Item 3. Legal Proceedings
We are a defendant in various lawsuits arising in the ordinary course of our business. While the outcome of these lawsuits cannot be predicted with certainty and could have a material adverse effect on our financial position, we do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.
In September 2002, Stocker Resources Inc., or Stocker, our general partner before we converted from a limited partnership to a corporation, filed a declaratory judgment action against Commonwealth Energy Corporation, or Commonwealth, in the Superior Court of Orange County, California relating to the termination of an electric service contract. Stocker was seeking a declaratory judgment that it was entitled to terminate the contract and that Commonwealth had no basis for proceeding against Stocker’s related $1.5 million performance bond. Also in September 2002, Stocker was named a defendant in an action brought by Commonwealth in the Superior Court of Orange County, California for breach of the electric service contract. In January 2004 Plains Resources signed a settlement agreement with Commonwealth. Under the terms of our master separation agreement with Plains Resources, we indemnified them for damages they might incur as a result of this action. As such, we reimbursed Plains Resources’ settlement amount.
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.
Directors and Executive Officers of Plains Exploration & Production Company
Listed below are our directors and executive officers, their age as of February 29, 2003 and their business experience for the last five years.
Directors
James C. Flores, age 44, Chairman of the Board, Chief Executive Officer and a Director since September 2002 and President since March 2004. He also has been Plains Resources’ Chairman of the Board since December 2002. He was Chairman of the Board and Chief Executive Officer of Plains Resources from May 2001 to December 2002. He was Co-founder and Chairman from inception of Ocean Energy Inc., an oil and gas company, and, at various times, President and Chief Executive Officer from 1992 until March 1999. In March 1999 Ocean Energy, Inc. was merged into Seagull Energy Corporation where Mr. Flores served as Chairman of the Board of the new Ocean Energy, Inc. from March 1999 until January 2000, and as Vice Chairman from January 2000 until January 2001. From January 2001 to May 2001 Mr. Flores managed various private investments.
Alan R. Buckwalter, III, age 57, Director since March 2003. He retired in January 2003 as Chairman of JPMorgan Chase Bank, South Region, a position he had held since 1998. From 1990 to 1998 he was President of Texas Commerce Bank-Houston, the predecessor entity of JPMorgan Chase Bank. Prior to 1990 Mr. Buckwalter held various executive management positions within the organization. Mr. Buckwalter currently serves on the board of Service Corporation International (SCI), the Texas Medical Center, the Greater Houston Area Red Cross, the University of St. Thomas and St. Luke’s Hospital System. He sits on the Audit Committee and is Chairman of the Compensation Committee for SCI.
Jerry L. Dees, age 64, Director since September 2002. He also was a director of Plains Resources from 1997 to December 2002. He retired in 1996 as Senior Vice President, Exploration and
Land, for Vastar Resources, Inc. (previously ARCO Oil and Gas Company), a position he had held since 1991. From 1987 to 1991 he was Vice President of Exploration and Land for ARCO Alaska, Inc., and from 1985 to 1987 he held various positions as Exploration Manager of ARCO. From 1980 to 1985 Mr. Dees was Manager of Exploration Geophysics for Cox Oil and Gas Producers.
Tom H. Delimitros, age 63, Director since September 2002. He also was a director of Plains Resources from 1988 to December 2002. He has been a General Partner of AMT Venture Funds, a venture capital firm, since 1989. He is also a director of Tetra Technologies, Inc., a publicly-traded energy services company. He currently serves as Chairman for three privately-owned companies. Previously, he has served as President and CEO for Magna Corporation, (now Baker Petrolite, a unit of Baker Hughes). From 1983 to 1988, Mr. Delimitros was a General Partner of Sunwestern Investment Funds and Senior Vice President of Sunwestern Management, Inc.
John H. Lollar, age 65, Director since September 2002. He also was a director of Plains Resources from 1995 to December 2002. He has been the Managing Partner of Newgulf Exploration L.P. since December 1996. He is also a director of Lufkin Industries, Inc., a manufacturing firm, where he is a member of the Compensation Committee and Chair of the Audit Committee. Mr. Lollar was Chairman of the Board, President and Chief Executive Officer of Cabot Oil & Gas Corporation from 1992 to 1995, and President and Chief Operating Officer of Transco Exploration Company from 1982 to 1992.
Executive Officers
Stephen A. Thorington, age 48, Executive Vice President and Chief Financial Officer since September 2002. He also has been Plains Resources’ Executive Vice President and Chief Financial Officer since February 2003. He was Plains Resources’ Acting Executive Vice President and Chief Financial Officer from December 2002 to February 2003. Previously, he was Senior Vice President-Finance and Corporate Development of Ocean Energy, Inc. from July 2001 to September 2002 and Senior Vice President-Finance, Treasury and Corporate Development of Ocean Energy, Inc. from March 1999 to July 2001. He also served as Vice President, Finance and Treasurer of Seagull Energy Corporation from May 1996 to March 1999. Mr. Thorington served as a Managing Director of Chase Securities, Inc. from April 1994 to May 1996.
John F. Wombwell, age 42, has been Executive Vice President, General Counsel and Secretary of our company and of Plains Resources since September 2003. Prior to Plains Exploration and Production Company, Mr. Wombwell was General Counsel of ExpressJet Airlines, Inc. from April 2002 to September 2003 and Integrated Electrical Services, Inc. from January 1998 to April 2002. Prior to that time, Mr. Wombwell was a partner at the law firm of Andrews & Kurth L.L.P., where he practiced law in the area of corporate and securities matters, representing a variety of public companies.
Thomas M. Gladney, age 51, Executive Vice President-Exploration & Production since June 2003. He was our Senior Vice President of Operations from September 2002 to June 2003. He also was Plains Resources’ Senior Vice President of Operations from November 2001 to December 2002. He was President of Arguello, Inc., a subsidiary of Plains, from December 1999 to November 2001. From July 1999 to December 1999 he served as a Project Manager for Torch Energy Services, a contract operating services company. From January 1999 to June 1999 he served as a Project Manager for Venoco Inc., an oil and gas company. From September 1998 to January 1999 he was a self-employed engineering services consultant. From 1992 to September 1998 he was Offshore Operations Manager for Oryx Energy Company. Previously, he served as Gulf Coast Reserve Development Manager of Oryx Energy/Sun E&P from 1988 to 1992.
Cynthia A. Feeback, age 46, Senior Vice President-Accounting and Treasurer since September 2002. She also was Plains Resources’ Senior Vice President-Accounting and Treasurer from July
2001 to December 2002. She was its Vice President-Accounting and Assistant Treasurer from May 1999 to July 2001, and its Assistant Treasurer, Controller and Principal Accounting Officer from May 1998 to May 1999. Previously, Ms. Feeback served as its Controller and Principal Accounting Officer from 1993 to 1998, Controller from 1990 to 1993, and Accounting Manager from 1988 to 1990.
Item 5.
Item 5. Market for Registrant’s Common Stock and Related Stockholder Matters
Price Range of Common stock
Our common stock is listed on the New York Stock Exchange under the symbol “PXP” and began trading on December 18, 2002. The number of stockholders of record of our common stock on February 29, 2004 was 1,352. The following table sets forth the range of high and low sales prices for our common stock as reported on the New York Stock Exchange Composite Tape for the periods indicated below:
Dividend Policy
We do not anticipate declaring or paying any cash dividends in the future. We intend to retain our earnings to finance the expansion of our business and for general corporate purposes. Our board of directors will have the authority to declare and pay dividends on our common stock in its discretion, as long as we have funds legally available to do so. Our credit facility and the indenture relating to our 8.75% senior subordinated notes restrict our ability to pay cash dividends.
Item 6.
Item 6. Selected Financial Data
The following selected financial information was derived from, and is qualified by reference to, our consolidated financial statements, including the notes thereto, appearing elsewhere in this report. You should read this information in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and notes thereto. This information is not necessarily indicative of our future results.
(1)
Reflects the effect of the 3TEC merger effective June 1, 2003.
(2)
Cumulative effect of adopting Statement of Financial Accounting Standards No. 143-“Accounting for Asset Retirement Obligations,” or SFAS 143 in 2003 and Statement of Financial Accounting Standards No. 133-“Accounting for Derivatives,” or SFAS 133 in 2001.
Table continued on following page
(1)
Reflects the effect of the 3TEC merger effective June 1, 2003.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following information should be read in connection with the information contained in the consolidated financial statements and notes thereto included elsewhere in this report.
Proposed Acquisition of Nuevo Energy Inc.
On February 12, 2004 we announced that we had entered into a definitive agreement to acquire Nuevo Energy Company (“Nuevo”) in a stock for stock transaction valued at approximately $945 million, based on our February 11, 2004 closing stock price of $15.89 per share. Under the terms of the definitive agreement, Nuevo stockholders will receive 1.765 shares of our common stock for each share of Nuevo common stock. If completed, we will issue up to 38.8 million shares to Nuevo shareholders and assume $234 million of net debt (as of December 31, 2003) and $115 million of Trust Convertible Preferred Securities.
The transaction is expected to qualify as a tax free reorganization under Section 368(a) and is expected to be tax free to our stockholders and tax free for the stock consideration received by Nuevo stockholders. The Boards of directors of both companies have approved the merger agreement and each has recommended it to their respective stockholders for approval. The transaction is subject to stockholder approval from both companies and other customary conditions. Post closing, it is anticipated that PXP stockholders will own approximately 52% of the combined company and Nuevo stockholders will own approximately 48% of the combined company.
The transaction will be accounted for as a purchase of Nuevo by PXP under purchase accounting rules and PXP will continue to use the full cost method of accounting for its oil and gas properties.
Acquisition of 3TEC Energy Corporation
On June 4, 2003, we acquired 3TEC Energy Corporation, or 3TEC, the merger, for approximately $312.9 million in cash and common stock plus $90.0 million to retire 3TEC’s outstanding debt and $14.7 million to retire outstanding 3TEC preferred stock. Prior to the merger, 3TEC was engaged in the upstream activities of acquiring, exploiting, developing and producing oil and gas in East Texas and the Gulf Coast region, both onshore and in the shallow waters of the Gulf of Mexico. In the transaction, each 3TEC common share was converted in to 0.85 of a share of our common stock and $8.50 in cash. In connection with the merger, we paid cash consideration to the common shareholders of approximately $152.4 million and issued 15.3 million shares. In addition, we paid cash consideration of $8.3 million and issued 0.8 million common shares to redeem outstanding warrants. The cash portion of the purchase price was funded by the issuance of $75.0 million of senior subordinated notes and amounts borrowed under our revolving credit facility. We have accounted for the acquisition of 3TEC as a purchase effective June 1, 2003.
Corporate Reorganization and Spin-off
Prior to December 18, 2002 we were a wholly owned subsidiary of Plains Resources. On December 18, 2002 Plains Resources distributed 100% of the issued and outstanding shares of our common stock to the holders of record of Plains Resources’ common stock as of December 11, 2002. Each Plains Resources stockholder received one share of our common stock for each share of Plains Resources common stock held. Prior to the spin-off, Plains Resources made an aggregate of $52.2 million in cash contributions to us and transferred to us certain assets and we assumed certain liabilities of Plains Resources, primarily related to land, unproved oil and gas properties, office equipment and pension obligations. We used the cash contributions to reduce outstanding debt under our revolving credit facility.
In contemplation of the spin-off, under the terms of a Master Separation Agreement between us and Plains Resources, on July 3, 2002 Plains Resources contributed to us 100% of the capital stock of its wholly owned subsidiaries that own oil and gas properties in offshore California and Illinois. As a result, we indirectly own our offshore California and Illinois properties and directly own our onshore California properties. Plains Resources also contributed to us $256.0 million of intercompany payables that we or our subsidiaries owed to it. On July 3, 2002 we and Plains E&P Company, our wholly owned subsidiary that has no material assets and was formed for the sole purpose of being a corporate co-issuer of certain of our indebtedness, issued $200 million of 8.75% Senior Subordinated Notes due 2012, or the 8.75% Notes. On July 3, 2002 we also entered into a $300 million revolving credit facility. We distributed the net proceeds of $195.3 million from the 8.75% senior subordinated notes and $116.7 million of initial borrowings under our credit facility to Plains Resources.
