounting as they reduce the price risk of the underlying hedged item and are designated as a hedge at inception. Additionally, the derivatives result in financial impacts which are inversely correlated to those of the items being hedged. This correlation, generally in excess of 80%, (a measure of hedge effectiveness) is measured both at the inception of the hedge and on an ongoing basis. If correlation ceases to exist, we would discontinue hedge accounting and apply mark to market accounting. Gains and losses on the termination of hedging instruments are deferred and recognized in income as the impact of the hedged item is recorded.
Unrealized changes in the market value of crude oil hedge contracts are not generally recognized in our statement of operations until the underlying hedged transaction occurs. The financial impacts of crude oil hedge contracts are included in our statements of operations as a component of revenues. Such financial impacts are offset by gains or losses realized in the physical market. Cash flows from crude oil hedging activities are included in operating activities in the accompanying statements of cash flows. Net deferred gains and losses on futures contracts, including closed futures contracts, entered into to hedge anticipated crude oil purchases and sales are included in current assets or current liabilities in the accompanying balance sheets. Deferred gains or losses from inventory hedges are included as part of the inventory costs and recognized when the related inventory is sold.
Amounts paid or received from interest rate swaps and collars are charged or credited to interest expense and matched with the cash flows and interest expense of the long-term debt being hedged, resulting in an adjustment to the effective interest rate. Deferred gains of $10.1 million received upon the termination of an interest rate swap are included in other long-term liabilities and deferred credits in the accompanying balance sheet at December 31, 1999.
Stock Options. We have elected to follow Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees ("APB 25") and related interpretations in accounting for our employee stock options. Under APB 25, no compensation expense is recognized when the exercise price of options equals the fair value (market price) of the underlying stock on the date of grant.
Sale of Units by a Subsidiary. When a subsidiary sells additional units to a third party, resulting in a change in our percentage ownership interest, we recognize a gain or loss in our consolidated statement of operations if the selling price per unit is more or less than our average carrying amount per unit. When we buy additional units from a subsidiary, resulting in a change in our percentage ownership interest, the difference between our cost and underlying equity in investee net assets is assigned first to identifiable tangible and intangible assets and to liabilities based on their fair values at the date of the change of interest; any unassigned difference is assigned to goodwill.
Recent Accounting Pronouncements. In June 1998, the FASB issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS 133"). SFAS 133 requires that all derivative instruments be recorded on the balance sheet at their fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if so, the type of hedge transaction. For fair value hedge transactions in which we are hedging changes in an asset's, liability's, or firm commitment's fair value, changes in the fair value of the derivative instrument will generally be offset in the income statement by changes in the hedged item's fair value. For cash flow hedge transactions, in which we are hedging the variability of cash flows related to a variable-rate asset, liability, or a forecasted transaction, changes in the fair value of the derivative instrument will be reported in other comprehensive income. The gains and losses on the derivative instrument that are reported in other comprehensive income will be reclassified as earnings in the periods in which earnings are affected by the variability of the cash flows of the hedged item. This statement was amended by Statement of Financial Accounting Standards No. 137, Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133 ("SFAS 137") issued in June 1999. SFAS 137 defers the effective date of SFAS 133 to
fiscal years beginning after June 15, 2000. We are required to adopt this statement beginning in 2001. We have not yet determined the effect that the adoption of SFAS 133 will have on our financial position or results of operations.
NOTE 3 -- UNAUTHORIZED TRADING LOSSES AND RESTATED FINANCIAL STATEMENTS
In November 1999, we discovered that a former employee of PAA had engaged in unauthorized trading activity, resulting in losses of approximately $162.0 million ($174.0 million, including estimated associated costs and legal expenses). A full investigation into the unauthorized trading activities by outside legal counsel and independent accountants and consultants determined that the vast majority of the losses occurred from March through November 1999, and the impact warranted a restatement of previously reported financial information for 1999 and 1998. Because the financial statements of PAA are consolidated with our financial statements, adverse effects on the financial statements of PAA directly affect our consolidated financial statements. As a result, we have restated our previously reported 1999 and 1998 results to reflect the losses incurred from these unauthorized trading activities. Approximately $7.1 million of the unauthorized trading losses were recognized in 1998 and the remainder in 1999.
Normally, as it purchases crude oil, PAA establishes a margin by selling crude oil for physical delivery to third-party users or by entering into a future delivery obligation with respect to futures contracts. The employee in question violated PAA's policy of maintaining a position that is substantially balanced between crude oil purchases and sales or future delivery obligations. The unauthorized trading and associated losses resulted in a default of certain covenants under PAA's credit facilities and significant short-term cash and letter of credit requirements.
Although one of our wholly-owned subsidiaries is the general partner of and owns 54% of PAA, the trading losses do not affect the operations or assets of our upstream business. The debt of PAA is nonrecourse to us. In addition, our indirect ownership in PAA does not collateralize any of our credit facilities. Our $225.0 million credit facility is collateralized by our oil and natural gas properties.
In December 1999, PAA executed amended credit facilities and obtained default waivers from all of its lenders. The amended credit facilities:
. waived defaults under covenants contained in the existing credit facilities; . increased availability under PAA's letter of credit and borrowing facility from $175.0 million in November 1999 to $295.0 million in December 1999, $315.0 million in January 2000, and thereafter decreasing to $239.0 million in February through April 2000, to $225.0 million in May and June 2000 and to $200.0 million in July 2000 through July 2001; . required the lenders' consent prior to the payment of distributions to unitholders; . prohibited contango inventory transactions subsequent to January 20, 2000; and . increased interest rates and fees under certain of the facilities.
PAA paid approximately $13.7 million to its lenders in connection with the amended credit facilities. This amount was capitalized as debt issue costs and will be amortized over the remaining term of the amended facilities. In connection with the amendments, we loaned approximately $114.0 million to PAA. This subordinated debt is due not later than November 30, 2005. We financed the $114.0 million that we loaned PAA with:
. the issuance of a new series of our 10% convertible preferred stock for proceeds of $50.0 million (see Note 8); . cash distributions of approximately $9.0 million made in November 1999 to PAA's general partner; and . $55.0 million of borrowings under our revolving credit facility.
In the period immediately following the disclosure of the unauthorized trading losses, a significant number of PAA's suppliers and trading partners reduced or eliminated the open credit previously extended to PAA. Consequently, the amount of letters of credit PAA needed to support the level of its crude oil purchases then in effect increased significantly. In addition, the cost to PAA of obtaining letters of credit increased under the amended credit facility. In many instances PAA arranged for letters of credit to secure its obligations to purchase crude oil from its customers, which increased its letter of credit costs and decreased its unit margins. In other instances, primarily involving lower margin wellhead and bulk purchases, certain of its purchase contracts were terminated.
The summarized restated results for the periods ended and financial position as of March 31, June 30, September 30, 1999 and December 31, 1998 are as follows (in thousands, except per shared data) (unaudited):
The summarized previously reported results for the periods ended and financial position as of March 31, June 30, September 30, 1999 and December 31, 1998 are as follows (in thousands, except per share data) (unaudited):
Below is the summarized restated and previously reported results for the three and nine months ending September 30, 1998.
NOTE 4 -- PLAINS ALL AMERICAN PIPELINE, L.P. - FORMATION AND OFFERINGS
Our midstream activities are conducted through PAA. PAA was formed in September of 1998 to acquire and operate the business and assets of our wholly- owned midstream subsidiaries.
On November 23, 1998, PAA completed an initial public offering of 13,085,000 common units at $20.00 per unit, representing limited partner interests and received proceeds of approximately $244.7 million. Concurrently with the closing
of the initial public offering, we were merged with certain of our midstream subsidiaries, and then sold the assets of these subsidiaries to PAA in exchange for $64.1 million and the assumption of $11.0 million of related indebtedness. At the same time, the general partner conveyed all of its interest in the All American Pipeline and the SJV Gathering System to PAA in exchange for:
. 6,974,239 common units, 10,029,619 subordinated units and an aggregate 2% general partner interest; . the right to receive incentive distributions as defined in the partnership agreement; and . PAA's assumption of $175.0 million of indebtedness incurred by the general partner in connection with the acquisition of the All American Pipeline and the SJV Gathering System.
In addition to the $64.1 million paid to us, PAA distributed approximately $177.6 million to the general partner and used approximately $3.0 million of the remaining proceeds to pay expenses incurred in connection with the offering. The general partner used $121.0 million of the cash distributed to it to retire the remaining indebtedness incurred in connection with the acquisition of the All American Pipeline and the SJV Gathering System and to pay other costs associated with the transactions. The general partner distributed the remaining $56.6 million to us, which we used to repay indebtedness and for other general corporate purposes.
