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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

FOR ANNUAL AND TRANSITION REPORTS PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

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

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2002

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)

500 Dallas Street, Suite 700

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)

(713) 739-6700

(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 þ    No ¨

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

On March 25, 2003, there were 24,225,075 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 $199,380,000 on March 25, 2003 (based on $8.68 per share, the last sale price of the Common Stock as reported on the New York Stock Exchange on such date). ⁽¹⁾

DOCUMENTS INCORPORATED BY REFERENCE: The information required in Part III of the Annual Report on Form 10-K is incorporated by reference to the registrant’s definitive proxy statement to be filed pursuant to Regulation 14A for the registrant’s 2003 Annual Meeting of Stockholders.

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. ¨

PLAINS EXPLORATION & PRODUCTION COMPANY

2002 ANNUAL REPORT ON FORM 10-K

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 in or implied by these forward-looking statements. These factors include, among other things:

All forward-looking statements in this Annual Report on Form 10-K 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 addressed in this Annual Report on Form 10-K. 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. See Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Factors That May Affect Future Results” for an additional discussion of these 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 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 (under “Investor Information” on 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.

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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 Form 10-K:

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.

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.

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.

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MMBOE.    One million BOE.

MMBtu.     One million British Thermal units. One British thermal unit is the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit.

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

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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.

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 are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. 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.

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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.

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.

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Items 1 and 2.    Business and Properties.

General

We are an independent oil and gas company primarily engaged in the upstream activities of acquiring, exploiting, developing and producing oil and gas in the United States. Our core areas of operation are:

Our strategy is to continue to grow our cash flow from operations and to use this cash flow to increase our proved developed reserves and production, acquire additional underdeveloped oil and gas properties and make other strategic acquisitions. We focus on implementing improved production practices and recovery techniques, and relatively low-risk development drilling. We believe we can continue our strong reserve and production growth through the exploitation and development of our existing inventory of projects relating to our properties. We also intend to be opportunistic in pursuing selective acquisitions of oil or gas properties or exploration projects. We will consider opportunities located in our current core areas of operation as well as projects in other areas in North America that meet our investment criteria.

Corporate Reorganization and Spin-off

Prior to December 18, 2002 we were a wholly owned subsidiary of Plains Resources Inc., or 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 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% 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. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.

Proposed Merger

On February 3, 2003 we announced that we entered into a definitive agreement pursuant to which we will acquire 3TEC Energy Corporation, or 3TEC, for approximately $333.0 million plus the

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assumption of debt, which totaled $99.0 million at December 31, 2002. Under the terms of the merger agreement, 3TEC common stockholders will receive $8.50 of cash and 0.85 of a share of our common stock for each share of 3TEC common stock they own, which equates to a total of $16.97 per 3TEC common share based on the January 31, 2003 closing price of $9.96 per share for our common stock. This exchange ratio is subject to an upward or downward adjustment should the market price of our common stock fall below $7.65 per share or rise above $12.35 per share, respectively. This mechanism is intended to provide that the total value of the consideration received by 3TEC common stockholders at the effective time of the merger will be between $15.00 and $19.00 per share of 3TEC common stock. For this purpose, the market price of our common stock will be the average closing price of our common stock for the 20 consecutive trading days immediately preceding the third trading day prior to closing. In addition, if the market price of our common stock is less than $6.25, we may either (i) terminate the merger agreement or (ii) in lieu of issuing more common stock increase the cash consideration paid per share of 3TEC common stock by the amount our common stock market price is less than $6.25 times the exchange ratio after adjustment.

The merger is expected to qualify as a tax free reorganization under Section 368(a) of the Internal Revenue Code. Accordingly, the merger is expected to be tax free to our stockholders and tax free for the stock portion of the consideration received by 3TEC stockholders. We anticipate funding the cash portion of the merger through a new credit facility.

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 and is expected to close in the second quarter of 2003. Assuming the market price of our common stock is between $7.65 and $12.35, after the merger is completed, 3TEC common stockholders will own approximately 40% of the combined company and our stockholders will own approximately 60% of the combined company.

Oil and Gas Operations

We own a 100% working interest in and operate all of our properties, except for offshore California, where we own a 52.6% working interest and where we are the operator. As a result, we benefit from economies of scale and control the level, timing and allocation of substantially all of our capital expenditures and expenses. Our reserves are generally mature but underdeveloped, have produced significant volumes since initial discovery and have significant estimated remaining reserves

We have a large inventory of projects in our core areas that we believe will support at least five years of exploitation and development activity. Over the last three years, we have achieved a high success rate on these types of projects, drilling a total of 407 development wells with a 99% success rate. In addition, we have completed numerous other production enhancement projects, such as recompletions, workovers and upgrades. The results of these activities over the last three years have been additions to proved reserves, excluding reserves added through acquisition activities, totaling 67.7 MMBOE, or approximately 257% of cumulative net production for this period. Reserve replacement costs, excluding acquisitions, have averaged approximately $3.86 per BOE for the same period.

We actively manage our exposure to commodity price fluctuations by hedging significant portions of our oil production through the use of swaps, collars and purchased puts and calls. The level of our hedging activity depends on our view of market conditions, available hedge prices and our operating strategy. Under our hedging program, we typically hedge approximately 70-75% of our production for the current year, 40-50% of our production for the next year and up to 25% of our production for the following year. For example, assuming estimated fourth quarter 2002 production levels are held constant in subsequent periods, as of March 1, 2003 we had hedged approximately 75% of our oil

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production for 2003, approximately 69% of our oil production for 2004 and approximately 20% of our oil production for 2005.

We had estimated total proved reserves of 253.0 MMBOE as of December 31, 2002, of which 95% was comprised of oil and 54% was proved developed. We have a reserve life of over 27 years and a proved developed reserve life of over 14 years. We believe our long-lived, low production decline reserve base combined with our active hedging strategy should provide us with relatively stable and recurring cash flow. As of December 31, 2002 and based on year-end 2002 spot market prices of $31.20 per Bbl of oil and $4.79 per MMBtu of gas, our reserves had a PV-10 of $1.5 billion and a standardized measure of $883.5 million.

The following table sets forth information with respect to our oil and gas properties as of and for the year ended December 31, 2002 (dollars in millions):

During the three-year period ended December 31, 2002 we drilled 407 development wells, 403 of which were successful. During this period, we incurred aggregate oil and gas acquisition, exploitation, development and exploration costs of $260.8 million, resulting in proved reserve additions of 70.3 MMBOE, at an average reserve replacement cost of $3.71 per BOE, which we believe to be among the lowest of our peer group. During that three-year period approximately 99% of our oil and gas capital expenditures were for acquisition, exploitation and development activities.

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Oil and Gas Reserves

The following table sets forth certain information with respect to our reserves based upon reserve reports prepared by the independent petroleum consulting firms of Netherland, Sewell & Associates, Inc. and Ryder Scott Company in 2002 and 2001, and H.J. Gruy and Associates, Inc., Netherland, Sewell & Associates, Inc. and Ryder Scott Company in 2000. The reserve volumes and values were determined under the method prescribed by the SEC, which requires the application of year-end prices for each year, held constant throughout the projected reserve life.