Plains Resources received a favorable private letter ruling from the Internal Revenue Service stating that, for United States federal income tax purposes, the distribution of our common stock qualified as a tax-free distribution under Section 355 of the Internal Revenue Code.
General
We are an independent oil and gas company primarily engaged in the activities of acquiring, exploiting, developing and producing oil and gas in the United States. We own oil and gas properties in ten states with principal operations in:
•
the Los Angeles and San Joaquin Basins in California;
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the Santa Maria Basin offshore California;
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the Gulf Coast Basin onshore and offshore Louisiana; and
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the East Texas Basin in east Texas and north Louisiana.
We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration, exploitation and development activities are capitalized. Our revenues are derived from the sale of oil, gas and natural gas liquids. We recognize revenues when our production is sold and title is transferred. Our revenues are highly dependent upon the prices of, and demand for, oil and gas. Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile in the future. The prices we receive for our oil and gas and our levels of production are subject to wide fluctuations and depend on numerous factors beyond our control, including supply and demand, economic conditions, foreign imports, the actions of OPEC, political conditions in other oil-producing countries, and governmental regulation, legislation and policies. Under the SEC’s full cost accounting rules, we review the carrying value of our proved oil and gas properties each quarter. These rules generally require that we price our future oil and gas production at the oil and gas prices in effect at the end of each fiscal quarter, after giving effect to commodity derivative instruments that qualify for hedge accounting, to determine a ceiling value of our properties. The rules require a write-down if our capitalized costs exceed the allowed “ceiling.” We have had no write-downs due to these ceiling test limitations since 1998. Given the volatility of oil and gas prices, it is likely that our estimate of discounted future net revenues from proved oil and gas reserves will fluctuate in the near term. If oil and gas prices decline significantly in the future, write-downs of our oil and gas properties could occur. Write-downs required by these rules do not directly impact our cash flows from operating activities. Decreases in oil and gas prices have had, and will likely have in the future, an adverse effect on the carrying value of our proved reserves and our revenues, profitability and cash flow.
To manage our exposure to commodity price risk, we use various derivative instruments to hedge our exposure to oil and gas sales price fluctuations. Our hedging arrangements provide us protection on the hedged volumes if these prices decline below the prices at which these hedges are set. However, if prices increase, ceiling prices in our hedges may cause us to receive less revenues on the
hedged volumes than we would receive in the absence of hedges. Gains and losses on derivative transactions that qualify for hedge accounting are recognized as revenues when the associated production is sold. Changes in the fair value of derivative instruments that do not qualify for hedge accounting are recognized in other income (expense).
Our oil and gas production expenses include salaries and benefits of personnel involved in production activities, electric costs, maintenance costs, production, ad valorem and severance taxes, and other costs necessary to operate our producing properties. Depletion of capitalized costs of producing oil and gas properties is provided using the units of production method based upon proved reserves. For the purposes of computing depletion, proved reserves are redetermined as of the end of each year and on an interim basis when deemed necessary.
General and administrative expenses consist primarily of salaries and related benefits of administrative personnel, office rent, systems costs and other administrative costs.
Results of Operations
The following table reflects the components of our oil and gas production and sales prices and sets forth our operating revenues and costs and expenses on a BOE basis:
Comparison of Year Ended December 31, 2003 to Year Ended December 31, 2002
Net income. We reported net income of $59.4 million, or $1.78 per diluted share for the year ended December 31, 2003 compared to net income of $26.2 million, or $1.08 per diluted share for the year 2002. Net income in 2003 includes the effect of the 3TEC acquisition as of June 1, 2003 and an after-tax $12.3 million credit related to the adoption of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”.
Income before the cumulative effect of accounting change increased to $47.1 million in 2003 from $26.2 million in 2002. The improvement is primarily attributable to higher oil and gas sales as a result of increased sales volumes due to the 3TEC acquisition and increased oil and gas prices. These increases were partially offset by expenses related to stock appreciation rights and higher production expenses due to the 3TEC acquisition.
Oil and gas revenues. Oil and gas revenues increased 61%, or $114.9 million, to $303.2 million for 2003 from $188.3 million for 2002. The increase is due to increased production volumes attributable to the 3TEC acquisition and higher realized prices.
Oil revenues increased 11%, or $20.1 million, to $198.1 million for 2003 from $178.0 million for 2002. A 6%, or 0.5 million barrel, increase in 2003 production volumes to 9.3 million barrels increased revenues by $9.8 million and higher realized prices increased revenues by $10.3 million. The 3TEC acquisition accounted for 0.4 million barrels of increased production.
Our average realized price for oil increased 5%, or $1.11, to $21.38 per Bbl for 2003 from $20.27 per Bbl for 2002. The increase is attributable to an improvement in the NYMEX oil price, which averaged $30.99 per Bbl in 2003 versus $26.15 per Bbl in 2002. Hedging had the effect of decreasing our average price per Bbl by $5.54 in 2003 compared to $1.77 per Bbl in 2002.
Gas revenues increased $94.8 million, to $105.1 million for the 2003 from $10.3 million for 2002. A 441% increase in 2003 production volumes to 18.2 Bcf increased revenues by $45.4 million and higher realized prices increased revenues by $49.4 million. The 3TEC acquisition accounted for 15.1 Bcf of 2003 production.
Our average realized price for gas increased 89%, or $2.71, to $5.77 per Mcf for 2003 from $3.06 per Mcf for 2002. The increase is primarily attributable to an improvement in the NYMEX gas price, which averaged $5.24 per Mcf in 2003 versus $3.34 in 2002 and the effects of hedging. Hedging revenues increased our average price per Mcf by $0.76 in 2003. The average location and quality differential for our gas production improved from $0.28 per Mcf in 2002 to $0.23 in 2003.
Production expenses. Production expenses increased 24%, or $17.9 million, to $92.1 million for 2003 from $74.2 million for 2002, primarily from an increased ownership percentage in our offshore California properties and the acquisition of the 3TEC properties. The 3TEC properties accounted for $9.2 million of 2003 production expenses. On a per unit basis, production expenses decreased to $7.49 per BOE in 2003 versus $7.94 per BOE in 2002 due to the 3TEC properties that have lower per unit operating expenses than our other properties.
Production and ad valorem taxes. Production and ad valorem taxes increased 136%, or $5.8 million, to $10.1 million for 2003 from $4.3 million for 2002 due to the 3TEC acquisition. Production and ad valorem taxes for 2003 include $5.7 million attributable to the 3TEC properties.
Gathering and transportation expenses. Gathering and transportation expense, which totaled $2.6 million in 2003, represents costs incurred to deliver oil and gas produced from certain of the 3TEC properties to the sales point.
General and administrative expense. G&A, expense, excluding amounts attributable to stock appreciation rights and merger-related costs, increased 85%, or $9.1 million, to $19.9 million for 2003 from $10.8 million for 2002. The increase is primarily a result of our reorganization and spin-off, reflecting the incremental costs of operating as a separate, publicly held company and to increased costs resulting from the 3TEC acquisition.
G&A expense for 2003 includes a charge of $18.0 million related to outstanding SARs. Accounting for SARs requires that we record an expense or credit to the income statement depending on whether, during the period, our stock price either rose or fell, respectively. Accordingly, since our stock price at December 31, 2003 was $15.39 as compared to $9.75 on December 31, 2002 we recorded an expense. Included in the 2003 expense amount is $2.1 million of cash payments for SARs exercised during the year. G&A expense for 2002 includes a non-cash charge of $3.7 million related to outstanding SARs.
G&A expense in 2003 includes $5.3 million of merger related expenses consisting primarily of severance and other compensation costs and accounting system integration and conversion expenses. G&A expense for 2002 includes $0.8 million of expenses related to the spin-off.
G&A expense does not include amounts capitalized as part of our acquisition, exploration and development activities. We capitalized $11.0 million and $6.0 million of G&A expense in 2003 and 2002, respectively.
Depreciation, depletion, amortization and accretion, or DD&A. DD&A expense increased 73%, or $22.1 million, to $52.5 million for 2003 from $30.4 million for 2002. Approximately $17.9 million of the increase was attributable to our oil and gas DD&A due to a higher per unit rate and higher production. Our oil and gas unit of production rate increased to $3.86 per BOE in 2003 compared to $3.17 per BOE in 2002. The increase primarily reflects the effect of the 3TEC acquisition. Other DD&A expense increased approximately $1.6 million, primarily from amortization of debt issue costs related to our senior subordinated debt and our revolving credit facility. Accretion expense for 2003 was $2.6 million. Accretion expense represents the adjustment of our asset retirement obligation to its present value at the end of the period based.
Interest expense. Interest expense increased 23%, or $4.4 million, to $23.8 million for 2003 from $19.4 million for 2002 due to higher outstanding debt as a result of the merger. Interest expense does not include interest capitalized on oil and gas properties not subject to amortization. We capitalized approximately $3.2 million and $2.4 million of interest in 2003 and 2002, respectively.
Expenses of terminated public equity offering. In conjunction with the termination of our proposed initial public equity offering we expensed costs incurred of $2.4 million in 2002.
Income tax expense. Income tax expense increased to $33.5 million for 2003 from $16.7 million for 2002. Our overall effective tax rate increased to 42% in 2003 from 39% in 2002. Our currently payable effective tax rate was 2% for 2003 as compared to 14.8% for 2002. The decreased currently payable effective rate in 2003 primarily reflects the treatment for tax purposes of certain items that are capitalized for financial reporting purposes. Tax expense and effective tax rates for the periods prior to our spin-off on December 18, 2002 were calculated based on the tax sharing agreement with Plains Resources.
Income tax expense for 2003 includes a net $1.7 million charge (a $3.8 million charge to deferred tax expense that includes a $1.7 million adjustment to reflect an increase in our effective state income tax rate and a $2.1 million credit (benefit) to current tax expense) to reflect differences between our provision for income taxes for the year ended December 31, 2002 and the final 2002 tax returns filed by us and Plains Resources. Such adjustment primarily relates to differences in the treatment of certain items related to our oil and gas operations.
Cumulative effect. The cumulative effect of accounting change recognized for the first quarter of 2003 was for the adoption of Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations,” as amended.
Comparison of Year Ended December 31, 2002 to Year Ended December 31, 2001
Net income. We reported net income of $26.2 million, or $1.08 per diluted share for the year ended December 31, 2002 compared to net income of $53.2 million, or $2.20 per diluted share for 2001. A discussion of the reasons for the decrease follows.
Oil and gas revenues. Oil and gas revenues decreased 8%, or $15.4 million, to $188.3 million for 2002 from $203.7 million for 2001. The decrease is due to lower realized gas prices that were partially offset by higher production volumes.
Oil revenues increased 2%, or $3.1 million, to $178.0 million for 2002 from $174.9 million for 2001. A 7%, or 0.6 million barrel, increase in 2002 production volumes to 8.8 million barrels increased revenues by $12.0 million.
Our average realized price for oil decreased 5%, or $1.01, to $20.27 per Bbl for 2002 from $21.28 per Bbl for 2001. The decrease is attributable to hedging which had the effect of decreasing our average price per Bbl by $1.77 in 2002 compared to an increase of $0.03 per Bbl in 2001. The effects of hedging were partially offset by a slight increase in the average NYMEX oil price to $26.15 per Bbl in 2002 versus $26.01 per Bbl in 2001 and an improvement in our location and quality differential to $4.11 per Bbl in 2002 versus $4.76 per Bbl in 2001.
