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Plains Exploration & Production Co – ‘10-K/A’ for 12/31/03

On:  Monday, 6/14/04, at 5:23pm ET   ·   For:  12/31/03   ·   Accession #:  1193125-4-102742   ·   File #:  1-31470

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  As Of                Filer                Filing    For·On·As Docs:Size              Issuer               Agent

 6/14/04  Plains Exploration & Producti… Co 10-K/A     12/31/03    8:1.3M                                   RR Donnelley/FA

Document/Exhibit                   Description                      Pages   Size 

 1: 10-K/A      Amendment to Annual Report                          HTML   1.15M 
 2: EX-23.1     Consent of Pricewaterhousecoopers LLP               HTML      7K 
 3: EX-23.2     Consent of Netherland, Sewell & Associates, Inc.    HTML      8K 
 4: EX-23.3     Consent of Ryder Scott Company                      HTML      9K 
 5: EX-31.1     Certification of Chief Executive Officer            HTML     12K 
 6: EX-31.2     Certification of Chief Financial Officer            HTML     12K 
 7: EX-32.1     Section 1350 Certification of Chief Executive       HTML     10K 
                          Officer                                                
 8: EX-32.2     Section 1350 Certification of Chief Financial       HTML     10K 
                          Officer                                                

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K/A

Amendment

No. 1

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2003

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

Commission file number: 001-31470

PLAINS EXPLORATION & PRODUCTION COMPANY

(Exact name of registrant as specified in its charter)

700 Milam Street, Suite 3100

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)

(832) 239-6000

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act: none

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).    Yes  x    No  ¨

On February 29, 2004, there were approximately 40.4 million shares of the registrant’s Common Stock outstanding. The aggregate market value of the Common Stock held by non-affiliates of the registrant (treating all executive officers and directors of the registrant, for this purpose, as if they may be affiliates of the registrant) was approximately $417 million on June 30, 2003 (based on $10.81 per share, the last sale price of the Common Stock as reported on the New York Stock Exchange on such date).

PLAINS EXPLORATION & PRODUCTION COMPANY

AMENDMENT NO. 1 TO 2003 ANNUAL REPORT ON FORM 10-K/A

Explanatory Note

This Amendment No. 1 to annual report on Form 10-K/A (“Form 10-K/A”) is being filed to amend the Company’s annual report on Form 10-K for the year ended December 31, 2003, which was filed with the SEC on March 12, 2004 (“Original Form 10-K”). Accordingly, pursuant to rule 12b-15 under the Securities Exchange Act of 1934, as amended, this Form 10-K/A contains the complete text of items 6, 7, 7A, 8 and 9A of Part II and item 15 of Part IV, as amended, as well as certain currently dated certifications. Unaffected items have not been repeated in this Amendment No. 1.

In June 2004 we determined that deferred tax assets associated with our current liability for commodity hedging contracts that had historically been classified in long-term deferred income taxes should instead be classified as a current asset in our consolidated balance sheet. Accordingly, we have revised our consolidated balance sheet to reflect this change in classification. The net effect of these revisions was to increase current assets, total assets, long-term deferred income taxes and total liabilities and stockholders’ equity by $21.8 million at December 31, 2003 and by $8.8 million at December 31, 2002. Such revisions had no impact on our consolidated statements of income, cash flows, comprehensive income or changes in stockholders’ equity.

This amendment does not reflect events occurring after the filing of the Original Form 10-K, and does not modify or update the disclosures therein in any way other than as required to reflect the amendments as described above and set forth below.

Table of Contents

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STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K includes forward-looking statements based on our current expectations and projections about future events. Statements that are predictive in nature, that depend upon or refer to future events or conditions, or that include words such as “will”, “would”, “should”, “plans”, “likely”, “expects”, “anticipates”, “intends”, “believes”, “estimates”, “thinks”, “may”, and similar expressions, are forward-looking statements. These statements involve known and unknown risks, uncertainties, and other factors that may cause our actual results and performance to be materially different from any future results or performance expressed or implied by these forward-looking statements. These factors include, among other things:

All forward-looking statements in this report are made as of the date hereof, and you should not place undue certainty on these statements without also considering the risks and uncertainties associated with these statements and our business that are discussed in this report. Moreover, although we believe the expectations reflected in the forward-looking statements are based upon reasonable assumptions, we can give no assurance that we will attain these expectations or that any deviations will not be material. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information. See Items 1 & 2.—“Business and Properties—Risk Factors” and Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Factors That May Affect Future Results” in this report for additional discussions of risks and uncertainties.

AVAILABLE INFORMATION

We file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any document we file at the SEC’s Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the SEC’s Public Reference Room. Our SEC filings are also available to the public at the SEC’s

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web site at www.sec.gov. No information from such web site is incorporated by reference herein. Our web site is www.plainsxp.com. You may also obtain copies of our annual, quarterly and current reports, proxy statements and certain other information filed with the SEC, as well as amendments thereto, free of charge from our web site. These documents are posted to our web site as soon as reasonably practicable after we have filed or furnished these documents with the SEC. We have placed on our website copies of our Corporate Governance Guidelines, charters of our Audit, Organization and Compensation and Nominating and Corporate Governance Committees, and our Policy Concerning Corporate Ethics and Conflicts of Interest. Stockholders may request a printed copy of these governance materials by writing to the Corporate Secretary, Plains Exploration & Production Company, 700 Milam, Suite 3100, Houston, TX 77002.