During 1998, we recognized a pre-tax gain of approximately $70.0 million (net of approximately $9.2 million in formation related expenses) in connection with the formation of PAA. The gain is the result of an increase in the book value of our equity in PAA to reflect our proportionate share of the underlying net assets of PAA due to the sale of units in the initial public offering. The formation related expenses consist primarily of amounts due to certain key employees in connection with the successful formation of PAA, debt prepayment penalties and legal fees.
In May 1999, PAA sold to the general partner 1.3 million Class B common units of PAA for a total cash consideration of $25.0 million, or $19.25 per unit, the price equal to the market value of PAA's common units on May 12, 1999, in connection with the Scurlock acquisition (see Note 6).
In October 1999, PAA completed a public offering of an additional 2,990,000 common units representing limited partner interests, at $18.00 per unit. Net proceeds to PAA from the offering, including our general partner contribution of $0.5 million, were approximately $51.3 million after deducting underwriters' discounts and commissions and offering expenses of approximately $3.1 million. These proceeds were used to reduce outstanding debt. We recognized a pre-tax gain of $9.8 million in connection with the offering as a result of an increase in the book value of our equity in PAA, as discussed above.
NOTE 5 -- UPSTREAM ACQUISITIONS AND DISPOSITIONS
On July 1, 1999, Arguello Inc., our wholly owned subsidiary, acquired Chevron's interests in Point Arguello. The interests acquired include Chevron's 26% working interest in the Point Arguello Unit, its 26% interest in various partnerships owning the associated transportation, processing and marketing infrastructure, and Chevron's right to participate in surrounding leases and certain fee acreage onshore. We assumed its 26% share of (1) plugging and abandoning all existing well bores, (2) removing conductors, (3) flushing hydrocarbons from all lines and vessels and (4) removing/abandoning all structures, fixtures and conditions created subsequent to closing. Chevron retained the obligation for all other abandonment costs, including but not limited to (1) removing, dismantling and disposing of the existing offshore platforms, (2) removing and disposing of all existing pipelines and (3) removing, dismantling, disposing and remediation of all existing onshore facilities. Arguello Inc. is the operator of record for the Point Arguello Unit and has entered into an outsourcing agreement with a unit of Torch Energy Advisors, Inc. for the conduct of certain field operations and other professional services.
During 1998, we acquired the Mt. Poso field from Aera Energy LLC for approximately $7.7 million. The field is located approximately 27 miles north of Bakersfield, California, in Kern County. The field added approximately 8 million barrels of oil equivalent to our proved reserves at the acquisition date.
In March 1997, we completed the acquisition of Chevron's interest in the Montebello field for $25.0 million, effective February 1, 1997. The assets acquired consist of a 100% working interest and a 99.2% net revenue interest in 55 producing oil wells and related facilities and also include approximately 450 acres of surface fee land. At the acquisition date, the Montebello Field, which is located approximately 15 miles from our existing California operations, was producing approximately 800 barrels of crude oil and 800 Mcf of natural gas per day and added approximately 23 million barrels of oil equivalent to our proved reserves. The acquisition was funded with proceeds from our revolving credit facility.
In November 1997, we acquired a 100% working interest and a 97% net revenue interest in the Arroyo Grande Field in San Luis Obispo County, California, from subsidiaries of Shell Oil Company ("Shell"). The assets acquired include surface
and development rights to approximately 1,000 acres included in the 1,500 acre unit. At the acquisition date, the Arroyo Grande Field was producing approximately 1,600 barrels of 14 degrees API gravity crude oil per day from 70 wells and added approximately 20 million barrels of oil equivalent to our proved reserves.
The aggregate purchase price of $22.1 million for the Arroyo Grande field consisted of rights to a non-producing property interest conveyed to Shell, the issuance of 46,600 shares of Series D Preferred Stock with an aggregate stated value of $23.3 million and a 5-year warrant to purchase 150,000 shares of Common Stock at $25.00 per share. No proved reserves had been assigned to the rights to the property interest conveyed.
During 1997, we sold certain non-strategic crude oil and natural gas properties located primarily in Louisiana for net proceeds of approximately $2.7 million.
NOTE 6 -- MIDSTREAM ACQUISITIONS AND DISPOSITIONS
Scurlock Acquisition
On May 12, 1999, PAA completed the acquisition of Scurlock Permian LLC and certain other pipeline assets from Marathon Ashland Petroleum LLC. Including working capital adjustments and closing and financing costs, the cash purchase price was approximately $141.7 million.
Scurlock, previously a wholly owned subsidiary of Marathon Ashland Petroleum, is engaged in crude oil transportation, gathering and marketing, and owns approximately 2,300 miles of active pipelines, numerous storage terminals and a fleet of more than 250 trucks. Its largest asset is an 800-mile pipeline and gathering system located in the Spraberry Trend in West Texas that extends into Andrews, Glasscock, Martin, Midland, Regan and Upton Counties, Texas. The assets we acquired also included approximately one million barrels of crude oil pipeline linefill.
Financing for the Scurlock acquisition was provided through:
. borrowings of approximately $92.0 million under Plains Scurlock's limited recourse bank facility with BankBoston, N.A.; . the sale to the general partner of 1.3 million Class B common units of PAA for a total cash consideration of $25.0 million, or $19.125 per unit, the price equal to the market value of PAA's common units on May 12, 1999; and . a $25.0 million draw under PAA's existing revolving credit agreement.
The funds for the purchase of the Class B units by the general partner were provided by a capital contribution from us. We financed our capital contribution through our revolving credit facility.
The purchase price allocation was based on preliminary estimates of fair value and is subject to adjustment as additional information becomes available and is evaluated. The purchase accounting entries include a $1.0 million accrual for estimated environmental remediation costs. Under the agreement for the sale of Scurlock by Marathon Ashland Petroleum to Plains Scurlock, Marathon Ashland Petroleum has agreed to indemnify and hold harmless Scurlock and Plains Scurlock for claims, liabilities and losses resulting from any act or omission attributable to Scurlock's business or properties occurring prior to the date of the closing of such sale to the extent the aggregate amount of such losses exceed $1.0 million; provided, however, that claims for such losses must individually exceed $25,000 and must be asserted by Scurlock against Marathon Ashland Petroleum on or before May 15, 2003.
The assets, liabilities and results of operations of Scurlock are included in our consolidated financial statements effective May 1, 1999. The Scurlock acquisition has been accounted for using the purchase method of accounting and the purchase price was allocated in accordance with Accounting Principles Board Opinion No. 16, Business Combinations ("APB 16") as follows (in thousands):
Crude oil pipeline, gathering and terminal assets $125,120 Other property and equipment 1,546 Pipeline linefill 16,057 Other assets (debt issue costs) 3,100 Other long-term liabilities (environmental accrual) (1,000) Net working capital items (3,090) -------- Cash paid $141,733 ========
Pro Forma Results for the Scurlock Acquisition
The following unaudited pro forma data is presented to show pro forma revenues, net loss and basic and diluted net loss per share as if the Scurlock acquisition, which was effective May 1, 1999, had occurred on January 1, 1998 (in thousands, except per share data):
YEAR ENDED DECEMBER 31, ---------------------- 1999 1998 --------- ---------- (RESTATED)
Revenues $5,227,013 $2,529,558 ========== ========== Net loss $ (27,147) $ (69,682) ========== ========== Net loss per share available to common stockholders: Basic and diluted $ (2.15) $ (4.43) ========== ==========
West Texas Gathering System Acquisition
On July 15, 1999, Plains Scurlock Permian, L.P. completed the acquisition of a West Texas crude oil pipeline and gathering system from Chevron Pipe Line Company for approximately $36.0 million, including transaction costs. Our total acquisition cost was approximately $38.9 million including costs to address certain issues identified in the due diligence process. The principal assets acquired include approximately 450 miles of crude oil transmission mainlines, approximately 400 miles of associated gathering and lateral lines and approximately 2.9 million barrels of crude oil storage and terminalling capacity in Crane, Ector, Midland, Upton, Ward and Winkler Counties, Texas. Financing for the amounts paid at closing was provided by a draw under the term loan portion of the Plains Scurlock credit facility.
Venice Terminal Acquisition
On September 3, 1999, PAA completed the acquisition of a Louisiana crude oil terminal facility and associated pipeline system from Marathon Ashland Petroleum LLC for approximately $1.5 million. The principal assets acquired include approximately 300,000 barrels of crude oil storage and terminalling capacity and a six-mile crude oil transmission system near Venice, Louisiana.
All American Pipeline Acquisition
On July 30, 1998, Plains All American Inc., acquired all of the outstanding capital stock of the All American Pipeline Company, Celeron Gathering Corporation and Celeron Trading & Transportation Company (collectively the "Celeron Companies") from Wingfoot, a wholly-owned subsidiary of the Goodyear Tire and Rubber Company ("Goodyear") for approximately $400.0 million, including transaction costs. The principal assets of the entities acquired include the All American Pipeline and the SJV Gathering System, as well as other assets related to such operations. The acquisition was accounted for utilizing the purchase method of accounting with the assets, liabilities and results of operations included in our consolidated financial statements effective July 30, 1998.