Gas revenues decreased $18.5 million, to $10.3 million for 2002 from $28.8 million for 2001 primarily due to a $5.52 per Mcf decrease in realized gas prices.
Our average realized price for gas decreased 64%, or $5.52, to $3.06 per Mcf for 2002 from $8.58 per Mcf for 2001. The decrease is primarily attributable to a premium we received for our California gas production in 2001. In 2001, the differential to NYMEX for our gas production was an increase of $4.24 per Mcf from the NYMEX gas price compared to a negative differential of $0.28 per Mcf in 2002.
Production expenses. Our production expenses increased 23%, or $14.0 million, to $74.2 million for the year ended December 31, 2002 from $60.2 million for the year ended December 31, 2001. On a per unit basis, production expenses increased 16%, or $1.08 per BOE, to $7.94 per BOE for the year ended December 31, 2002 from $6.86 per BOE for the year ended December 31, 2001. Production expenses for 2001 were reduced by approximately $0.25 per BOE as a result of nonrecurring credits (primarily the sale of certain California emissions credits). Excluding these credits, production expenses increased 12% per BOE in 2002, primarily due to increased workover and maintenance expense, insurance expense and electricity costs in California as well as our increased ownership percentage in the offshore California properties, which have a higher per unit production cost than our other properties.
Production and ad valorem taxes. Production and ad valorem taxes increased 19% to $4.3 million in 2002 versus $3.6 million in 2001 due to higher property valuations as a result of increased prices.
General and administrative expense. Our general and administrative, or G&A, expense, excluding amounts attributable to stock appreciation rights and costs related to our spin-off from Plains Resources, increased 6%, or $0.6 million, to $10.8 million in 2002 from $10.2 million in 2001. This
increase was primarily due to higher personnel cost. G&A expense for 2002 includes approximately $0.8 million of legal and other costs related to our spin-off and approximately $3.7 million of expense attributable to the in-the-money value of stock appreciation rights issued on the spin-off date. G&A expense does not include amounts capitalized as part of our acquisition, exploration and development activities. We capitalized $6.3 million and $6.2 million of G&A expense in 2002 and 2001, respectively.
Depreciation, depletion amortization and accretion. DD&A increased 26%, or $6.3 million, to $30.4 million for the year ended December 31, 2002 from $24.1 million for the year ended December 31, 2001. Approximately $4.1 million of the increase was attributable to a higher unit rate ($3.17 per BOE in 2002 versus $2.70 in 2001) and $1.8 million was attributable to increased production in 2002. DD&A is affected by many factors, including production levels, costs incurred in the acquisition, exploitation and development of proved reserves and estimates of proved reserve quantities and future development costs. The increase in our DD&A rate in 2002 was primarily due to our 2001 capital program resulting in higher costs being subject to DD&A and, to a lesser extent, to higher estimated future development costs.
Expenses of terminated public equity offering. In conjunction with the termination of our proposed initial public equity offering we expensed costs incurred of $2.4 million in 2002.
Interest expense. Our interest expense increased 11%, or $2.0 million, to $19.4 million for the year ended December 31, 2002 from $17.4 million for the year ended December 31, 2001, reflecting higher debt balances during 2002 and a decrease in the amount of capitalized interest, partially offset by lower interest rates. We capitalized approximately $2.4 million and $3.1 million of interest in 2002 and 2001, respectively.
Income tax expense. Our income tax expense decreased $17.7 million to $16.7 million for the year ended December 31, 2002 from $34.4 million for the year ended December 31, 2001. The decrease was primarily due to decreases in pre-tax income. Our overall effective tax rate increased slightly to 38.9% in 2002 from 38.6% for the year ended December 31, 2001. Our currently payable effective tax rate was 14.8% for the year ended December 31, 2002 as compared to 6.8% for the year ended December 31, 2001. The increased currently payable effective rate in 2002 primarily reflects lower expenditures that are expensed for tax purposes and capitalized for financial reporting purposes and the $3.7 million in expense related to stock appreciation rights that is not deductible until paid. Tax expense and effective tax rates for the periods prior to our spin-off on December 18, 2002 were calculated based on the tax sharing agreement with Plains Resources.
Liquidity and Capital Resources
Our primary sources of liquidity are cash generated from our operations and our revolving credit facility. At December 31, 2003 we had approximately $186.0 million of availability under our revolving credit facility. We believe that we have sufficient liquidity through our cash from operations and borrowing capacity under our revolving credit facility to meet our short-term and long-term normal recurring operating needs, debt service obligations, contingencies and anticipated capital expenditures.
Our cash flows depend on many factors, including the price of oil and gas and the success of our acquisition and drilling activities. We actively manage our exposure to commodity price fluctuations by hedging significant portions of our production and thereby mitigate our exposure to price declines. This allows us the flexibility to continue to execute our capital plan even if prices decline during the period our hedges are in place. In addition, the majority of our capital expenditures are discretionary and could be curtailed if our cash flows declined from expected levels.
Financing Activities
In connection with our acquisition of 3TEC, we replaced our then existing credit facility with a new $500.0 million credit facility with an initial borrowing base of $425.0 million.
On May 30, 2003 we and Plains E&P Company, our wholly owned subsidiary that has no material assets and was formed for the sole purpose of being a corporate co-issuer of certain of our indebtedness, issued, at an issue price of 106.75%, $75.0 million of 8.75% senior subordinated notes due 2012. We used the net proceeds of $80.1 million from the sale of these notes to fund a portion of the cash portion of the purchase price of the merger with 3TEC. As a result of the issuance, the borrowing base on our credit facility was reduced to $402.5 million.
At December 31, 2003 we had a working capital deficit of approximately $94.8 million. Approximately $55.1 million of the working capital deficit is attributable to the fair value of our commodity derivative instruments. In accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”, the fair value of all derivative instruments is recorded on the balance sheet. Gains and losses on instruments that qualify for hedge accounting are included in oil and gas revenues in the period that the related volumes are delivered. Changes in the fair value of instruments that do not qualify for hedge accounting are reflected in other income (expense). The hedge agreements provide for monthly settlement based on the differential between the agreement price and actual NYMEX oil price. Cash received for sale of physical production will be based on actual market prices and will generally offset any gains or losses on the hedge instruments. In addition, $16.0 million of the working capital deficit is attributable to the in-the-money value of stock appreciation rights that were deemed vested at December 31, 2003. The remaining working capital deficit will be financed through cash flow and borrowings under our credit facility.
As of December 31, 2003 we had $211.0 million in borrowings and $5.5 million in letters of credit outstanding under our revolving credit facility. The credit facility has a borrowing base of $402.5 million that will be reviewed every six months, with the lenders and us each having the right to one annual interim unscheduled redetermination, and adjusted based on our oil and gas properties, reserves, other indebtedness and other relevant factors, and matures in 2005. The credit facility contains a $50.0 million sub-limit on letters of credit. To secure borrowings, we pledged 100% of the shares of stock of our domestic subsidiaries and gave mortgages covering 80% of the total present value of our domestic oil and gas properties.
Amounts borrowed under the credit facility bear an annual interest rate, at our election, equal to either: (i) the Eurodollar rate, plus from 1.375% to 2.000%; or (ii) the greatest of (1) the prime rate, as determined by JPMorgan Chase Bank, (2) the certificate of deposit rate, plus 1.0%, or (3) the federal funds rate, plus 0.5%; plus an additional 0.125% to 0.750% for each of (1)-(3). The amount of interest payable on outstanding borrowings is based on (1) the utilization rate as a percentage of the total amount of funds borrowed under the credit facility to the borrowing base and (2) our long-term debt rating. Commitment fees and letter of credit fees under the credit facility are based on the utilization rate and long-term debt rating. Commitment fees range from 0.375% to 0.5% of the unused portion of the borrowing base. Letter of credit fees range from 1.375% to 2.000%. The issuer of any letter of credit receives an issuing fee of 0.125% of the undrawn amount. Our domestic subsidiaries unconditionally guarantee payment of borrowings under the credit facility.
The credit facility contains negative covenants that limit our ability, as well as the ability of our subsidiaries, among other things, to incur additional debt, pay dividends on stock, make distributions of cash or property, change the nature of our business or operations, redeem stock or redeem subordinated debt, make investments, create liens, enter into leases, sell assets, sell capital stock of subsidiaries, create subsidiaries, guarantee other indebtedness, enter into agreements that restrict dividends from subsidiaries, enter into certain types of swap agreements, enter into gas imbalance or take-or-pay arrangements, merge or consolidate and enter into transactions with affiliates. In addition, the credit facility requires us to maintain a current ratio, which includes availability, of at least 1.0 to 1.0 and a minimum tangible net worth (as defined).
The $275 million 8.75% senior subordinated notes are our unsecured general obligations, are subordinated in right of payment to all of our existing and future senior indebtedness and are jointly
and severally guaranteed on a full, unconditional basis by all of our existing and future domestic restricted subsidiaries. The indenture governing the notes contains covenants that limit our ability, as well as the ability of our subsidiaries, among other things, to incur additional indebtedness, make certain investments, make restricted payments, sell assets, enter into agreements containing dividends and other payment restrictions affecting subsidiaries, enter into transactions with affiliates, create liens, merge, consolidate and transfer assets and enter into different lines of business. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase. The indenture governing the 8.75% senior subordinated notes permitted the spin-off and the spin-off did not, in itself, constitute a change of control for purposes of the indenture. The merger did not constitute a change of control for purposes of the indenture.
The notes are not redeemable until July 1, 2007. On or after that date they are redeemable, at our option, at 104.375% of the principal amount for the twelve-month period ending June 30, 2008, at 102.917% of the principal amount for the twelve-month period ending June 30, 2009, at 101.458% of the principal amount for the twelve-month period ending June 30, 2010 and at 100% of the principal amount thereafter. In each case, accrued interest is payable to the date of redemption.
We have been assigned a Ba3 senior implied rating and the 8.75% senior subordinated notes have been assigned a B2 rating by Moody’s Investor Service Inc. We have also been assigned a BB- corporate credit rating by Standard and Poor’s Corp. All of these ratings are all below investment grade. As a result, at times we may have difficulty accessing capital markets or raising capital on favorable terms.
Cash Flows
Net cash provided by operating activities were $118.3 million, $78.8 million and $116.8 million for 2003, 2002 and 2001, respectively. The increase from 2002 to 2003 is primarily a result of increased sales volumes as a result of the 3TEC acquisition and, to a lesser extent, increases in oil and gas prices. The change between 2002 and 2001 is primarily due to changes in oil and gas prices in the periods presented.
Net cash used in investing activities were $368.7 million, $64.2 million and $125.9 million, respectively, and consist primarily of costs incurred in connection with our oil and gas acquisition, development and exploration activities. Our 2003 capital expenditures included $267.6 million for the acquisition of 3TEC. The 2002 capital expenditure level was reduced from the 2001 amount to manage debt levels and allow flexibility in pursuing acquisition and other opportunities.
Net cash provided by financing activities in 2003 was $250.8 million. Cash receipts in 2003 included net borrowings of $175.2 million under our credit facility and proceeds received from the issuance of our 8.75% senior subordinated notes ($80.1 million). Cash outflows in 2003 included payments for debt issuance costs ($4.3 million); and principal payments on long-term debt ($0.5 million); and repurchases of treasury stock ($0.1 million). Net cash used in financing activities in 2002 was $13.7 million. Cash receipts in 2002 included proceeds received from the issuance of the 8.75% notes ($196.8 million); cash contributions by Plains Resources ($52.2 million); cash advances from
Plains Resources prior to the reorganization ($20.4 million); and net borrowings under the PXP credit facility ($35.8 million). Cash outflows in 2002 included cash distributions to Plains Resources ($312.0 million); payments for debt issuance costs ($5.9 million); and principal payments on long-term debt ($0.5 million). Cash provided by financing activities in 2001 of $8.5 million included cash advances from Plains Resources ($9.0 million) less principal payments on long-term debt ($0.5 million).