GLOSSARY OF OIL AND GAS TERMS

The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and this information statement:

API gravity.    A system of classifying oil based on its specific gravity, whereby the greater the gravity, the lighter the oil.

Bbl.    One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcf.    One billion cubic feet of gas.

BOE.    One stock tank barrel equivalent of oil, calculated by converting gas volumes to equivalent oil barrels at a ratio of 6 Mcf to 1 Bbl of oil.

Developed acreage.    The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development well.    A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential.    An adjustment to the price of oil from an established spot market price to reflect differences in the quality and/or location of oil.

Exploratory well.    A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.

Farm-in.    An agreement between a participant who brings a property into the venture and another participant who agrees to spend an agreed amount to explore and develop the property and has no right of reimbursement but may gain a vested interest in the venture. A “farm-in” describes the position of the participant who agrees to spend the agreed-upon sum of money to gain a vested interest in the venture.

Gas.    Natural gas.

Gross acres.    The total acres in which a person or entity has a working interest.

Gross oil and gas wells.    The total wells in which a person or entity owns a working interest.

Infill drilling.    A drilling operation in which one or more development wells is drilled within the proven boundaries of a field.

MBbl.    One thousand barrels of oil or other liquid hydrocarbons.

MBOE.    One thousand BOE.

Mcf.    One thousand cubic feet of gas.

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Midstream.    The portion of the oil and gas industry focused on marketing, gathering, transporting and storing oil.

MMBbl.    One million barrels of oil or other liquid hydrocarbons.

MMBOE.    One million BOE.

MMcf.    One million cubic feet of gas.

Net acres.    Gross acres multiplied by the percentage working interest.

Net oil and gas wells.    Gross wells multiplied by the percentage working interest.

Net production.    Production that is owned, less royalties and production due others.

Net revenue interest.    Our share of petroleum after satisfaction of all royalty and other non-cost-bearing interests.

NYMEX.    New York Mercantile Exchange.

Oil.    Crude oil, condensate and natural gas liquids.

Operator.    The individual or company responsible for the exploration and/or exploitation and/or production of an oil or gas well or lease.

PV-10.    The pre-tax present value, discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying sales prices in effect as of the dates of such estimates and held constant throughout the productive life of the reserves (except for consideration of price changes to the extent provided by contractual arrangements), and deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on current costs and assuming continuation of existing economic conditions).

Proved developed reserves.    Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved reserves.    Per Article 4-10(a)(2) of Regulation S-X, the SEC defines proved oil and gas reserves as the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes: (i) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (ii) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

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Estimates of proved reserves do not include: (i) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (ii) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (iii) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (iv) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved reserve additions.    The sum of additions to proved reserves from extensions, discoveries, improved recovery, acquisitions and revisions of previous estimates.

Proved undeveloped reserves.    Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Reserve life.    A measure of the productive life of an oil and gas property or a group of properties, expressed in years. Reserve life is calculated by dividing proved reserve volumes at year-end by production for that year.

Reserve replacement cost.    The cost per BOE of reserves added during a period calculated by using a fraction, the numerator of which equals the costs incurred for the relevant property acquisition, exploration, exploitation and development and the denominator of which equals changes in proved reserves due to revisions of previous estimates, extensions, discoveries, improved recovery and other additions and purchases of reserves in-place.

Reserve replacement ratio.    The proved reserve additions for the period divided by the production for the period.

Royalty.    An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Standardized measure.    The present value, discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying sales prices in effect as of the dates of such estimates and held constant throughout the productive life of the reserves (except for consideration of price changes to the extent provided by contractual arrangements), and deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on current costs and assuming continuation of existing economic conditions). Future income taxes are 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.

Undeveloped acreage.    Acreage held under lease, permit, contract or option that is not in a spacing unit for a producing well.

Upstream.    The portion of the oil and gas industry focused on acquiring, exploiting, developing, exploring for and producing oil and gas.

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Waterflood.    A secondary recovery operation in which water is injected into the producing formation to maintain reservoir pressure and force oil toward and into the producing wells.

Working interest.    An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

References herein to “Plains Exploration”, “Plains”, “PXP”, the “Company”, “we”, “us” and “our” mean Plains Exploration & Production Company.

6

PART II

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.

Table continued on following page

7

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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.

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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:

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

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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:

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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.

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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.

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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

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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.

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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 $73.0 million. (See Note 2 to the consolidated financial statements). Approximately $33.3 million of the working capital deficit is attributable to the fair value of our commodity derivative instruments (net of related deferred income taxes). 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

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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

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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

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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

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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—Quantitative and Qualitative Disclosures about Market Risks”.