The acquisition was accounted for utilizing the purchase method of accounting and the purchase price was allocated in accordance with APB 16 as follows (in thousands):
Financing for the acquisition was provided through a $325.0 million, limited recourse bank facility and an approximate $114.0 million capital contribution by us. Actual borrowings at closing were $300.0 million.
All American Pipeline Linefill Sale and Asset Disposition
We initiated the sale of approximately 5.2 million barrels of crude oil linefill from the All American Pipeline in November 1999. This sale was substantially completed in February 2000. The linefill was located in the segment of the All American Pipeline that extends from Emidio, California, to McCamey, Texas. Except for minor third party volumes, one of
our subsidiaries has been the sole shipper on this segment of the pipeline since its predecessor acquired the line from Goodyear in July 1998. Proceeds from the sale of the linefill were approximately $100.0 million, net of associated costs, and were used for working capital purposes. We estimate that we will recognize a total gain of approximately $44.0 million in connection with the sale of linefill. As of December 31, 1999, we had delivered approximately 1.8 million barrels of linefill and recognized a gain of $16.5 million. The amount of crude oil linefill for sale at December 31, 1999 was $37.9 million and is included in inventory on the consolidated balance sheet.
On March 24, 2000, we completed the sale of the above referenced segment of the All American Pipeline to a unit of El Paso Energy Corporation for total proceeds of $129.0 million. The proceeds from the sale were used to reduce PAA's outstanding debt. Our net proceeds are expected to be approximately $124.0 million, net of associated transaction costs and estimated costs to remove certain equipment. We estimate that we will recognize a gain of approximately $20.0 million in connection with the sale. During 1999, we reported gross margin of approximately $5.0 million from volumes transported on the segment of the line that was sold.
NOTE 7 -- LONG-TERM DEBT AND CREDIT FACILITIES
Short-term debt and current portion of long-term debt consists of the following (in thousands):
Long-term debt consists of the following (in thousands):
PLAINS RESOURCES LONG-TERM DEBT AND CREDIT FACILITIES
Revolving Credit Facility
We have a $225.0 million revolving credit facility with a group of banks. The revolving credit facility is guaranteed by all of our upstream subsidiaries and is collateralized by our upstream oil and natural gas properties and those of the guaranteeing subsidiaries and the stock of all upstream subsidiaries. The borrowing base under the revolving credit facility at December 31, 1999, is $225.0 million and is subject to redetermination from time to time by the lenders in good faith, in the exercise of the lenders' sole discretion, and in accordance with customary practices and standards in effect from time to time for crude oil and natural gas loans to borrowers similar to our company. Our borrowing base may be affected from time to
time by the performance of our crude oil and natural gas properties and changes in crude oil and natural gas prices. We incur a commintment fee of 3/8% per annum on the unused portion of the borrowing base. The revolving credit facility, as amended, matures on July 1, 2001, at which time the remaining outstanding balance converts to a term loan which is repayable in sixteen equal quarterly installments commencing October 1, 2001, with a final maturity of July 1, 2005. The revolving credit facility bears interest, at our option of either LIBOR plus 1 3/8% or Base Rate (as defined therein). At December 31, 1999, letters of credit of $0.6 million and borrowings of approximately $137.3 million were outstanding under the revolving credit facility.
The revolving credit facility contains covenants which, among other things, restrict the payment of cash dividends, limit the amount of consolidated debt, limit our ability to make certain loans and investments and provide that we must maintain a specified relationship between current assets and current liabilities.
10.25% Senior Subordinated Notes Due 2006
We have $275 million principal amount of 10.25% Senior Subordinated Notes Due 2006 outstanding which bear a coupon rate of 10.25% which at December 31, 1999 consists of (in thousands):
Series A $ 500 Series B 149,500 Series C 50 Series D 49,950 Series E 75,000 -------- $275,000 ========
The Series A & B 10.25% Notes were issued in 1996 at 99.38% of par to yield 10.35%. The Series C & D 10.25% Notes were issued in 1997 at approximately 107% of par to yield a minimum yield to worst of 8.79%, or 9.03% to maturity. Proceeds from the sale of the Series C & D 10.25% Notes, net of offering costs, were approximately $53.0 million and were used to reduce the balance on our revolving credit facility.
The Series E 10.25% Notes were issued in September 1999 pursuant to a Rule 144A private placement at approximately 101% of par to yield a minimum yield to worst of 9.97%. Proceeds from the sale of the Series E 10.25% Notes, net of offering costs, were approximately $74.6 million and were used to reduce the balance on our revolving credit facility.
In connection with the sale of the Series E Notes, we agreed to offer to exchange 10.25% Senior Subordinated Notes due 2006, Series F for all of the Series E Notes. The Series F Notes will be substantially identical (including principal amount, interest rate, maturity and redemption rights) to the Series E Notes except for certain transfer restrictions relating to the Series E Notes. We also agreed to file a registration statement with the SEC with respect to this exchange offer and to use our best efforts to cause such registration statement to be declared effective by January 20, 2000. If such registration statement is not declared effective by such date, with respect to the first 90- day period thereafter, the interest rate on the Series E Notes increases by 0.50% per annum and will increase by an additional 0.50% per annum with respect to each subsequent 90-day period until the registration statement has been declared effective, up to a maximum increase of 2% per annum. While the registration statement has been filed, we will not request the SEC to declare it effective until after the filing of our 1999 Form 10-K. As a result, the interest rate on the Series E Notes has increased to 10.75% for the 90-day period following January 20, 2000. At such time as the registration statement is declared effective by the SEC, the interest rate will revert to 10.25% per annum.
The 10.25% Notes are redeemable, at our option, on or after March 15, 2001 at 105.13% of the principal amount thereof, at decreasing prices thereafter prior to March 15, 2004, and thereafter at 100% of the principal amount thereof plus, in each case, accrued interest to the date of redemption.
The Indenture contains covenants that include, but are not limited to, covenants that: (1) limit the incurrence of additional indebtedness; (2) limit certain investments; (3) limit restricted payments; (4) limit the disposition of assets; (5) limit the payment of dividends and other payment restrictions affecting subsidiaries; (6) limit transactions with affiliates; (7) limit the creation of liens; and (8) restrict mergers, consolidations and transfers of assets. In the event of a Change of Control and a corresponding Rating Decline, as both are defined in the Indenture, we will be required to make an offer to repurchase the 10.25% Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase.
The Series A-E Notes are unsecured general obligations and are subordinated in right of payment to all our existing and future senior indebtedness and are guaranteed by all of our upstream subsidiaries on a full, unconditional, joint and several basis. The Series A-E Notes are not guaranteed by PAA or any of our other midstream subsidiaries.
PLAINS ALL AMERICAN PIPELINE L.P. CREDIT FACILITIES
The discussion below relates to credit facilities of PAA, which are nonrecourse to us, but are included in our consolidated financial statements. In addition, our indirect ownership in PAA does not collateralize any of our credit facilities.
PAA has a letter of credit and borrowing facility, the purpose of which is to provide standby letters of credit to support the purchase and exchange of crude oil for resale and borrowings primarily to finance crude oil inventory which has been hedged against future price risk or designated as working inventory. As a result of the unauthorized trading losses discovered in November 1999, the facility was in default of certain covenants, with those defaults being subsequently waived and the facility amended in December. As amended, the letter of credit facility has a sublimit for cash borrowings of $40.0 million at December 31, 1999, with decreasing amounts thereafter through April 30, 2000, at which time the sublimit is eliminated. The letter of credit and borrowing facility provides for an aggregate letter of credit availability of $295.0 million in December 1999, $315.0 million in January 2000, and thereafter decreasing to $239.0 million in February through April 2000, to $225.0 million in May and June 2000, and to $200.0 million in July 2000 through July 2001. Aggregate availability under the letter of credit facility for direct borrowings and letters of credit is limited to a borrowing base which is determined monthly based on certain of PAA's current assets and current liabilities, primarily accounts receivable and accounts payable related to the purchase and sale of crude oil. This facility is secured by a lien on substantially all of PAA's assets except the assets which secure the Plains Scurlock credit facility. At December 31, 1999, there were letters of credit of approximately $292.0 million and borrowings of $13.7 million outstanding under this facility.
On December 30, 1999, PAA entered into a $65.0 million senior secured term credit facility to fund short-term working capital requirements resulting from the unauthorized trading losses. The facility was secured by a portion of the 5.2 million barrels of linefill that was sold and receivables from certain sales contracts applicable to the linefill. The facility had a maturity date of March 24, 2000 and was repaid with the proceeds from the sale of the linefill securing the facility. At December 31, 1999, there were borrowings of $45.0 million outstanding.