Capital Requirements
We have made and will continue to make substantial capital expenditures for the acquisition, exploitation, development, exploration and production of oil and gas. During 2004, we expect to make aggregate capital expenditures of approximately $163-$177 million on our existing asset base. Capital expenditures for the Nuevo properties are expected to be $65-$70 million pursuant to Nuevo’s 2004 capital plan. Based on the foregoing, total pro forma capital expenditures for the combined asset base are estimated to be $228-$247 million for 2004, assuming the merger closed on January 1, 2004. Subsequent to the closing of the Nuevo acquisition, we may reallocate capital between the two asset bases to optimize 2004 spending. We expect that 2004 capital expenditures will be funded with cash flow from our operations and our revolving credit facility. In addition, we intend to continue to pursue the acquisition of underdeveloped producing properties.
We will incur cash expenditures upon the exercise of stock appreciation rights, or SARs, but our outstanding share count will not increase. At December 31, 2003 we had approximately 3.9 million SARs outstanding of which 2.0 million were vested. If all of the vested SARs were exercised, based on $15.39, the price of our common stock as of December 31, 2003, we would pay $13.2 million to holders of the SARs. In 2003 we made cash payments of $2.1 million for SARs that were exercised during the year. See “Critical Accounting Policies and Factors that May Affect Future Results-Stock Appreciation Rights”.
Commitments and Contingencies
Contractual obligations. At December 31, 2003, the aggregate amounts of contractually obligated payment commitments for the next five years are as follows (in thousands):
The long-term debt amounts consist principally of amounts due under our credit facility and our 8.75% notes. The obligation for producing property remediation consists of obligations associated with the purchase of certain of our California properties. Operating leases relate primarily to obligations associated with our office facilities and certain cogeneration operations in California.
Environmental matters. As discussed under “Business & Properties-Regulation -Environmental,” as an owner or lessee and operator of oil and gas properties, we are subject to various federal, state, and local laws and regulations relating to discharge of materials into, and protection of, the environment. Typically when producing oil and gas assets are purchased, one assumes the obligation to plug and abandon wells that are part of such assets. However, in some instances, we have received an indemnity in connection with such purchase. There can be no assurance that we will be able to collect on these indemnities. Often these regulations are more
burdensome on older properties that were operated before the regulations came into effect such as some of our properties in California that have operated for over 90 years. We have established policies for continuing compliance with environmental laws and regulations. We also maintain insurance coverage for environmental matters, which we believe is customary in the industry, but we are not fully insured against all environmental risks. 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.
Plugging, Abandonment and Remediation Obligations. Consistent with normal industry practices, substantially all of our oil and 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. Typically, when producing oil and gas assets are purchased the purchaser assumes the obligation to plug and abandon wells that are part of such assets. However, in some instances, we received an indemnity with respect to those costs.
In connection with the purchase of certain of our onshore California properties, each year we are required to plug and abandon 20% of the then remaining inactive wells (there were 158 inactive wells at December 31, 2003). If we do not meet this commitment, and the requirement is not waived, we must escrow funds to cover the cost of the wells that were not abandoned. To date we have not been required to escrow any funds. In addition, until the end of 2006 we are required to spend at least $600,000 per year (and $300,000 per year from 2007 through 2011) to remediate oil contaminated soil from existing well sites that require remediation
For a discussion of our specific contractual obligations to incur plugging, abandonment and remediation costs, see “Business-Plugging, Abandonment and Remediation Obligations”.
Other commitments and contingencies. 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.
As discussed under “Legal Proceedings,” in the ordinary course of business, we are a claimant and/or defendant in various other legal proceedings. In particular, we were required to indemnify Plains Resources for any liabilities it incurred in connection with a lawsuit it (through a predecessor interest in Stocker Resources, Inc.) had regarding an electric services contract with Commonwealth Energy Corporation. In January 2004 Plains Resources settled the suit. Under the terms of our master separation agreement with Plains Resources, we indemnified them for damages they might incur as a result of this action.
Operating risks and insurance coverage. Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and gas, including well blowouts, cratering, explosions, oil spills, gas or well fluids, fires, pollution and releases of toxic gas, each of which could result in damage to or destruction of oil and gas wells, production facilities or other property, or injury to persons. Our operations in California, including transportation of oil by pipelines within the city and county of Los Angeles, are especially susceptible to damage from earthquakes and involve increased risks of personal injury, property damage and marketing interruptions because of the population density of southern California. Although we maintain insurance coverage considered to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of high premium costs. We maintain coverage for earthquake damages in California but this coverage may not provide for the full effect of damages that could occur and we may be subject to additional liabilities. The occurrence of a significant event that is not fully insured against could have a material adverse effect on our financial position. Our insurance does not cover every potential risk associated with operating our pipelines, including the potential loss of significant revenues. Consistent
with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences.
Industry Concentration
Financial instruments which potentially subject us to concentrations of credit risk consist principally of accounts receivable with respect to our oil and gas operations and derivative instruments related to our hedging activities. PAA is the exclusive marketer/purchaser for all of our equity oil production in California and Illinois. This concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that PAA may be affected by changes in economic, industry or other conditions. We do not believe the loss of PAA as the exclusive purchaser of our equity production would have a material adverse affect on our results of operations. We believe PAA could be replaced by other purchasers under contracts with similar terms and conditions.
The contract counterparties for our derivative commodity contracts are all major financial institutions with Standard & Poor’s ratings of A or better. Six of the financial institutions are participating lenders in our credit facility, holding contracts that represent approximately 62% of the fair value of all of our open positions at December 31, 2003.
There are a limited number of alternative methods of transportation for our production. Substantially all of our oil and gas production is transported by pipelines and trucks 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 oil and gas production which could have a negative impact on future results of operations or cash flows.
Critical Accounting Policies and Factors that May Affect Future Results
Based on the accounting policies which we have in place, certain factors may impact our future financial results. The most significant of these factors and their effect on certain of our accounting policies are discussed below.
Commodity pricing and risk management activities. Prices for oil and gas have historically been volatile. Decreases in oil and gas prices from current levels will adversely affect our revenues, results of operations, cash flows and proved reserves. If the industry experiences significant prolonged future price decreases, this could be materially adverse to our operations and our ability to fund planned capital expenditures.
Periodically, we enter into hedging arrangements relating to a portion of our oil and gas sales to achieve a more predictable cash flow, as well as to reduce our exposure to adverse price fluctuations. Hedging instruments used are typically fixed price swaps and collars and purchased puts and calls. While the use of these types of hedging instruments limits our downside risk to adverse price movements, we are subject to a number of risks, including instances in which the benefit to revenues is limited when commodity prices increase. For a further discussion concerning our risks related to oil and gas prices and our hedging programs, see “Item 7A
Item 7A. Qualitative and Quantitative Disclosures About Market Risks
We are exposed to various market risks, including volatility in oil and gas commodity prices and interest rates. Although we have routinely hedged a substantial portion of our production and intend to continue this practice, substantial future oil and gas price declines would adversely affect our overall
results, and therefore our liquidity. Furthermore, low oil and gas prices could affect our ability to raise capital on favorable terms. Decreases in the prices of oil and 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. To manage our exposure, we monitor 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.
Under SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”, as amended, all derivative instruments are recorded on the balance sheet at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. To qualify for hedge accounting, the derivative must qualify either as a fair value hedge, cash flow hedge or foreign currency hedge. Currently, we use primarily cash flow hedges and the remaining discussion will relate exclusively to this type of derivative instrument. If the derivative qualifies for hedge accounting, the gain or loss on the derivative is deferred in accumulated Other Comprehensive Income, or OCI, a component of our stockholders’ equity, to the extent the hedge is effective.
The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. Hedge accounting is discontinued prospectively when a hedge instrument becomes ineffective. Gains and losses deferred in OCI related to cash flow hedges for which hedge accounting has been discontinued remain unchanged until the related product has been delivered. If it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are recognized in earnings immediately.
We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. Hedge effectiveness is measured on a quarterly basis. This process includes specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.
We utilize various derivative instruments to hedge our exposure to price fluctuations on oil and gas sales. The derivative instruments consist primarily of cash-settled option and swap contracts entered into with financial institutions. We also use interest rate swaps to manage the interest rate exposure on our credit facility.
We assumed several open derivative positions in connection with the 3TEC merger. Such derivative positions were recorded at fair value in the purchase price allocation. We determined that one such derivative position did not qualify as a hedge. Changes in fair value of such position subsequent to the merger have been reflected in income. All other open derivative positions at December 31, 2003 qualified for hedge accounting.
At December 31, 2002, OCI consisted of $20.9 million ($12.6 million, net of tax) of unrealized net losses on our open hedging instruments. As oil prices increased significantly during 2003 and we assumed 3TEC’s hedge positions as a result of the merger, the fair value of our open hedging positions that qualified for hedge accounting, net of settlements, decreased $45.8 million ($27.7 million after tax). At December 31, 2003, OCI consisted of $66.7 million ($40.3 million after tax) of unrealized losses on our open hedging instruments, $0.2 million ($0.1 million, net of tax) loss related to our
interest rate swap and $0.1 million ($0.1 million, net of tax) loss related to deferred compensation liabilities. At December 31, 2003 the assets and liabilities related to our open commodity derivative instruments were included in current liabilities ($55.1 million), other long-term liabilities ($23.7 million) and deferred income taxes (a tax benefit of $32.1 million).
During 2003, 2002 and 2001, deferred gains (losses) of ($37.6 million), ($15.6 million) and $0.3 million, respectively, were reclassified from OCI and charged to income as a reduction of oil and gas revenues. As of December 31, 2003, $43.0 million ($26.0 million, net of tax) of deferred net losses on derivative instruments recorded in OCI are expected to be reclassified to earnings during the next twelve-month period. During 2003 we recognized $0.8 million of income from the change in the fair value of derivatives that do not qualify for hedge accounting.
Commodity price risk. As of February 29, 2004, we had the following open hedge positions with respect to our oil and gas properties:
Assuming our fourth quarter 2003 production volumes remain unchanged, these positions result in us hedging approximately 69%, 45% and 39% of production in 2004, 2005 and 2006, respectively. Location and quality differentials attributable to our properties and the cost of the hedges are not included in the foregoing prices. Because of the quality and location of our oil and gas production, these adjustments will reduce our net price.
The fair value of outstanding crude oil derivative commodity instruments and the change in fair value that would be expected from a 10% price decrease are shown in the table below (in millions):
The fair value of the swaps and option contracts 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 quarters 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% decrease in price 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% change in prompt month 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.
The contract counterparties for our derivative commodity contracts are all major financial institutions with Standard & Poor’s ratings of A or better. Six of the financial institutions are participating lenders in our revolving credit facility, holding contracts that represent approximately 62% of the fair value of all open positions as of December 31, 2003.
Our management intends to continue to maintain hedging arrangements for a significant portion of our production. These contracts may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if oil prices decline below the prices at which these hedges are set, but ceiling prices in our hedges may cause us to receive less revenues on the hedged volumes than we would receive in the absence of hedges.
Interest rate risk. Our credit facility is sensitive to market fluctuations in interest rates. We use interest rate swaps 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. We have entered into an interest rate swap for an aggregate notional principal amount of $7.5 million that fixes the interest rate on that amount of borrowing under our credit facility at 3.9% plus the LIBOR margin set forth in our credit facility. The swap expires in October 2004.
Item 8.
Item 8. Financial Statements and Supplementary Data
The information required here is included in this 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.
Item 9A.
Item 9A. Controls and Procedures
Under the supervision and with the participation of our management, including our Chief Executive Officer (our principal executive officer) and our Chief Financial Officer (our principal financial officer), we evaluated the effectiveness of our disclosure controls and procedures (as defined under Rule 13a-14(c) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on this evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures as of December 31, 2003 are effective to ensure that information we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
There were no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of such evaluation.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant
Information regarding our directors and executive officers will be included in an amendment to this Form 10-K or in the proxy statement for the 2004 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2003, and is incorporated by reference to this report.