Write-downs under full cost ceiling test rules.    Under the SEC’s full cost accounting rules we review the carrying value of our proved oil and gas properties each quarter. Under these rules, capitalized costs of proved oil and gas properties (net of accumulated depreciation, depletion and amortization, and deferred income taxes) may not exceed a “ceiling” equal to:

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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 and require a write-down if our capitalized costs exceed this “ceiling,” even if prices declined for only a short period of time. 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 change in the near term. If oil and gas prices decline significantly in the future, even if only for a short period of time, 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.

Oil and gas reserves.    Our proved reserve information is based on estimates prepared by outside engineering firms. Estimates prepared by others may be higher or lower than these estimates.

Estimates of proved reserves may be different from the actual quantities of oil and gas recovered because such estimates depend on many assumptions and are based on operating conditions and results at the time the estimate is made. The actual results of drilling and testing, as well as changes in production rates and recovery factors, can vary significantly from those assumed in the preparation of reserve estimates. As a result, such factors have historically, and can in the future, cause significant upward and downward revisions to proved reserve estimates.

You should not assume that PV-10 is the current market value of our estimated proved oil and gas reserves. In accordance with SEC requirements, we base the estimated discounted future net revenues from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.

Historically, we have experienced significant upward and downward revisions to our reserves volumes and values as a result of changes in year-end oil and gas prices and the corresponding adjustment to the projected economic life of such properties. Prices for oil and gas are likely to continue to be volatile, resulting in future downward and upward revisions to our reserve base.

Our rate of recording DD&A is dependent upon our estimate of proved reserves including future development and abandonment costs as well as our level of capital spending. If the estimates of proved reserves decline, the rate at which we record DD&A expense increases, reducing our net income. This decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields. The decline in proved reserve estimates may impact the outcome of the “ceiling” test discussed above. In addition, increases in costs required to develop our reserves would increase the rate at which we record DD&A expense. We are unable to predict changes in future development costs as such costs are dependent on the success of our exploitation and development program, as well as future economic conditions.

Stock appreciation rights.    As part of the spin-off, all outstanding options to acquire Plains Resources common stock at the time of the spin-off were “split” between Plains Resources stock options and stock appreciation rights (SARs) with respect to our common stock.

SARs are subject to variable accounting treatment under U.S. generally accepted accounting principles. As a result, 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 outstanding or unexercised SAR that is vested or for accounting purposes is deemed vested at the end of the quarter. For example, if a SAR is

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scheduled to vest on December 31, for accounting purposes one-fourth of the shares are deemed to vest at the end of each quarter even though no vesting occurs until December 31. To the extent the closing price at the end of each quarter exceeds the exercise price of each SAR, we will recognize such excess as an accounting charge for the SARs deemed vested to the extent such excess has not previously been recognized as expense. If the quarter-end closing price decreases compared to prior periods, we will recognize credits to income, to the extent we have previously recognized expense. These quarterly charges and credits will make our results of operations depend, in part, on fluctuations in the price of our common stock and could have a material adverse effect on our results of operations. We will incur cash expenditures as SARs are exercised, but our outstanding common shares will not increase.

We recognized compensation expense of $18.0 million related to SARs for the year ended December 31, 2003, representing the increase in our stock price and the vesting deemed to have occurred during the year. In 2003 we made cash payments of $2.1 million for SARs that were exercised during the year. As of December 31, 2003, we have approximately 3.9 million SARs outstanding with an average exercise price of $9.25, of which 3.1 million of the SARs were deemed vested.

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 merger, over the fair value of the net assets acquired. In our acquisition of 3TEC, goodwill totaled $147.3 million and represents 12% of our total assets at December 31, 2003.

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.

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

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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

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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 assets ($21.8 million) current liabilities ($55.1 million), other long-term liabilities ($23.7 million) and deferred income tax liability (a tax benefit of $10.3 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.

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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.    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 F-1.

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”)). A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. 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 at the “reasonable assurance” level 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.

In June 2004 we determined that deferred tax assets associated with our current liability for commodity hedging contracts that had historically been classified in long-term deferred income taxes should instead be classified as a current asset in our consolidated balance sheet. We identified this deficiency and we brought it to the attention of our audit committee and auditors promptly. Accordingly, in this Form 10-K/A we revised our consolidated balance sheets at December 31, 2003 and 2002 to reflect the reclassification of deferred tax assets associated with our current liability for commodity hedging contracts. We believe we have addressed this deficiency as we have recently added a Director of Tax position to enhance our ability to comply with all appropriate tax and related accounting issues, inclusive of the period end reporting process around classification of deferred tax assets and liabilities.

There were no significant changes in our internal controls, other than the addition of a Director of Tax position, or in other factors that could significantly affect these controls subsequent to the date of such evaluation.

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PART IV

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 F-1.

(a) (3) Exhibits

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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.

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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.

F-1

Report of Independent Registered Public Accounting Firm

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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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.