Concurrently with the closing of PAA's initial public offering in November 1998, PAA entered into a $225.0 million bank credit agreement that includes a $175.0 million term loan facility and a $50.0 million revolving credit facility. As a result of the unauthorized trading losses discovered in November 1999, the facility was in default of certain covenants, with those defaults being subsequently waived and the facility amended in December. The bank credit agreement is secured by a lien on substantially all of PAA's assets except the assets which secure the Plains Scurlock credit facility. PAA may borrow up to $50.0 million under the revolving credit facility for acquisitions, capital improvements, working capital and general business purposes. At December 31, 1999, PAA had $175.0 million outstanding under the term loan facility, and $50.0 million outstanding under the revolving credit facility. The term loan facility matures in 2005, and no principal is scheduled for payment prior to maturity. The term loan facility may be prepaid at any time without penalty. The revolving credit facility expires in November 2000. The term loan and revolving credit facility bear interest at PAA's option at either the base rate, as defined, plus an applicable margin, or reserve adjusted LIBOR plus an applicable margin. PAA incurs a commitment fee on the unused portion of the revolving credit facility.
Plains Scurlock, an operating partnership which is a subsidiary of PAA, has a bank credit agreement which consists of a five-year $82.6 million term loan facility and a three-year $35.0 million revolving credit facility. The Plains Scurlock bank credit agreement is nonrecourse to PAA, Plains Marketing, L.P. and All American Pipeline, L.P. and is secured by substantially all of the assets of Plains Scurlock Permian, L.P. and its subsidiaries, including the Scurlock assets and the West Texas gathering system. Borrowings under the term loan and under the revolving credit facility bear interest at LIBOR plus the applicable margin. A commitment fee equal to 0.5% per year is charged on the unused portion of the revolving credit facility. The revolving credit facility, which may be used for borrowings or letters of credit to support crude oil purchases, matures in May 2002. The term loan provides for principal amortization of $0.7 million annually beginning May 2000, with a final maturity in May 2004. As of December 31, 1999, letters of credit of approximately $29.5 million were outstanding under the revolver and borrowings of $82.6 million and $2.5 million were outstanding under the term loan and revolver, respectively. The term loan was reduced to $82.6 million from $126.6 million with proceeds from PAA's October 1999 public offering.
All of PAA's credit facilities contain prohibitions on distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, PAA's facilities contain various covenants limiting its ability to:
. incur indebtedness; . grant liens; . sell assets in excess of certain limitations; . engage in transactions with affiliates; . make investments; . enter into hedging contracts; and . enter into a merger, consolidation or sale of assets.
Each of PAA's facilities treats a change of control as an event of default. In addition, the terms of PAA's letter of credit and borrowing facility and its bank credit agreement require lenders' consent prior to the payment of distributions to unitholders and require it to maintain:
. a current ratio of 1.0 to 1.0, as defined in PAA's credit agreement; . a debt coverage ratio which is not greater than 5.0 to 1.0; . an interest coverage ratio which is not less than 3.0 to 1.0; . a fixed charge coverage ratio which is not less than 1.25 to 1.0; and . a debt to capital ratio of not greater than 0.60 to 1.0.
The terms of the Plains Scurlock bank credit agreement require Plains Scurlock to maintain at the end of each quarter:
. a debt coverage ratio of 6.0 to 1.0 from October 1, 1999 through June 30, 2000; 5.0 to 1.0 from July 1, 2000 through June 30, 2001; and 4.0 to 1.0 thereafter; and . an interest coverage ratio of 2.0 to 1.0 from October 1, 1999 through June 30, 2000 and 2.5 to 1.0 thereafter.
In addition, the Plains Scurlock bank credit agreement contains limitations on the Plains Scurlock operating partnership's ability to make distributions to PAA if its indebtedness and current liabilities exceed certain levels as well as the amount of expansion capital it may expend.
Maturities
The aggregate amount of maturities of all long-term indebtedness for the next five years is: 2000 - $51.1 million, 2001 - $9.7 million, 2002 - $38.0 million, 2003 - $35.5 million and 2004 - $114.8 million.
NOTE 8 - REDEEMABLE PREFERRED STOCK
Series E and Series G Cumulative Convertible Preferred Stock
On July 29, 1998, we sold in a private placement 170,000 shares of our Series E Cumulative Convertible Preferred Stock (the "Series E Preferred Stock") for $85.0 million. Each share of the Series E Preferred Stock has a stated value of $500 per share and bears a dividend of 9.5% per annum. Dividends are payable semi-annually in either cash or additional shares of Series E Preferred Stock at our option and are cumulative from the date of issue. Each share of Series E Preferred Stock is convertible into 27.78 shares of common stock (an initial effective conversion price of $18.00 per share) and in certain circumstances may be converted at our option into common stock if the average trading price for any thirty-day trading period is equal to or greater than $21.60 per share. The Series E Preferred Stock is redeemable at our option at 105% of stated value through December 31, 2003 and at par thereafter. If not previously redeemed or converted, the Series E Preferred Stock is required to be redeemed in 2012. Proceeds from the Series E preferred Stock were used to fund a portion of our capital contribution to Plains All American Inc. to acquire the Celeron Companies (see Note 6).
On April 1, 1999, we paid a dividend on the Series E Preferred Stock for the period from October 1, 1998 through March 31, 1999. The dividend amount of approximately $4.1 million was paid by issuing 8,209 additional shares of the Series E Preferred Stock. On September 9, 1999, 3,408 shares of Series E Preferred Stock, including accrued dividends, were converted into 98,613 shares of common stock at a conversion price of $18.00 per share. On October 1, 1999, we paid a cash dividend of approximately $4.2 million on the Series E Preferred Stock for the period April 1, 1999 through September 30, 1999.
In connection with the sale of the Series F Preferred Stock described below, we agreed with the purchasers of the Series F Preferred Stock (who were also holders of the Series E Preferred Stock), to reduce the conversion price of the Series E Preferred Stock from $18.00 to $15.00. This reduction of the conversion price of the Series E Preferred Stock was effected through an exchange of each outstanding share of Series E Preferred Stock for a share of a new Series G Preferred Stock. Other than the reduction of the conversion price, the terms of the Series G Preferred Stock are substantially identical to those of the Series E Preferred Stock.
On March 22, our Board of Directors declared a cash dividend on our Series G Preferred Stock, which is payable on April 3, 2000 to holders of record on March 23, 2000. The dividend amount of $4,219,000 is for the period of October 1, 1999 through March 31, 2000.
Series F Cumulative Convertible Preferred Stock
On December 14, 1999, we sold in a private placement 50,000 shares of our Series F Cumulative Convertible Preferred Stock (the "Series F Preferred Stock") for $50.0 million. Each share of the Series F Preferred Stock has a stated value of $1,000 per share and bears a dividend of 10% per annum. Dividends are payable semi-annually in either cash or additional shares of Series F Preferred Stock at our option and are cumulative from the date of issue. Dividends paid in additional shares of Series F Preferred Stock are limited to an aggregate of six dividend periods. Each share of Series F Preferred Stock is convertible into 81.63 shares of common stock (an initial effective conversion price of $12.25 per share) and in certain circumstances may be converted at our option into common stock if the average trading price for any sixty-day trading period is equal to or greater than $21.60 per share. After December 15, 2003, the Series F Preferred Stock is redeemable at our option at 110% of stated value through December 15, 2004 and at declining amounts thereafter. If not previously redeemed or converted, the Series F Preferred Stock is required to be redeemed in 2007.
Proceeds from the Series F Preferred Stock were advanced to PAA in connection with the unauthorized trading losses through the issuance of $114.0 million of subordinated debt, due not later than November 30, 2005 (see Note 3). On March 22, our Board of Directors declared a cash dividend on our Series F Preferred Stock, which is payable on April 3, 2000 to holders of record on March 23, 2000. The dividend amount of $1,475,000 is for the period December 15, 1999 (the date of original issuance) through March 31, 2000.
NOTE 9 -- CAPITAL STOCK
Common and Preferred Stock
We have authorized capital stock consisting of 50 million shares of common stock, $0.10 par value, and 2 million shares of preferred stock, $1.00 par value. At December 31, 1999, there were 17.9 million shares of common stock issued and outstanding and 274,226 shares of preferred stock outstanding.
Stock Warrants and Options
At December 31, 1999, we had warrants outstanding which entitle the holders thereof to purchase an aggregate 251,350 shares of common stock. Per share exercise prices and expiration dates for the warrants are as follows: 101,350 shares at $7.50 expiring in 2000 and 150,000 shares at $25.00 expiring in 2002. We have various stock option plans for our employees and directors (see Note 15).