We have provided summary information with respect to our directors and executive officers following Item 4 in Part I of this report.
Item 11.
Item 11. Executive Compensation
Information regarding executive compensation will be included in an amendment to this Form 10-K or in the proxy statement and is incorporated by reference to this report.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Information regarding beneficial ownership will be included in an amendment to this Form 10-K or in the proxy statement and is incorporated by reference to this report.
Item 13.
Item 13. Certain Relationships and Related Transactions
Information regarding certain relationships and related transactions will be included in an amendment to this Form 10-K or in the proxy statement and is incorporated by reference to this report.
Item 14.
Item 14. Principal Accountant Fees and Services
Information regarding principal accountant fees and services will be included in an amendment to this Form 10-K or in the proxy statement and is incorporated by reference to this report.
PART IV
Item 15.
Item 15. 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
*
Filed herewith.
**
Furnished herewith.
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 11, 2004
By:
/s/ STEPHEN A. THORINGTON
Stephen A. Thorington, 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.
PLAINS EXPLORATION & PRODUCTION COMPANY
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 Auditors
To the Board of Directors and Stockholders
of Plains Exploration & Production Company:
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Plains Exploration and Production Company and its subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. 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 of America, 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 our opinion.
As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations effective January 1, 2003. As discussed in Note 3 to the consolidated financial statements, the Company changed its method of accounting for derivative instruments and hedging activities, effective January 1, 2001.
PricewaterhouseCoopers LLP
Houston, Texas
March 10, 2004
PLAINS EXPLORATION & PRODUCTION COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands of dollars)
See notes to consolidated financial statements.
PLAINS EXPLORATION & PRODUCTION COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(in thousands, except per share data)
See notes to consolidated financial statements.
PLAINS EXPLORATION & PRODUCTION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands of dollars)
See notes to consolidated financial statements.
PLAINS EXPLORATION & PRODUCTION COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in thousands of dollars)
See notes to consolidated financial statements.
PLAINS EXPLORATION AND PRODUCTION COMPANY
STATEMENTS OF STOCKHOLDERS’ EQUITY
(share and dollar amounts in thousands)
See notes to consolidated financial statements.
PLAINS EXPLORATION & PRODUCTION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1-Organization and Significant Accounting Policies
Organization
The consolidated financial statements of Plains Exploration & Production Company (“PXP”, “us”, “our”, or “we”) include the accounts of our wholly-owned subsidiaries Arguello Inc., Plains Illinois, Inc., PXP Gulf Coast Inc. and other immaterial subsidiaries. We are a Delaware corporation that was converted from a limited partnership in September 2002. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to prior year statements to conform to the current year presentation.
We are an independent energy company that is engaged in the “upstream” oil and gas business. The upstream business acquires, exploits, develops, explores for and produces oil and gas. Our upstream activities are all located in the United States.
Under the terms of a Master Separation Agreement between us and Plains Resources, on July 3, 2002, Plains Resources contributed to us: (i) 100% of the capital stock of its wholly owned subsidiaries that own oil and gas properties offshore California and in Illinois; and (ii) all amounts payable to it by us and our subsidiary companies (the “reorganization”). The contribution of the amounts payable to Plains Resources is reflected in Stockholders’ Equity.
On July 3, 2002, we issued $200.0 million of 8.75% Senior Subordinated Notes due 2012 (the “8.75% Notes”) and entered into a $300.0 million revolving credit facility. The net proceeds from the 8.75% notes, $195.3 million, and $116.7 million borrowed under the credit facility were used to pay a $312.0 million cash distribution to Plains Resources.
Effective at the time of the reorganization we assumed direct ownership and control of Arguello Inc., Plains Illinois, Inc., and two other subsidiaries. Accordingly, for periods subsequent to the reorganization, the financial information is presented on a consolidated basis. For periods prior to the reorganization, the historical operations of the businesses owned by PXP, Arguello Inc., Plains Illinois, Inc. and the two other subsidiaries, all previously referred to as the Upstream Subsidiaries of Plains Resources Inc., were presented on a carve-out combined basis since no direct owner relationship existed among the various operations comprising these businesses. Accordingly, Plains Resources’ net investment in the businesses (combined owners’ equity) was shown in lieu of stockholder’s equity in the historical financial statements.
In June 2002, we filed a registration statement on Form S-1 with the Securities and Exchange Commission (the “SEC”) for the initial public offering (the “IPO”), of our common stock. We terminated the IPO in October 2002, primarily due to market conditions. As a result, costs and expenses of $2.4 million incurred in connection with the IPO were charged to expense during 2002.
In September 2002, we were capitalized with 24.2 million shares of common stock, all of which were owned by Plains Resources. As a result of the capitalization, Combined Owners Equity as of June 30, 2002 was reclassified between Common Stock and Additional Paid-in Capital. Retained Earnings as December 31, 2002 represents our earnings from June 30, 2002 through December 31, 2002.
On December 18, 2002, Plains Resources distributed 24.1 million of the issued and outstanding shares of our common stock to the holders of Plains Resources’ common stock on the basis of one
share of our common stock for every one share of Plains Resources common stock held as of the close of business on December 11, 2002 (the “spin-off”) and contributed 0.1 million shares of our common stock to us. Prior to the spin-off Plains Resources made a $52.2 million cash capital contribution to us and transferred to us certain assets and liabilities of Plains Resources ($4.3 million, net), primarily related to land, unproved oil and gas properties, office equipment and compensation obligations. In addition, as a result of the spin-off certain tax attributes previously considered in the deferred income tax liabilities allocated to us ($4.3 million) and recognized in our financial statements remained with Plains Resources. The cash contributions, the transfer of assets and the assumption of certain liabilities by us and the effect of the increase in our deferred tax liabilities are reflected in Additional Paid-in Capital in Stockholders’ Equity.
On June 4, 2003, we acquired 3TEC Energy Corporation, or 3TEC. We have accounted for the acquisition as a purchase with effect from June 1, 2003. See Note 2.
These financial statements include allocations of direct and indirect corporate and administrative costs of Plains Resources made prior to the reorganization. The methods by which such costs were estimated and allocated to us were deemed reasonable by Plains Resources’ management; however, such allocations and estimates are not necessarily indicative of the costs and expenses that would have been incurred had we operated as a separate entity. Allocations of such costs are considered to be related party transactions and are discussed in Note 5.
Significant Accounting Policies
Oil and 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 estimated asset retirement obligations recorded in accordance with Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143), are amortized to expense by the unit-of-production method using engineers’ estimates of 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 (including the effect of any related hedging activities) reduced by future operating expenses, development expenditures and abandonment costs (net of salvage values), and estimated future income taxes thereon.
Asset Retirement Obligations. Effective January 1, 2003, we adopted SFAS 143 which requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred. A legal obligation is a liability that a party is required to settle as a result of an existing or enacted law, statute, ordinance or contract. When the liability is initially recorded, the entity is required to capitalize the retirement cost of the related long-lived asset. Each period the liability is accreted to its then present value, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. In prior periods we included estimated future costs of abandonment and dismantlement in our full cost amortization base and these costs were amortized as a component of our depletion expense.
At January 1, 2003, the present value of our future asset retirement obligation for oil and gas properties and equipment was $26.5 million. The cumulative effect of our adoption of SFAS 143 and the change in accounting principle resulted in an increase in net income during the first quarter of 2003 of $12.3 million (reflecting a $30.8 million decrease in accumulated depreciation, depletion and amortization, partially offset by $10.6 million in accretion expense, and $7.9 million in income taxes). We recorded a liability of $26.5 million and an asset of $15.9 million in connection with the adoption of SFAS 143. Adopting SFAS No. 143 did not impact our cash flows.
The following table illustrates the changes in our asset retirement obligation during the period (in thousands):
(1)
$500 included in current liabilities.
The following table illustrates on a pro forma basis the effect on our net income and earnings per share as if SFAS 143 had been applied during the years ended December 31, 2002 and 2001 (thousands of dollars, except per share data):
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. Net gains or losses on property and equipment disposed of are included in interest and other income in the period in which the transaction occurs.
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) oil and natural gas reserves; (2) depreciation, depletion and amortization, including future abandonment costs; (3) assigning fair value and allocating purchase price in connection with business combinations, including goodwill; (4) income taxes; (5) accrued liabilities; and (6) valuation of derivative instruments. 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. At December 31, 2003 and 2002, the majority of cash and cash equivalents is concentrated in two institutions and at times may exceed federally insured limits. We periodically assess the financial condition of the institutions and believe that any possible credit risk is minimal.
Inventory. Oil inventories are carried at the lower of the cost to produce or market value. Materials and supplies inventory is stated at the lower of cost or market with cost determined on an average cost method. Inventory consists of the following (in thousands):
Other Assets. Other assets consists of the following (in thousands):
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. Use of the straight-line method does not differ materially from the “effective interest” method of amortization.
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. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
Under the terms of a tax allocation agreement, our taxable income or loss prior to the spin-off was included in the consolidated income tax returns filed by Plains Resources. To the extent Plains
Resources’ net operating losses were used in the consolidated return to offset our taxable income from operations during the period January 1, 2002 through the spin-off, we will reimburse Plains Resources for the reduction in our federal income tax liability resulting from the utilization of such net operating losses, but such reimbursement shall not exceed $3.0 million exclusive of any interest accruing under the agreement. At December 31, 2003 and 2002 other long-term liabilities includes $3.0 million payable to Plains Resources with respect to the utilization of net operating losses. Such amount will be paid to Plains Resources in periods in which they are in a currently taxable position.
Income tax obligations reflected in our financial statements in periods prior to the spin-off are calculated assuming we filed a separate consolidated income tax return. To reflect differences between the amounts included in our financial statements at December 31, 2002 and the final 2002 tax returns filed by us and Plains Resources, income tax expense for the year ended December 31, 2003 includes a $1.7 million charge (a $3.8 million deferred tax expense that includes a $1.7 million adjustment to reflect an increase in our effective state income tax rate, partially offset by a $2.1 million current tax benefit) and our deferred tax liability at December 31, 2002 has been adjusted by $4.8 million. Such adjustments resulted in a $6.9 million decrease in our Additional Paid-in Capital.
Revenue Recognition. Oil and gas revenue from our interests in producing wells is recognized when the production is delivered and the title transfers.
Derivative Financial Instruments (Hedging). We utilize various derivative instruments to reduce our exposure to fluctuations in the market price of oil and gas. The derivative instruments consist primarily of oil and gas swap and option contracts entered into with financial institutions. Gains and losses on derivative instruments that qualify for hedge accounting are included in oil and gas revenues in the period the related volumes are delivered. Changes in the fair value of derivative instruments that do not qualify for hedge accounting are recognized in other income (expense). See Note 3.
Stock Based Compensation. We account for stock based compensation using the intrinsic value method. See Note 6.
Earnings Per Share. In September 2002, we were capitalized with 24,200,000 shares of common stock, all of which were owned by Plains Resources. In accordance with SEC Staff Accounting Bulletin No. 98, this capitalization has been retroactively reflected for purposes for calculating earnings per share for the year ended December 31, 2001. The weighted average shares outstanding for computing both basic and diluted earnings per share was 24,200,000 shares for the year ended December 31, 2001. Weighted average shares outstanding for computing basic and diluted earnings per share were 33,321,000 and 33,460,000, respectively, for the year ended December 31, 2003 and 24,193,000 and 24,201,000, respectively, for the year ended December 31, 2002. In computing EPS, no adjustments were made to reported net income. In 2003 and 2002, the difference between basic and diluted shares relates to non-vested restricted stock and in 2001 there was no potential common stock.