Series D Cumulative Convertible Preferred Stock
In November 1997, we issued 46,600 shares of Series D Cumulative Convertible Preferred Stock (the "Series D Preferred Stock"). The Series D Preferred Stock has an aggregate stated value of $23.3 million and is redeemable at our option at 140% of stated value. If not previously redeemed or converted, the Series D Preferred Stock will automatically convert into 932,000 shares of common stock in 2012. Each share of the Series D Preferred Stock has a stated value of $500 and is convertible into common stock at a ratio of $25.00 of stated value for each share of Common Stock to be issued. The Series D Preferred Stock was initially recorded at $20.5 million, a discount of $2.8 million from the stated value of $23.3 million. Commencing January 1, 2000, the Series D Preferred Stock will bear an annual dividend of $30.00 per share. Prior to this date, no dividends were accrued and the discount was amortized to retained earnings through December 31, 1999.
On March 22, our Board of Directors declared a cash dividend on our Series D Preferred stock, which is payable on April 3, 2000 to holders of record on March 23, 2000. The dividend amount of $350,000 is for the period January 1, 2000 through March 31, 2000.
NOTE 10 -- EARNINGS PER SHARE
The following is a reconciliation of the numerators and the denominators of the basic and diluted earnings per share computations for income (loss) from continuing operations before extraordinary item for the years ended December 31, 1999, 1998 and 1997 (in thousands, except per share amounts):
In 1999 and 1998, we recorded net losses and our options and warrants were not included in the computations of diluted earnings per share because their assumed conversion was antidilutive. In 1997 certain options and warrants to purchase shares of our common stock were not included in the computations of diluted earnings per share because the exercise prices were greater than the average market price of the common stock during the period of the calculations, resulting in antidilution. In addition, our preferred stock is convertible into common stock but was not included in the computation of diluted earnings per share in 1999, 1998 and 1997 because the effect was antidilutive. See Notes 9 and 15 for additional information concerning outstanding options and warrants.
NOTE 11 -- INCOME TAXES
Our deferred income tax assets and liabilities at December 31, 1999 and 1998, consist of the tax effect of income tax carryforwards and differences related to the timing of recognition of certain types of costs incurred in both our upstream and midstream activities as follows (in thousands):
At December 31, 1999, we have a net deferred federal tax asset of $69.2 million. Management believes that it is more likely than not that it will generate taxable income sufficient to realize such asset based on certain tax planning strategies available to us.
At December 31, 1999, we have carryforwards of approximately $229.3 million of regular tax NOLs, $7.0 million of statutory depletion, $1.4 million of alternative minimum tax credits and $0.3 million of enhanced oil recovery credits. At December 31, 1999, we had approximately $209.8 million of alternative minimum tax NOL carryforwards available as a deduction against future alternative minimum tax income. The NOL carryforwards expire from 2005 through 2019.
Set forth below is a reconciliation between the income tax provision (benefit) computed at the United States statutory rate on income (loss) before income taxes and the income tax provision per the accompanying Consolidated Statements of Operations (in thousands):
In accordance with certain provisions of the Tax Reform Act of 1986, a change of greater than 50% of our beneficial ownership within a three-year period (an "Ownership Change") will place an annual limitation on our ability to utilize our existing tax carryforwards. Under the Final Treasury Regulations issued by the Internal Revenue Service, we do not believe that an Ownership Change has occurred as of December 31, 1999.
NOTE 12 -- EXTRAORDINARY ITEM
For the year ended December 31, 1999, we recognized an extraordinary loss related to the early extinguishment of debt. The loss is related to the reduction of the Plains Scurlock term loan facility with proceeds from PAA's 1999 public offering and the restructuring of PAA's letter of credit and borrowing facility as a result of the unauthorized trading losses (see Note 3 and 7).
NOTE 13 -- RELATED PARTY TRANSACTIONS
Reimbursement of Expenses of the General Partner and Its Affiliates
As the general partner for PAA, we have sole responsibility for conducting its business and managing its operations and we own all of the incentive distribution rights. Some of our senior executives who currently operate our business also manage the business of PAA. We do not receive any management fee or other compensation in connection with the management of their business, but we are reimbursed for all direct and indirect expenses incurred on their behalf. For the years ended December 31, 1999 and 1998, we were reimbursed approximately $44.7 million and $0.5 million, respectively, for direct and indirect expenses on their behalf. The reimbursed costs consist primarily of employee salaries and benefits. PAA does not employ any persons to manage its business. These functions are provided by the employees of the general partner and us.
Crude Oil Marketing Agreement
PAA is the exclusive marketer/purchaser for all of our equity crude oil production. The marketing agreement provides that PAA will purchase for resale at market prices all of our equity crude oil production for which they charge a fee of $0.20 per barrel. For the year ended December 31, 1999 and the period from November 23, 1998 to December 31, 1998, we were paid approximately $131.5 million and $4.1 million, respectively, for the purchase of crude oil under the agreement. Prior to the marketing agreement, PAA's predecessor marketed our crude oil production and that of our subsidiaries and our royalty owners. We were paid approximately $83.4 million and $101.2 million for the purchase of these products for the period from January 1, 1998 to November 22, 1998 and the year ended December 31, 1997, respectively. In management's opinion, such purchases were made at prevailing market prices. PAA's predecessor did not recognize a profit on the sale of the crude oil purchased from us.
Financing
In December 1999, we loaned to PAA $114.0 million. This subordinated debt is due not later than November 30, 2005 (see Note 3).
To finance a portion of the purchase price of the Scurlock acquisition, we purchased 1.3 million Class B common units from PAA at $19.125 per unit, the market value of the common units on May 12, 1999 (see Note 6).
Long-Term Incentive Plans
We have adopted the Plains All American Inc. 1998 Long-Term Incentive Plan for employees and directors of the general partner and its affiliates who perform services for PAA. The Long-Term Incentive Plan consists of two components, a restricted unit plan and a unit option plan. The Long-Term Incentive Plan currently permits the grant of restricted units and unit options covering an aggregate of 975,000 common units. The plan is administered by the Compensation Committee of the general partner's board of directors.
Restricted Unit Plan. A restricted unit is a "phantom" unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit. As of March 15, 2000, an aggregate of approximately 500,000 restricted units have been authorized for grants to employees of the general partner, 170,000 of which have been granted with the remaining 330,000 to be granted in the near future. The Compensation Committee may, in the future, make additional grants under the plan to employees and directors containing such terms as the Compensation Committee shall determine. In general, restricted units granted to employees during the subordination period will vest only upon, and in the same proportions as, the conversion of
the subordinated units to common units. Grants made to non-employee directors of the general partner will be eligible to vest prior to termination of the subordination period.
Unit Option Plan. The Unit Option Plan currently permits the grant of options covering common units. No grants have been made under the Unit Option Plan to date. However, the Compensation Committee may, in the future, make grants under the plan to employees and directors containing such terms as the committee shall determine, provided that unit options have an exercise price equal to the fair market value of the units on the date of grant. Unit options granted during the subordination period will become exercisable automatically upon, and in the same proportions as, the conversion of the subordinated units to common units, unless a later vesting date is provided.
Transaction Grant Agreements In addition to the grants made under the Restricted Unit Plan described above, the general partner, at no cost to PAA, agreed to transfer approximately 400,000 of its affiliates' common units (including distribution equivalent rights attributable to such units) to certain key employees of the general partner. A grant covering 50,000 of such common units was terminated in 1999. Generally, approximately 69,444 of the remaining common units vest in each of the years ending December 31, 1999, 2000 and 2001 if the operating surplus generated in such year equals or exceeds the amount necessary to pay the minimum quarterly distribution on all outstanding common units and the related distribution on the general partner interest. If a tranche of common units does not vest in a particular year, such common units will vest at the time the common unit arrearages for such year have been paid. In addition, approximately 47,224 of the remaining common units vest in each of the years ending December 31, 1999, 2000 and 2001 if the operating surplus generated in such year exceeds the amount necessary to pay the minimum quarterly distribution on all outstanding common units and subordinated units and the related distribution on the general partner interest. In 1999, approximately 69,444 of such common units vested and 47,224 of such common units remain unvested as no distribution on the subordinated units was made for the fourth quarter of 1999. Any common units remaining unvested shall vest upon, and in the same proportion as, the conversion of subordinated units to common units. Distribution equivalent rights are paid in cash at the time of the vesting of the associated common units. Notwithstanding the foregoing, all common units become vested if Plains All American Inc. is removed as general partner prior to January 1, 2002.
We recognized noncash compensation expense of approximately $1.0 million for the year ended December 31, 1999 related to the transaction grants which vested in 1999
NOTE 14 -- RETIREMENT PLAN
Effective June 1, 1996, our board of directors adopted a nonqualified retirement plan (the "Plan") for certain of our officers. Benefits under the Plan are based on salary at the time of adoption, vest over a 15-year period and are payable over a 15-year period commencing at age 60. The Plan is unfunded.
Net pension expense for the years ended December 31, 1999, 1998 and 1997, is comprised of the following components (in thousands):
The following schedule reconciles the status of the Plan with amounts reported in our balance sheet at December 31, 1999 and 1998 (in thousands):
The weighted-average discount rate used in determining the projected benefit obligation was 7.8% and 6.5% for the years ended December 31, 1999 and 1998.