Goodwill. In a purchase transaction, goodwill represents the excess of the purchase price plus the liabilities assumed, including deferred income taxes recorded in connection with the transaction, over the fair value of the net assets acquired. Goodwill is not amortized, but instead must be tested at least annually for impairment by applying a fair-value based test. Goodwill is deemed impaired to the extent of any excess of its carrying amount over the residual fair value of the reporting unit. Such impairment could significantly reduce earnings during the period in which the impairment occurs and would result in a corresponding reduction to goodwill and stockholders’ equity. The most significant factors that could result in the impairment of our goodwill would be significant declines in oil and gas prices and/or reserve volumes which would result in a decline in the fair value of our oil and gas properties.
Recent Accounting Pronouncements. The Financial Accounting Standards Board (FASB) issued Financial Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities” in January 2003. FIN 46 addresses the consolidation of variable interest entities (VIEs) by business enterprises that are the primary beneficiaries. A VIE is an entity that does not have sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or whose equity investors lack the characteristics of a controlling financial interest. The primary beneficiary of a VIE is the enterprise that has the majority of the risks or rewards associated with the VIE. In December 2003, the FASB issued a revision to FIN 46, Interpretation No. 46R (FIN 46R), to clarify some of the provisions of FIN 46, and to exempt certain entities from its requirements. Application of FIN 46R is required in financial statements of public entities that have interests in structures that are commonly referred to as special-purpose entities for periods ending after December 15, 2003. Application for all other types of VIEs is required in financial statements for periods ending after March 15, 2004. We do not believe we participate in any arrangement that would be subject to the provisions of FIN 46R.
In 2003, the SEC inquired of the FASB regarding the application of certain provisions of SFAS No. 141, Business Combinations, (“SFAS No. 141”) and SFAS No. 142, Goodwill and Other Intangible Assets, (“SFAS No. 142”) to oil and gas companies. SFAS Nos. 141 and 142 became effective for transactions subsequent to June 30, 2001. SFAS No. 141 requires that all business combinations initiated after June 30, 2001 be accounted for using the purchase method and that acquired intangible assets be disaggregated and reported separately from goodwill. Specifically, the SEC’s inquiry is based on whether costs of contract-based drilling and mineral use rights (“mineral rights”) should be recorded and disclosed as intangible assets under the guidance in SFAS Nos. 141 and 142. The current practice for us and the industry is to present oil and gas related assets, including mineral rights, as property and equipment (tangible assets) on the balance sheet. Subsequent to June 30, 2001, we entered into a business combination with 3TEC and the majority of the purchase price was allocated to oil and gas properties.
An Emerging Issues Task Force Working Group (“EITF”) has been created to research the accounting and disclosure treatment of mineral rights for oil and gas companies. As a result, the EITF has added Issue No. 04-2, “Whether Mineral Rights are Tangible or Intangible Assets and Related Issues,” and Issue No. 03-S, “Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil and Gas Companies”. Currently, we do not believe that generally accepted accounting principles require the classification of mineral rights as intangible assets and continues to classify these assets as oil and gas properties. However, the decisions of the EITF may affect how we classify these assets in the future. If the EITF ultimately determines that SFAS Nos. 141 and 142 require oil and gas companies to classify mineral rights as separate intangible assets, at December 31, 2003, we had undeveloped leaseholds of approximately $32.0 million that would be reclassified as “intangible undeveloped leasehold” and developed leaseholds of approximately $278.0 million that would be reclassified as “intangible developed leasehold”. The amounts that would be subject to this reclassification included in our historical balance sheet prior to the acquisition of 3TEC is not material
Amounts to be reclassified would be impacted by the provisions of the EITF consensus. The ultimate reclassification amount could be materially different than the above amounts as numerous decisions that could be included in the consensus would impact the composition and amortization of the intangible assets, if any.
We believe that cash flows and results of operations would not be affected since such intangible assets would likely continue to be depleted and assessed for impairment in accordance with our accounting policies as prescribed under the full cost method of accounting for oil and gas properties. Further, we do not believe the classification of the mineral rights as intangible assets would affect compliance with covenants under our debt agreements.
We will continue to classify our oil and gas mineral rights held under lease and other contractual rights representing the right to extract such reserves as tangible oil and gas properties until further guidance is provided.
Note 2-Acquisition of 3TEC Energy Corporation
On June 4, 2003, we acquired 3TEC (the “merger”), for approximately $312.9 million in cash and common stock plus $90.0 million to retire 3TEC’s outstanding debt. In the transaction, each 3TEC common share was converted in to 0.85 of a share of our common stock and $8.50 in cash. In connection with the merger, we paid cash consideration to the common shareholders of approximately $152.4 million and issued 15.3 million shares. In addition, we paid cash consideration of $8.3 million and issued 0.8 million common shares to redeem outstanding warrants. The cash portion of the purchase price was funded by the issuance of $75.0 million of senior subordinated notes and amounts borrowed under our revolving credit facility. We have accounted for the acquisition of 3TEC as a purchase effective June 1, 2003.
The calculation of the purchase price and the allocation to assets and liabilities as of June 4, 2003 are shown below. The average PXP common stock price is based on the average closing price of PXP common stock during the five business days commencing two days before the merger was announced.
Prior to the merger, 3TEC redeemed all outstanding shares of its Series D preferred stock for $14.7 million and incurred $11.1 million of merger related costs. Current liabilities assumed in the merger include $14.7 million related to the preferred stock redemption which was paid shortly after the merger and $1.7 million of merger related costs.
The significant factors contributing to the recognition of goodwill include, but are not limited to, providing a presence in East Texas and the Gulf Coast regions that can be used to pursue other opportunities in these areas, improving financial flexibility with more efficient access to lower cost capital and higher returns from synergies in having a broader and more diversified reserve base and the ability to acquire an established business with an assembled workforce. In addition, additional goodwill has been recorded due to the application of purchase accounting rules that require that deferred taxes be recorded at undiscounted amounts. The goodwill is not deductible for income tax purposes.
Pro Forma Information
The following unaudited pro forma information for the years ended December 31, 2003 and 2002 have been prepared based on our historical consolidated statements of income and the historical consolidated statements of income of 3TEC. Such pro forma information for 2003 and 2002 assumes the merger and the issuance of $75.0 million of 8.75% senior subordinated notes on May 31, 2003 occurred on January 1, 2003 and January 1, 2002, respectively. Such pro forma information for 2002 also assumes the following 2002 transactions occurred on January 1, 2002: (i) the reorganization and spin-off, discussed in Note 1; and (ii) the July 3, 2002 issuance of $200.0 million of 8.75% senior subordinated notes, discussed in Note 4.
We believe the assumptions used provide a reasonable basis for presenting the significant effects directly attributable to the pro forma transactions. This pro forma financial information does not purport to represent what our results of operations would have been if such transactions had occurred on such dates.
Note 3-Derivative Instruments and Hedging Activities
Derivative instruments are accounted for in accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” as amended. Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. If a derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. If a derivative qualifies for hedge accounting, the unrealized gain or loss on the derivative is deferred in accumulated Other Comprehensive Income (“OCI”), a component of Stockholders’ Equity. On January 1, 2001, in accordance with the transition provisions of SFAS 133, we recorded a gain of $7.0 million in OCI, representing the cumulative effect of an accounting change to recognize at fair value all cash flow derivatives. We recorded cash flow hedge derivative assets and liabilities of $9.7 million and $4.2 million, respectively, and a net-of-tax non-cash charge of $1.5 million was recorded in earnings as a cumulative effect adjustment.
The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. Hedge accounting is discontinued prospectively when a hedge instrument becomes ineffective. Gains and losses deferred in OCI related to cash flow hedges for which hedge accounting has been discontinued remain unchanged until the related product has been delivered. If it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are recognized in earnings immediately.
Effective October 2001 we implemented Derivatives Implementation Group (“DIG”), Issue G20, “Cash Flow Hedges: Assessing and Measuring the Effectiveness of a Purchased Option Used in a
Cash Flow Hedge”, or DIG Issue G20, which provides guidance for basing the assessment of hedge effectiveness on total changes in an option’s cash flows rather than only on changes in the option’s intrinsic value. Implementation of DIG Issue G20 has reduced earnings volatility since it allows us to include changes in the time value of purchased options and collars in the assessment of hedge effectiveness. Time value changes were previously recognized in current earnings since we excluded them from the assessment of hedge effectiveness. Oil and gas revenues for the year ended December 31, 2001 include a $3.1 million non-cash loss related to the ineffective portion of the cash flow hedges representing the fair value change in the time value of options for the nine months before the implementation of DIG Issue G20. No ineffectiveness was recognized in 2003 or 2002.
We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. Hedge effectiveness is measured on a quarterly basis. This process includes specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.
We assumed several open derivative positions in connection with the 3TEC merger. Such derivative positions were recorded at fair value in the purchase price allocation. Changes in fair value of such position subsequent to the merger have been reflected in income. All other open derivative positions at December 31, 2003 related to production from our oil and gas properties qualified for hedge accounting.
At December 31, 2002, OCI consisted of $20.9 million ($12.6 million, net of tax) of unrealized net losses on our open hedging instruments. As oil prices increased significantly during 2003 and we assumed 3TEC’s hedge positions as a result of the merger, the fair value of our open hedging positions that qualified for hedge accounting, net of settlements, decreased $45.8 million ($27.7 million after tax). At December 31, 2003, OCI consisted of $66.7 million ($40.3 million after tax) of unrealized losses on our open hedging instruments, $0.2 million ($0.1 million, net of tax) loss related to our interest rate swap and $0.1 million ($0.1 million, net of tax) loss related to deferred compensation liabilities. At December 31, 2003 the assets and liabilities related to our open hedging instruments were included in current liabilities ($55.1 million), other long-term liabilities ($23.7 million) and deferred income taxes (a tax benefit of $32.1 million). At December 31, 2002, the assets and liabilities related to our open oil hedging instruments were included in current assets ($2.6 million), other assets ($1.4 million), current liabilities ($24.4 million), other long-term liabilities ($0.6 million) and deferred income taxes (a tax benefit of $8.4 million).
During 2003, 2002 and 2001, deferred gains (losses) of ($37.6 million), ($15.6 million) and $0.3 million, respectively, were reclassified from OCI and charged to income as a reduction of oil and gas revenues. As of December 31, 2003, $43.0 million ($26.0 million, net of tax) of deferred net losses on derivative instruments recorded in OCI are expected to be reclassified to earnings during the next twelve-month period. During 2003 we recognized $0.8 million of income from the change in the fair value of derivatives that do not qualify for hedge accounting.
Commodity price risk. At December 31, 2003 we had the following open hedge positions with respect to our oil and gas properties:
Location and quality differentials attributable to our properties are not included in the foregoing prices. Because of the quality and location of our oil production, these adjustments will reduce our net price per barrel.
We utilize interest rate swaps to manage the interest rate exposure on our long-term debt. We currently have an interest rate swap agreement that expires in October 2004, under which we receive LIBOR and pay 3.9% on a notional amount of $7.5 million. The interest rate swap fixes the interest rate on $7.5 million of borrowings under our credit facility at 3.9% plus the LIBOR margin set forth in the credit facility (5.3% at December 31, 2003).
Note 4-Long-Term Debt
At December 31, 2003, long-term debt consisted of (in thousands):
Revolving credit facility
On April 4, 2003, we entered into a three-year, $500.0 million senior revolving credit facility with a group of lenders and with JP Morgan Chase Bank serving as administrative agent. The credit facility provides for a borrowing base of $402.5 million that will be redetermined on a semi-annual basis, with us and the lenders each having the right to one annual interim unscheduled redetermination, and adjusted based on the Company’s oil and gas properties, reserves, other indebtedness and other relevant factors. Additionally, the credit facility contains a $50.0 million sub-limit on letters of credit. To secure borrowings, we pledged 100% of the shares of stock of our domestic subsidiaries and gave mortgages covering 80% of the total present value of our domestic oil and gas properties. The effective interest rate on our borrowings under the revolving credit facility was 2.9% at December 31, 2003.