NOTE 15 -- STOCK COMPENSATION PLANS
Historically, we have used stock options as a long-term incentive for our employees, officers and directors under various stock option plans. The exercise price of options granted to employees is equal to or greater than the market price of the underlying stock on the date of grant. Accordingly, consistent with the provisions of APB 25, no compensation expense has been recognized in the accompanying financial statements.
We have options outstanding under our 1996, 1992 and 1991 plans, under which a maximum of 3.5 million shares of common stock were reserved for issuance. Generally, terms of the options provide for an exercise price of not less than the market price of our stock on the date of the grant, a pro rata vesting period of two to four years and an exercise period of five to ten years.
We have outstanding performance options to purchase a total of 500,000 shares of common stock which were granted to two executive officers. Terms of the options provide for an exercise price of $13.50, the market price on the date of grant, and an exercise period ending in August 2001. The performance options vest when the price of our common stock trades at or above $24.00 per share for any 20 trading days in any 30 consecutive trading day period or upon a change in control if certain conditions are met.
A summary of the status of our stock options as of December 31, 1999, 1998, and 1997, and changes during the years ending on those dates are presented below:
In October 1995, the Financial Accounting Standards Board issued SFAS 123 which established financial accounting and reporting standards for stock-based employee compensation. The pronouncement defines a fair value based method of accounting for an employee stock option or similar equity instrument. SFAS 123 also allows an entity to continue to measure compensation cost for those instruments using the intrinsic value-based method of accounting prescribed by APB 25. We have elected to follow APB 25 and related interpretations in accounting for our employee stock options because, as discussed below, the alternative fair value accounting provided for under SFAS 123 requires the use of option valuation models that were not developed for use in valuing employee stock options. Under APB 25, because the exercise price of our employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense has been recognized in the accompanying financial statements. We will recognize compensation expense under APB 25 in the future for the performance options described above, if certain conditions are met and the options vest.
Pro forma information regarding net income (loss) and earnings per share is required by SFAS 123 and has been determined as if we had accounted for our employee stock options under the fair value method as provided therein. The fair value for the options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for grants in 1999, 1998 and 1997: risk-free interest rates of 5.1% for 1999, 5.6% for 1998 and 6.1% for 1997; a volatility factor of the expected market price of our common stock of .50 for 1999, .38 for 1998 and .42 for 1997; no expected dividends; and weighted-average expected option lives of 2.7 years in 1999, 2.7 years in 1998 and 2.6 years in 1997.
The Black-Scholes option valuation model and other existing models were developed for use in estimating the fair value of traded options that have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of and are highly sensitive to subjective assumptions including the expected stock price volatility. Because our employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not provide a reliable single measure of the fair value of its employee stock options.
For purposes of pro forma disclosures, the estimated fair value of the options is amortized to expense over the options' vesting period. The pro forma information is not meant to be representative of the effects on reported net income (loss) for future years, because as provided by SFAS 123, the effects of awards granted before December 31, 1994, are not considered in the pro forma calculations. Set forth below is a summary of our net income (loss) before extraordinary item and earnings per share as reported and pro forma as if the fair value based method of accounting defined in SFAS 123 had been applied (in thousands, except per share data).
The following table summarizes information about stock options outstanding at December 31, 1999 (share amounts in thousands):
During 1999, 1998 and 1997, pursuant to board of directors' resolutions, we contributed approximately 65,000, 28,000 and 21,000 shares, respectively, of common stock at weighted average prices of $15.46, $16.21 and $15.22 per share, respectively, on behalf of participants in our 401(k) Savings Plan, representing our matching contribution for 50% of an employee's contribution.
NOTE 16 -- COMMITMENTS, CONTINGENCIES AND INDUSTRY CONCENTRATION
Commitments and Contingencies
We lease certain real property, equipment and operating facilities under various operating leases. We also incur costs associated with leased land, rights-of-way, permits and regulatory fees whose contracts generally extend beyond one year but can be canceled at any time should they not be required for operations. Future non-cancelable commitments related to these items at December 31, 1999, are summarized below (in thousands):
2000 $8,093 2001 5,759 2002 2,257 2003 1,595 2004 1,506 Later years 2,245
Total expenses related to these commitments for the years ended December 31, 1999, 1998 and 1997 were $9.3 million, $1.6 million and $1.1 million, respectively.
In connection with its crude oil marketing, PAA provides certain purchasers and transporters with irrevocable standby letters of credit to secure their obligation for the purchase of crude oil. Generally, these letters of credit are issued for up to seventy day periods and are terminated upon completion of each transaction. At December 31, 1999, PAA had outstanding letters of credit of approximately $321.5 million. Such letters of credit are secured by PAA's crude oil inventory and accounts receivable. (see Note 7).
Under the amended terms of an asset purchase agreement between us and Chevron, commencing with the year beginning January 1, 2000, and each year thereafter, we are required to plug and abandon 20% of the then remaining inactive wells, which currently aggregate approximately 233. To the extent we elect not to plug and abandon the number of required wells, we are required to escrow an amount equal to the greater of $25,000 per well or the actual average plugging cost per well in order to provide for the future plugging and abandonment of such wells. In addition, we are required to expend a minimum of $600,000 per year in each of the ten years beginning January 1, 1996, and $300,000 per year in each of the succeeding five years to remediate oil contaminated soil from existing well sites, provided there are remaining sites to be remediated. In the event we do not expend the required amounts during a calendar year, we are required to contribute an amount equal to 125% of the actual shortfall to an escrow account. We may withdraw amounts from the escrow account to the extent we expend excess amounts in a future year. As of December 31, 1999, we have not been required to make contributions to an escrow account.
Although we obtained environmental studies on our properties in California, the Sunniland Trend and the Illinois Basin and we believe that such properties have been operated in accordance with standard oil field practices, certain of the fields have been in operation for more than 90 years, and current or future local, state and federal environmental laws and regulations may require substantial expenditures to comply with such rules and regulations. In connection with the purchase of certain of our California properties, we received a limited indemnity from Chevron for certain conditions if they violate applicable local, state and federal environmental laws and regulations in effect on the date of such agreement. We believe that we do not have any material obligations for operations conducted prior to our acquisition of the properties from Chevron, other than our obligation to plug existing wells and those normally associated with customary oil field operations of similarly situated properties, there can be no assurance that current or future local, state or federal rules and regulations will not require us to spend material amounts to comply with such rules and regulations or that any portion of such amounts will be recoverable under the Chevron indemnity.
Consistent with normal industry practices, substantially all of our crude oil and natural gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. We have estimated that the costs to perform these tasks is approximately $13.4 million, net of salvage value and other considerations. Such estimated costs are amortized to expense through the unit-of-production method as a component of accumulated depreciation, depletion and amortization. Results from operations for 1999, 1998 and 1997 include $0.5 million, $0.8 million and $0.6 million, respectively, of expense associated with these estimated future costs. For valuation and realization purposes of the affected crude oil and natural gas properties, these estimated future costs are also deducted from estimated future gross revenues to arrive at the estimated future net revenues and the Standardized Measure disclosed in Note 20.
As is common within the industry, we have entered into various commitments and operating agreements related to the exploration and development of and production from proved crude oil and natural gas properties and the marketing, transportation, terminalling and storage of crude oil. It is management's belief that such commitments will be met without a material adverse effect on our financial position, results of operations or cash flows.
Industry Concentration
Financial instruments which potentially subject us to concentrations of credit risk consist principally of trade receivables. Our accounts receivable are primarily from purchasers of crude oil and natural gas products and shippers of crude oil. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit for receivables from customers which are not considered investment grade, unless the credit risk can otherwise be reduced. The loss of an individual customer would not have a material adverse effect.
There are a limited number of alternative methods of transportation for our production. Substantially all of our California crude oil and natural gas production and our Sunniland Trend crude oil production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services to us for a reasonable fee could result in our having to find transportation alternatives, increased transportation costs or involuntary curtailment of a significant portion of our crude oil and natural gas production which could have a negative impact on future results of operations or cash flows.
NOTE 17 -- LITIGATION
Texas Securities Litigation. On November 29, 1999, a class action lawsuit was filed in the United States District Court for the Southern District of Texas entitled Di Giacomo v. Plains All American Pipeline, et al. The suit alleged that Plains All American Pipeline, L.P. and certain of the general partner's officers and directors violated federal securities laws, primarily in connection with unauthorized trading by a former employee. An additional nineteen cases have been filed in the Southern District of Texas, some of which name the general partner and us as additional defendants. Plaintiffs allege that the defendants are liable for securities fraud violations under Rule 10b-5 and Section 20(a) of the Securities Exchange Act of 1934 and for making false registration statements under Sections 11 and 15 of the Securities Act of 1933. The court has consolidated all subsequently filed cases under the first filed action described above. Two unopposed motions are currently pending to appoint lead plaintiffs. These motions ask the court to appoint two distinct lead plaintiffs to represent two different plaintiff classes: (1) purchasers of our common stock and options and (2) purchasers of PAA's common units. Once lead plaintiffs have been appointed, the plaintiffs will file their consolidated amended complaints. No answer or responsive pleading is due until thirty days after a consolidated amended complaint is filed.