Amounts borrowed under the credit facility bear an annual interest rate, at our election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus from 1.375% to 2.0%; or (ii) the greatest
of (1) the prime rate, as determined by JP Morgan Chase Bank, (2) the certificate of deposit rate, plus 1.0%, or (3) the federal funds rate, plus 0.5%; plus an additional 0.125% to 0.75% for each of (1)-(3). The amount of interest payable on outstanding borrowings is based on (1) the utilization rate as a percentage of the total amount of funds borrowed under the credit facility to the borrowing base and (2) our long-term debt rating. Commitment fees and letter of credit fees under the credit facility are based on the utilization rate and our long-term debt rating. Commitment fees range from 0.375% to 0.5% of the unused portion of the borrowing base. Letter of credit fees range from 1.375% to 2.0%. The issuer of any letter of credit receives an issuing fee of 0.125% of the undrawn amount.
The credit facility contains negative covenants that limit our ability, as well as the ability of our subsidiaries, among other things, to incur additional debt, pay dividends on stock, make distributions of cash or property, change the nature of our business or operations, redeem stock or redeem subordinated debt, make investments, create liens, enter into leases, sell assets, sell capital stock of subsidiaries, create subsidiaries, guarantee other indebtedness, enter into agreements that restrict dividends from subsidiaries, enter into certain types of swap agreements, enter into gas imbalance or take-or-pay arrangements, merge or consolidate and enter into transactions with affiliates. In addition, the credit facility requires us to maintain a current ratio, which includes availability, of at least 1.0 to 1.0 and a minimum tangible net worth (as defined). At December 31, 2003, we were in compliance with the covenants contained in our credit facility and could have borrowed the full amount available under the credit facility.
8.75% senior subordinated notes
On May 30, 2003, we issued $75.0 million principal amount of 8.75% senior subordinated notes due 2012 (the”8.75% notes”) at an issue price of 106.75%. The proceeds were used to fund a portion of the cost of the merger.
At December 31, 2003, we had $275.0 million principal amount of 8.75% notes outstanding. The 8.75% notes are our unsecured general obligations, are subordinated in right of payment to all of our existing and future senior indebtedness and are jointly and severally guaranteed on a full, unconditional basis by all of our existing and future domestic restricted subsidiaries. The indenture governing the 8.75% notes contains covenants that limit our ability, as well as the ability of our subsidiaries, among other things, to incur additional indebtedness, make certain investments, make restricted payments, sell assets, enter into agreements containing dividends and other payment restrictions affecting subsidiaries, enter into transactions with affiliates, create liens, merge, consolidate and transfer assets and enter into different lines of business. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase. The indenture governing the 8.75% notes permitted the spin-off and the spin-off did not, in itself, constitute a change of control for purposes of the indenture. The merger did not constitute a change of control for purposes of the indenture.
The 8.75% notes are not redeemable until July 1, 2007. On or after that date they are redeemable, at our option, at 104.375% of the principal amount for the twelve-month period ending June 30, 2008, at 102.917% of the principal amount for the twelve-month period ending June 30, 2009, at 101.458% of the principal amount for the twelve-month period ending June 30, 2010 and at 100% of the principal amount thereafter. In each case, accrued interest is payable to the date of redemption.
Other
We also have a note with an outstanding principal balance of $0.5 million at December 31, 2003 that was issued in connection with the purchase of a production payment on certain of our producing properties. The note bears interest at 8%, payable annually, and the final annual principal payment of $0.5 million is due in 2004.
Aggregate total maturities of long-term debt in the next five years are as follows: 2004-$0.5 million; 2005-$0.0 million; 2006-$211.0 million; 2007-$0.0 million; and 2008-$0.0 million.
Note 5-Related Party Transactions
Prior to the reorganization, we used a centralized cash management system under which our cash receipts were remitted to Plains Resources and our cash disbursements were funded by Plains Resources. We were charged interest on any amounts, other than income taxes payable, due to Plains Resources at the average effective interest rate of Plains Resources long-term debt. For the years ended December 31, 2002 and 2001 we were charged $10.7 million and $20.4 million, respectively, of interest on amounts payable to Plains Resources. Of such amounts, $9.3 million and $17.3 million was included in interest expense in 2002 and 2001, respectively, and $1.4 million and $3.1 million was capitalized in oil and gas properties in 2002 and 2001, respectively.
To compensate Plains Resources for services rendered under the Services Agreement, we were allocated direct and indirect corporate and administrative costs of Plains Resources. Such costs for the years ended December 31, 2002 and 2001 totaled $4.4 million and $8.2 million, respectively. Of such amounts, $3.1 million and $6.1 million was included in general and administrative expense in 2002 and 2001, respectively, and $1.3 million and $2.1 million was capitalized in oil and gas properties in 2002 and 2001, respectively.
In addition, prior to the reorganization Plains Resources entered into various derivative instruments to reduce our exposure to decreases in the market price of crude oil. At the time of the reorganization, all open derivative instruments held by Plains Resources on our behalf were assigned to us.
In connection with the reorganization and the spin-off we entered into certain agreements with Plains Resources, including a master separation agreement; an intellectual property agreement; the Plains Exploration & Production transition services agreement; the Plains Resources transition services agreement; and a technical services agreement. For the year ended December 31, 2003 we billed Plains Resources $0.5 million for services provided by us under these agreements and Plains Resources billed us $0.1 million for services they provided to us under these agreements.
Plains All American Pipeline, L.P. (“PAA”), a publicly-traded master limited partnership, is an affiliate of Plains Resources. Certain of our officers and directors are officers and directors of Plains Resources. PAA is the exclusive marketer/purchaser for all of our oil production, including the royalty share of production, from properties owned prior to the merger. PAA purchases for resale at market prices certain of our equity oil production. We pay PAA a marketing and administrative fee and reimburse PAA for its reasonable expenses incurred in transporting or exchanging our oil. During the years ended December 31, 2003, 2002 and 2001, the following amounts were recorded with respect to such transactions (in thousands of dollars).
During 2003, 2002 and 2001 no other purchaser accounted for more than 10% of our total revenues.
We charter private aircraft from Gulf Coast Aviation Inc., a corporation which from time-to-time leases aircraft owned by our Chief Executive Officer. In 2003 and 2002, we paid Gulf Coast $0.8 million and $0.2 million, respectively, in connection with charter services in which our Chief Executive Officer’s aircraft were used. The charter services were arranged through arms-length dealings and the rates were market-based.
Note 6-Stock and Other Compensation Plans
At the time of the spin-off all individuals holding outstanding options to acquire Plains Resources common stock were granted an equal number of stock appreciation rights (“SARs”) with respect to our common stock. The exercise price of the SARs was based on the exercise price of the Plains Resources options adjusted for the relationship of the closing price (with dividend) of Plains Resources common stock on the spin-off date ($23.05 per share) less the closing price (on a “when-issued” basis) of our common stock on the spin-off date ($9.10 per share), both as reported on the NYSE, and such closing price of our common stock ($9.10 per share). All recipients of our SARs received the benefit of prior service credit at Plains Resources and have the same amount of vesting as they had under their related Plains Resources stock options and vesting terms remain unchanged. Generally, the SARs have a pro rata vesting period of two to five years and an exercise period of five to ten years. We issued additional SARs in 2003.
SARs are subject to variable accounting treatment. Accordingly, at the end of each quarter, we compare the closing price of our common stock on the last day of the quarter to the exercise price of each SAR. To the extent the closing price exceeds the exercise price of each SAR, we recognize such excess as an accounting charge for the SAR’s deemed vested at the end of the quarter to the extent such excess had not been recognized in previous quarters. If such excess were to be less than the extent to which accounting charges had been recognized in previous quarters, we would recognize the difference as income in the quarter. In 2003 and 2002 we recognized charges of $18.0 million and $3.7 million, respectively, as compensation expense with respect to SARs vested or deemed vested during the periods. In 2003 we made cash payments with respect to SARs exercised in 2003 of $2.1 million.
A summary of the status of our SARs as of December 31, 2003 and 2002 and changes during the years ending on those dates are presented below (shares in thousands):
The following table reflects the SARs outstanding at December 31, 2003 (share amounts in thousands):
Our stock compensation plans also allow grants of restricted stock and restricted stock units. Restricted stock is issued on the grant date but restricted as to transferability. Restricted stock unit awards represent the right to receive common stock when vesting occurs.
At the time of the spin-off we granted awards of 165,000 restricted shares of common stock that vest in three equal annual installments beginning on the first anniversary of the date of grant. During 2003 we granted awards of 420,000 restricted stock units with vesting terms up to three years. We will recognize total compensation expense of $6.1 million ratably over the life of these grants. During 2003 we recognized compensation expense of $2.9 million related to these grants. At December 31, 2003 and 2002 there were 0.5 million and 0.2 million, respectively, outstanding restricted stock shares and units.
As a result of the separation of employment of an executive of the Company in March 2004, in accordance with the terms of the employment agreement between the Company and the executive, the former executive received a cash payment and his SARs and restricted shares of the Company’s common stock vested. In the first quarter of 2004, the Company will recognize a pre-tax $2.9 million charge to earnings in connection with the former executive’s termination of employment.
We also have a 401(k) defined contribution plan whereby we match 100% of an employee’s contribution (subject to certain limitations in the plan). Matching contributions are made 100% in cash. The initial contribution under the plan, $0.1 million, was made for the pay period ended December 31, 2002. In 2003 we made contributions totaling $2.0 million to the 401(k) plan.
Note 7-Income Taxes
Until the date of the spin-off, our taxable income or loss was included in the consolidated income tax returns filed by Plains Resources. Income tax obligations reflected in these financial statements with respect to such returns are based on the tax sharing agreement that provides that income taxes are calculated assuming we filed a separate combined income tax return.
Our deferred income tax assets and liabilities at December 31, 2003 and 2002 consist of the tax effect of income tax carryforwards and differences related to the timing of recognition of certain types of costs as follows (in thousands):
At December 31, 2003, for federal income tax purposes, we had carryforwards of approximately $8.4 million of regular tax net operating losses, $4.8 million of alternative minimum tax credits and $1.2 million of enhanced oil recovery credits. The NOL carryforwards expire in 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 in the accompanying consolidated statements of operations (in thousands):
Under the terms of a tax allocation agreement, we have agreed to indemnify Plains Resources if the spin-off is not tax-free to Plains Resources as a result of various actions taken by us or with respect to our failure to take various actions. In addition, we agreed that, during the three-year period following the spin-off, without the prior written consent of Plains Resources, we will not engage in transactions that could adversely affect the tax treatment of the spin-off unless we obtain a supplemental tax ruling from the IRS or a tax opinion acceptable to Plains Resources of nationally recognized tax counsel to the effect that the proposed transaction would not adversely affect the tax treatment of the spin-off or provide adequate economic security to Plains Resources to ensure we would be able to comply with our obligation under this agreement. We may not be able to control some of the events that could trigger this indemnification obligation.
Note 8-Property Divestments
We periodically evaluate and from time to time elect to sell certain of our producing properties that we consider to be nonstrategic or fully valued. In 2003, we sold our interest in 36 predominantly non-operated and noncore fields in the Permian Basin, the Texas Panhandle, east Texas, the Mid-continent Area, Alabama, Arkansas, Mississippi, North Dakota and New Mexico for aggregate proceeds of approximately $23.2 million. No gains or losses were reflected in net income with respect to these sales.
Note 9-Commitments, Contingencies and Industry Concentration
Commitments and Contingencies
Operating leases. We lease certain real property, equipment and operating facilities under various operating leases. Future noncancellable commitments related to these leases are as follows (in thousands):
Total expenses related to operating leases obligations were $2.2 million in 2003 and less than $0.1 million in each of 2002 and 2001.