Delaware Derivative Litigation. On December 3, 1999, two derivative lawsuits were filed in the Delaware Chancery Court, New Castle County, entitled Susser v. Plains All American Inc., et al and Senderowitz v. Plains All American Inc., et al. These suits, and three others which were filed in Delaware subsequently, named the general partner, its directors and certain of its officers as defendants, and allege that the defendants breached the fiduciary duties that they owed to Plains All American Pipeline, L.P. and its unitholders by failing to monitor properly the activities of its employees. The derivative complaints allege, among other things, that Plains All American Pipeline has been harmed due to the negligence or breach of loyalty of the officers and directors that are named in the lawsuits. These cases are currently in the process of being consolidated. No answer or responsive pleading is due until these cases have been consolidated and a consolidated complaint has been filed.
We intend to vigorously defend the claims made in the Texas securities litigation and the Delaware derivative litigation. However, there can be no assurance that we will be successful in our defense or that these lawsuits will not have a material adverse effect on our financial position or results of operation.
On July 9, 1987, Exxon Corporation ("Exxon") filed an interpleader action in the United States District Court for the Middle District of Florida, Exxon Corporation v. E. W. Adams, et al., Case Number 87-976-CIV-T-23-B. This action was filed by Exxon to interplead royalty funds as a result of a title controversy between certain mineral owners in a field in Florida. One group of mineral owners, John W. Hughes, et al. (the "Hughes Group"), filed a counterclaim against Exxon alleging fraud, conspiracy, conversion of funds, declaratory relief, federal and Florida RICO, breach of contract and accounting, as well as challenging the validity of certain oil and natural gas leases owned by Exxon, and seeking exemplary and treble damages. In March 1993, but effective November 1, 1992, Calumet Florida, Inc. ("Calumet"), our wholly owned subsidiary, acquired all of Exxon's leases in the field affected by this lawsuit. In order to address those counterclaims challenging the validity of certain oil and natural gas leases, which constitute approximately 10% of the land underlying this unitized field, Calumet filed a motion to join Exxon as plaintiff in the subject lawsuit, which was granted July 29, 1994. In August 1994, the Hughes Group amended its counterclaim to add Calumet as a counter- defendant. Exxon and Calumet filed a motion to dismiss the counterclaims. On March 22, 1996, the Court granted Exxon's and Calumet's motion to dismiss the counterclaims alleging fraud, conspiracy, and federal and Florida RICO violations and challenging the validity of certain of our oil and natural gas leases but denied such motion as to the counterclaim alleging conversion of funds. We have reached an agreement in principle to settle with the Hughes Group. In consideration for full and final settlement, and dismissal with prejudice, we have agreed to pay to the Hughes Group the total sum of $100,000. We and Exxon have filed motions for summary judgment with respect to the claims of the remaining defendants. The court has not yet set a date for hearing of these motions. The trial date is currently scheduled in June 2000.
We are a defendant, in the ordinary course of business, in various other legal proceedings in which our exposure, individually and in the aggregate, is not considered material to the accompanying financial statements.
NOTE 18 -- FINANCIAL INSTRUMENTS
Derivatives
We utilize derivative financial instruments, as defined in Statement of Financial Accounting Standards No. 119, "Disclosure About Derivative Financial Instruments and Fair Value of Financial Instruments" to hedge our exposure to price volatility on crude oil and do not use such instruments for speculative trading purposes. These arrangements expose us to credit risk (as to counterparties) and to risk of adverse price movements in certain cases where our purchases are less than expected. In the event of non-performance of a counterparty, we might be forced to acquire alternative hedging arrangements or be required to honor the underlying commitment at then-current market prices. In order to minimize credit risk relating to the non-performance of a counterparty, we enter into such contracts with counterparties that are considered investment grade, periodically review the financial condition of such counterparties and continually monitor the effectiveness of derivative financial instruments in achieving our objectives. In view of our criteria for selecting counterparties, our process for monitoring the financial strength of these counterparties and our experience to date in successfully completing these transactions, we believe that the risk of incurring significant financial statement loss due to the non- performance of counterparties to these transactions is minimal.
We have entered into various arrangements to fix the NYMEX crude oil spot price for a significant portion of our crude oil production. On December 31, 1999, these arrangements provided for a NYMEX crude oil price for 18,500 barrels per day from January 1, 2000, through December 31, 2000, at an average floor price of approximately $16.00 per barrel. Approximately 10,000 barrels per day of the volumes hedged in 2000 will participate in price increases above the $16.00 per barrel floor price, subject to a ceiling limitation of $19.75 per barrel. Location and quality differentials attributable to our properties are not included in the foregoing prices. The agreements provide for monthly settlement based on the differential
between the agreement price and the actual NYMEX crude oil price. Gains or losses are recognized in the month of related production and are included in crude oil and natural gas sales.
At December 31, 1999, our hedging activities included crude oil futures contracts maturing in 2000 through 2002, covering approximately 7.4 million barrels of crude oil, including the portion of the linefill sold in January and February 2000. Since such contracts are designated as hedges and correlate to price movements of crude oil, any gains or losses resulting from market changes will be largely offset by losses or gains on our hedged inventory or anticipated purchases of crude oil.
In addition, we have entered into swap agreements with various financial institutions to hedge the interest rate on an aggregate of $240 million of bank debt. These swaps are scheduled to terminate in 2001 and thereafter.
Fair Value of Financial Instruments
The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standards No. 107, Disclosures About Fair Value of Financial Instruments ("SFAS 107"). The estimated fair value amounts have been determined using available market information and valuation methodologies described below. Considerable judgement is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.
The carrying values of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. Crude oil futures contracts permit settlement by delivery of the crude oil and, therefore, are not financial instruments, as defined. The carrying amounts and fair values of our other financial instruments are as follows (in thousands):
(1) These amounts represent the calculated difference between the NYMEX crude oil price and the hedge arrangements for future production from our properties as of December 31, 1999 and 1998. These hedges, and therefore the unrealized gains or losses, have been included in estimated future gross revenues to arrive at the estimated future net revenues and the Standardized Measure disclosed in Note 20.
The carrying value of bank debt approximates its fair value as interest rates are variable, based on prevailing market rates. The fair value of subordinated debt was based on quoted market prices based on trades of subordinated debt. Other long-term debt was valued by discounting the future payments using our incremental borrowing rate. The fair value of the redeemable preferred stock is estimated to be its liquidation value at December 31, 1999 and 1998. The fair value of the interest rate swap and collar agreements is based on current termination values or quoted market prices of comparable contracts at December 31, 1999 and 1998.
NOTE 19 -- SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Selected cash payments and noncash activities were as follows (in thousands):
NOTE 20 -- CRUDE OIL AND NATURAL GAS ACTIVITIES
Our oil and natural gas acquisition, exploration, exploitation and development activities are conducted in the United States. The following table summarizes the costs incurred during the last three years (in thousands).
Costs Incurred YEAR ENDED DECEMBER 31, ------------------------------- 1999 1998 1997 ------- -------- -------- Property acquisitions costs: Unproved properties $ 879 $ 6,266 $ 15,249 Proved properties 2,880 3,851 28,182 Exploration costs 4,101 1,657 1,730 Exploitation and development costs 65,119 89,161 82,217 ------- -------- -------- $72,979 $100,935 $127,378 ======= ======== ========
Capitalized Costs
Under full cost accounting rules as prescribed by the Securities and Exchange Commission ("SEC"), unamortized costs of proved crude oil and natural gas properties are subject to a ceiling, which limits such costs to the Standardized Measure (as described below). At December 31, 1998, the capitalized costs of our proved crude oil and natural gas properties exceeded the Standardized Measure and we recorded a noncash, after tax charge to expense of $109.0 million ($173.9 million pre-tax). The following table presents the aggregate capitalized costs subject to amortization relating to our crude oil and natural gas acquisition, exploration, exploitation and development activities, and the aggregate related DD&A (in thousands).
DECEMBER 31, -------------------- 1999 1998 --------- --------- Proved properties $ 671,928 $ 596,203 Accumulated DD&A (387,437) (369,260) --------- --------- $ 284,491 $ 226,943 ========= =========
The DD&A rate per equivalent unit of production excluding the writedown in 1998 was $2.13, $3.00 and $2.83 for the years ended December 31, 1999, 1998 and 1997, respectively.
Costs Not Subject to Amortization
The following table summarizes the categories of costs which comprise the amount of unproved properties not subject to amortization (in thousands).
December 31, --------------------------------- 1999 1998 1997 ---------- ---------- ----------
Acquisition costs $ 42,261 $ 47,657 $ 41,652 Exploration costs 4,842 2,467 2,573 Capitalized interest 4,928 4,421 7,799 ---------- ---------- ----------
$ 52,031 $ 54,545 $ 52,024 ========== ========== ==========
Unproved property costs not subject to amortization consist mainly of acquisition and lease costs and seismic data related to unproved areas. We will continue to evaluate these properties over the lease terms; however, the timing of the ultimate evaluation and disposition of a significant portion of the properties has not been determined. Costs associated with seismic data and all other costs will become subject to amortization as the prospects to which they relate are evaluated. Approximately 16%, 19% and 31% of the balance in unproved properties at December 31, 1999, related to additions made in 1999, 1998 and 1997, respectively.
During 1999, 1998 and 1997, we capitalized $4.4 million, $3.7 million and $3.3 million, respectively, of interest related to the costs of unproved properties in the process of development.
Supplemental Reserve Information (Unaudited)
The following information summarizes our net proved reserves of crude oil (including condensate and natural gas liquids) and natural gas and the present values thereof for the three years ended December 31, 1999. The following reserve information is based upon reports of the independent petroleum consulting firms of H.J. Gruy and Company, Netherland Sewell & Associates, Inc., and Ryder Scott Company in 1999, 1998 and 1997 and in addition, in 1997 by System Technology Associates, Inc. The estimates are in accordance with regulations prescribed by the SEC.
In management's opinion, the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation principles consistently applied, are believed to be reasonable. However, there are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree speculative, the quantities of crude oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil and natural gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the Standardized Measure shown below represents estimates only and should not be construed as the current market value of the estimated crude oil and natural gas reserves attributable to our properties. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year's estimates. Such revisions reflect additional information from subsequent exploitation and development activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices.
Decreases in the prices of crude oil and natural gas have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and our revenues, profitability and cash flow. Almost all of our reserve base (approximately 94% of year-end 1999 reserve volumes) is comprised of long-life crude oil properties that are sensitive to crude oil price volatility. The NYMEX market price of crude oil price at December 31, 1999, upon which proved reserve volumes, the estimated present value (discounted at 10%) of future net revenue from our proved crude oil and natural gas reserves (the "Present Value of Proved Reserves") and the Standardized Measure as of such date were based, was $25.60 per barrel. In comparison, the crude oil price at December 31, 1998, was $12.05 per barrel.
Estimated Quantities of Crude Oil and Natural Gas Reserves (Unaudited)
The following table sets forth certain data pertaining to our proved and proved developed reserves for the three years ended December 31, 1999 (in thousands).
Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
The Standardized Measure of discounted future net cash flows relating to proved crude oil and natural gas reserves is presented below (in thousands):
December 31, -------------------------------------- 1999 1998 1997 ----------- ---------- ----------- Future cash inflows $ 4,837,010 $1,102,863 $ 2,237,876 Future development costs (231,914) (117,924) (157,877) Future production expense (1,758,572) (546,091) (1,019,254) Future income tax expense (845,133) - (261,130) ----------- ---------- ----------- Future net cash flows 2,001,391 438,848 799,615 Discounted at 10% per year (1,073,591) (211,905) (387,792) ----------- ---------- ----------- Standardized measure of discounted future net cash flows $ 927,800 $ 226,943 $ 411,823 =========== ========== ===========
The Standardized Measure of discounted future net cash flows (discounted at 10%) from production of proved reserves was developed as follows:
1. An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions. 2. In accordance with SEC guidelines, the engineers' estimates of future net revenues from our proved properties and the present value thereof are made using crude oil and natural gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. The crude oil price at December 31, 1999 is based on the NYMEX crude oil price of $25.60 per barrel with variations therefrom based on location and grade of crude oil. We have entered into various fixed price and floating price collar arrangements to fix or limit the NYMEX crude oil price for a significant portion of our crude oil production. Arrangements in effect at December 31, 1999 are reflected in the reserve reports through the term of the arrangements (see Note 18). The overall average prices used in the reserve reports as of December 31, 1999, were $20.94 per barrel of crude oil, condensate and natural gas liquids and $2.77 per Mcf of natural gas. 3. The future gross revenue streams were reduced by estimated future operating costs (including production and ad valorem taxes) and future development and abandonment costs, all of which were based on current costs. 4. The reports reflect the pre-tax Present Value of Proved Reserves to be $1.2 billion, $226.9 million and $511.0 million at December 31, 1999, 1998 and 1997, respectively. SFAS No. 69 requires us to further reduce these estimates by an amount equal to the present value of estimated income taxes which might be payable by us in future years to arrive at the Standardized Measure. Future income taxes were calculated by applying the statutory federal
income tax rate to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards. A large portion of our reserve base (approximately 94% of year-end 1999 reserve volumes) is comprised of long-life oil properties that are sensitive to crude oil price volatility. By comparison, using a normalized NYMEX crude oil price of $18.50 per barrel, results in a pre-tax Present Value of Proved Reserves of $664.7 million and estimated net proved reserves of 212.7 million barrels of oil equivalent. Such information is based upon reserve reports prepared by independent petroleum engineers, in accordance with the rules and regulations of the SEC, using a normalized crude oil price.
The principal sources of changes in the Standardized Measure of the future net cash flows for the three years ended December 31, 1999, are as follows (in thousands):
NOTE 21--QUARTERLY FINANCIAL DATA (UNAUDITED)
The following table shows summary financial data for 1999 and 1998 (in thousands, except per share data):
- ----------------- (1) As indicated in Note 3, quarterly results for 1999 and the fourth quarter of 1998 have been restated from amounts previously reported due to the unauthorized trading losses. (2) Excludes net gains of $9.8 million and $60.8 million related to PAA's unit offerings in 1999 and 1998, respectively, recorded upon the formation of PAA.
NOTE 22--OPERATING SEGMENTS
Our operations consist of three operating segments: (1) Upstream Operations - engages in the acquisition, exploitation, development, exploration and production of crude oil and natural gas and (2) Midstream Operations - engages in pipeline transportation, purchases and resales of crude oil at various points along the distribution chain and the leasing of certain terminalling and storage assets and (3) Corporate - reflects certain amounts that are not directly attributable to Upstream or Midstream Operations. The accounting policies of the segments are the same as those described in the summary of significant accounting policies (see Note 1). We evaluate segment performance based on gross margin, gross profit and income before income taxes and extraordinary items.
(a) Intersegment revenues and transfers were conducted on an arm's-length basis. (b) Gross margin is calculated as operating revenues less operating expenses. (c) Gross profit is calculated as operating revenues less operating expenses and general and administrative expenses. (d) Differences between segment totals and company totals represent the net gain of $60.8 million recorded upon the formation of PAA, which was not allocated to segments.
The following table reconciles segment revenues to amounts reported in our financial statements:
Customers accounting for more than 10% of total sales for the periods indicated are as follows:
PERCENTAGE OF TOTAL SALES YEAR ENDED DECEMBER 31, ------------------------ CUSTOMER 1999 1998 1997 ------- ------ ------- Sempra Energy Trading Corporation 22% 27% 11% Koch Oil Company 18% 15% 27%
PERCENTAGE OF OIL AND GAS SALES -------------------------------- Chevron 43% - - Tosco Refining Company 21% 50% - Conoco Inc. 12% Scurlock Permian LLC - 17% - Unocal Energy Trading, Inc. - - 52% Marathon Oil Company 17% - 23% Exxon Company U.S.A. - - 10%
NOTE 23 -- CONSOLIDATING FINANCIAL STATEMENTS
The following financial information presents consolidating financial statements which include:
. the parent company only ("Parent"); . the guarantor subsidiaries on a combined basis ("Guarantor Subsidiaries"); . the nonguarantor subsidiaries on a combined basis ("Nonguarantor Subsidiaries"); . elimination entries necessary to consolidate the Parent, the Guarantor Subsidiaries and the Nonguarantor Subsidiaries; and . Plains Resources Inc. on a consolidated basis.
These statements are presented because the Series A-E Notes discussed in Note 7 are not guaranteed by PAA and our consolidated financial statements include the accounts of PAA.
PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEET (in thousands) DECEMBER 31, 1999
PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEET (restated) (in thousands) DECEMBER 31, 1998
PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATING STATEMENT OF OPERATIONS (in thousands) YEAR ENDED DECEMBER 31, 1999
PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATING STATEMENT OF OPERATIONS (restated) (in thousands) YEAR ENDED DECEMBER 31, 1998
PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATING STATEMENT OF OPERATIONS (in thousands) YEAR ENDED DECEMBER 31, 1997
PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (in thousands) YEAR ENDED DECEMBER 31, 1999
PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (restated) (in thousands) YEAR ENDED DECEMBER 31, 1998
PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (unaudited) (in thousands) YEAR ENDED DECEMBER 31, 1997