Environmental matters. As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state, and local laws and regulations relating to discharge of materials into, and protection of, the environment. Typically when producing oil and gas assets are purchased, one assumes the obligation to plug and abandon wells that are part of such assets. However, in some instances, we have received an indemnity in connection with such purchase. There can be no assurance that we will be able to collect on these indemnities. Often these regulations are more burdensome on older properties that were operated before the regulations came into effect such as some of our properties in California that have operated for over 90 years. We have established policies for continuing compliance with environmental laws and regulations. We also maintain insurance coverage for environmental matters, which we believe is customary in the industry, but we are not fully insured against all environmental risks. 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.
Plugging, Abandonment and Remediation Obligations. Consistent with normal industry practices, substantially all of our oil and 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. Typically, when producing oil and gas assets are purchased the purchaser assumes the obligation to plug and abandon wells that are part of such assets. However, in some instances, we receive an indemnity with respect to those costs.
In connection with the purchase of certain of our onshore California properties, each year we are required to plug and abandon 20% of the then remaining inactive wells (there were 158 inactive wells at December 31, 2003). If we do not meet this commitment, and the requirement is not waived, we must escrow funds to cover the cost of the wells that were not abandoned. To date we have not been required to escrow any funds. In addition, until the end of 2006, we are required to spend at least $600,000 per year (and $300,000 per year from 2007 through 2011) to remediate oil contaminated soil from existing well sites that require remediation.
Other commitments and contingencies. 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 oil and gas properties and the marketing, transportation, terminalling and storage of 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.
We are a defendant in various lawsuits arising in the ordinary course of our business. While the outcome of these lawsuits cannot be predicted with certainty and could have a material adverse effect on our financial position, we do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.
In September 2002, Stocker Resources Inc., or Stocker, our general partner before we converted from a limited partnership to a corporation, filed a declaratory judgment action against Commonwealth Energy Corporation, or Commonwealth, in the Superior Court of Orange County, California relating to the termination of an electric service contract. Stocker was seeking a declaratory judgment that it was entitled to terminate the contract and that Commonwealth had no basis for proceeding against Stocker’s related $1.5 million performance bond. Also in September 2002, Stocker was named a defendant in an action brought by Commonwealth in the Superior Court of Orange County, California for breach of the electric service contract. In January 2004 Plains Resources signed a settlement agreement with Commonwealth. Under the terms of our master separation agreement with Plains
Resources, we indemnified them for damages they might incur as a result of this action. As such, we reimbursed Plains Resources’ settlement amount.
Operating risks and insurance coverage. Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and gas, including well blowouts, cratering, explosions, oil spills, gas or well fluids, fires, pollution and releases of toxic gas, each of which could result in damage to or destruction of oil and gas wells, production facilities or other property, or injury to persons. Our operations in California, including transportation of oil by pipelines within the city and county of Los Angeles, are especially susceptible to damage from earthquakes and involve increased risks of personal injury, property damage and marketing interruptions because of the population density of southern California. Although we maintain insurance coverage considered to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of high premium costs. We maintain coverage for earthquake damages in California but this coverage may not provide for the full effect of damages that could occur and we may be subject to additional liabilities. The occurrence of a significant event that is not fully insured against could have a material adverse effect on our financial position. Our insurance does not cover every potential risk associated with operating our pipelines, including the potential loss of significant revenues. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences.
Industry Concentration
Financial instruments which potentially subject us to concentrations of credit risk consist principally of accounts receivable with respect to our oil and gas operations and derivative instruments related to our hedging activities. Plains All American Pipeline, L.P. (“PAA”), in which Plains Resources held an approximate 22% interest at December 31, 2003, is the exclusive marketer/purchaser for all of our equity oil production in California and Illinois. This concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that PAA may be affected by changes in economic, industry or other conditions. We do not believe the loss of PAA as the exclusive purchaser of our equity production in California and Illinois would have a material adverse affect on our results of operations. We believe PAA could be replaced by other purchasers under contracts with similar terms and conditions. During 2003, 2002 and 2001 no other purchaser accounted for more than 10% of our total revenues.
The contract counterparties for our derivative commodity contracts are all major financial institutions with Standard & Poor’s ratings of A or better. Six of the financial institutions are participating lenders in our credit facility, holding contracts that represent approximately 62% of the fair value of all of our open positions at December 31, 2003.
There are a limited number of alternative methods of transportation for our production. Substantially all of our oil and gas production is transported by pipelines and trucks 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 oil and gas production which could have a negative impact on future results of operations or cash flows.
Note 10-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 judgment 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. Derivative financial instruments included in other assets are stated at fair value. The carrying amounts and fair values of our other financial instruments are as follows (in thousands):
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 is based on quoted market prices based on trades of subordinated debt.
Note 11-Supplemental Cash Flow Information
Cash payments for interest and taxes were (in thousands of dollars):
Cash payments for interest are net of capitalized interest of $3,232 and $1,006 in 2003 and 2002, respectively.
The merger involved non-cash consideration as follows (in thousands of dollars);
Note 12-Oil and natural gas activities
Costs incurred
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).
(1)
In connection with the acquisition of an additional interest in the Point Arguello field, offshore California, in 2002 we assumed certain obligations of the seller. As consideration for receiving the transferred properties and assuming such obligations, we received $2.4 million. In addition, we received $2.7 million as our share of revenues less costs for the period April 1 to July 31, 2002, the period prior to ownership.
(2)
Amounts presented for 2003 do not include the cumulative effect adjustment for the January 1, 2003 adoption of SFAS 143 of $15.9 million.
Amounts presented include capitalized general and administrative expense of $11.0 million, $6.0 million and $6.2 million in 2003, 2002 and 2001, respectively, and capitalized interest expense of $3.2 million, $2.4 million and $3.1 million in 2003, 2002 and 2001, respectively.
Capitalized costs
The following table presents the aggregate capitalized costs subject to amortization relating to our oil and gas acquisition, exploration, exploitation and development activities, and the aggregate related accumulated DD&A (in thousands).
The average DD&A rate per equivalent unit of production was $3.86, $3.17 and $2.70 in 2003, 2002 and 2001, respectively.
Costs not subject to amortization
The following table summarizes the categories of costs comprising the amount of unproved properties not subject to amortization (in thousands).
Unproved property costs not subject to amortization consist of acquisition costs related to unproved areas, exploration costs and capitalized interest. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves established or impairment determined. We will continue to evaluate these properties and costs will be transferred into the amortization base as the undeveloped areas are tested. Our onshore properties and one offshore property consist of mature but underdeveloped crude oil properties that were acquired from major or large independent oil and gas companies. Certain of these fields were discovered from 1906 to 1981, have produced significant volumes since initial discovery, and exhibit complex reservoir and geologic conditions. Due to the nature of the reserves, the ultimate evaluation of the properties will occur over a
period of several years. We expect that 70% of the costs not subject to amortization at December 31, 2003 will be transferred to the amortization base over the next three years and the remainder within the next seven years. The majority of the leases covering the properties are held by production and will not limit the time period for evaluation. Approximately 73%, 2% and 2% of the balance in unproved properties at December 31, 2003, related to additions made in 2003, 2002 and 2001, respectively.
Results of operations for oil and gas producing activities
The results of operations from oil and gas producing activities below exclude non-oil and gas revenues, general and administrative expenses, interest charges, interest income and interest capitalized. Income tax expense was determined by applying the statutory rates to pretax operating results (in thousands).
Supplemental reserve information (unaudited)
The following information summarizes our net proved reserves of oil (including condensate and natural gas liquids) and gas and the present values thereof for the three years ended December 31, 2003. The following reserve information is based upon reports of the independent petroleum consulting firms of Netherland, Sewell & Associates, Inc., and Ryder Scott Company. The estimates are in accordance with SEC regulations.
Management believes the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation principles consistently applied, are 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 oil and 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 oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and 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 oil and 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 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. A significant portion of our reserve base (approximately 81% of year-end 2003 reserve volumes) is comprised of oil properties that are sensitive to crude oil price volatility.
Estimated quantities of 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, 2003 (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):
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 oil and 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. We have entered into various arrangements to fix or limit the prices for a significant portion of our oil and gas production. Arrangements in effect at December 31, 2003 are discussed in Note 3. Such arrangements are not reflected in the reserve reports. The overall average year-end prices used in the reserve reports as of December 31, 2003, 2002 and 2001 were $28.22, $26.91, and $15.31 per barrel of oil, respectively, and $5.53, $4.63, and $2.56 per Mcf of gas, respectively.
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 $2.0 billion, $1.5 billion, and $0.6 billion at December 31, 2003, 2002 and 2001, 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 and state 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 related to oil and gas operations.
The principal sources of changes in the Standardized Measure of the future net cash flows for the three years ended December 31, 2003, are as follows (in thousands):
Note 13-Quarterly Financial Data (Unaudited)
The following table shows summary financial data for 2003 and 2002 (in thousands, except per share data):
Note 14-Consolidating Financial Statements
We and Plains E&P Company are the co-issuers of the 8.75% notes discussed in Note 4. The 8.75% notes are jointly and severally guaranteed on a full and unconditional basis by Arguello Inc., Plains Illinois Inc. and certain immaterial subsidiaries (referred to as “Guarantor Subsidiaries”).
The following financial information presents consolidating financial statements, which include:
•
PXP (the “Issuer”);
•
the guarantor subsidiaries on a combined basis (“Guarantor Subsidiaries”);
•
elimination entries necessary to consolidate the Issuer and Guarantor Subsidiaries; and
•
the company on a consolidated basis.
Plains E&P Company has no material assets or operations; accordingly, Plains E&P Company has been omitted from the Issuer financial information.
PLAINS EXPLORATION & PRODUCTION COMPANY
CONDENSED CONSOLIDATING BALANCE SHEET
DECEMBER 31, 2003
(in thousands)
PLAINS EXPLORATION & PRODUCTION COMPANY
CONDENSED CONSOLIDATING BALANCE SHEET
DECEMBER 31, 2002
(in thousands)
PLAINS EXPLORATION & PRODUCTION COMPANY
CONDENSED CONSOLIDATING STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 2003
(in thousands)
PLAINS EXPLORATION & PRODUCTION COMPANY
CONDENSED CONSOLIDATING STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 2002
(in thousands)
PLAINS EXPLORATION & PRODUCTION COMPANY
CONDENSED CONSOLIDATING STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 2001
(in thousands)
PLAINS EXPLORATION & PRODUCTION COMPANY
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2003
(in thousands)
PLAINS EXPLORATION & PRODUCTION COMPANY
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2002
(in thousands)
PLAINS EXPLORATION & PRODUCTION COMPANY
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2001
(in thousands)
Note 15-Subsequent Event (unaudited)
On February 12, 2004 we announced that we had entered into a definitive agreement to acquire Nuevo Energy Company, or Nuevo, in a stock for stock transaction valued at approximately $945 million, based on our February 11, 2004 closing stock price of $15.89 per share. Under the terms of the definitive agreement, Nuevo stockholders will receive 1.765 shares of our common stock for each share of Nuevo common stock. If completed, we will issue up to 38.8 million shares to Nuevo shareholders and assume $234 million of net debt (as of December 31, 2003) and $115 million of Trust Convertible Preferred Securities.
The transaction is expected to qualify as a tax free reorganization under Section 368(a) and is expected to be tax free to our stockholders and tax free for the stock consideration received by Nuevo stockholders. The Boards of directors of both companies have approved the merger agreement and each has recommended it to their respective stockholders for approval. The transaction will remain subject to stockholder approval from both companies and other customary conditions. Post closing, it is anticipated that our stockholders will own approximately 52% of the combined company and Nuevo stockholders will own approximately 48% of the combined company.
We will account for the transaction as a purchase of Nuevo under purchase accounting rules and we will continue to use the full cost method of accounting for our oil and gas properties.