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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

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).

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 2004 Annual Meeting of Stockholders.

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PLAINS EXPLORATION & PRODUCTION COMPANY.

2003 ANNUAL REPORT ON FORM 10-K

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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.

Items 1 and 2.    Business and Properties.

General

We are an independent oil and gas company primarily engaged in the activities of acquiring, developing, exploiting and producing oil and gas in the United States. We own oil and gas properties in ten states with principal operations in:

Assets in our principal focus areas include mature properties with long-lived reserves and significant development and exploitation opportunities as well as newer properties with development, exploitation and exploration potential. We opportunistically hedge portions of our oil and gas production to manage our exposure to commodity price risk.

Proposed Acquisition of Nuevo Energy Corporation

On February 12, 2004 we announced that we had entered into a definitive agreement to acquire Nuevo Energy Company, or Nuevo, in a stock for stock transaction valued at approximately $945 million, based on our February 11, 2004 closing stock price of $15.89 per share. Under the terms of the definitive agreement, Nuevo stockholders will receive 1.765 shares of our common stock for each share of Nuevo common stock. If completed, we will issue up to 38.8 million shares to Nuevo shareholders and assume $234 million of net debt (as of December 31, 2003) and $115 million of Trust Convertible Preferred Securities.

The transaction is expected to qualify as a tax free reorganization under Section 368(a) and is expected to be tax free to our stockholders and tax free for the stock consideration received by Nuevo stockholders. The Boards of directors of both companies have approved the merger agreement and each has recommended it to their respective stockholders for approval. The transaction 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

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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 compensation obligations. We used the cash contributions to reduce outstanding debt under our revolving credit facility.

In contemplation of the spin-off, under the terms of a Master Separation Agreement between us and Plains Resources, on July 3, 2002 Plains Resources contributed to us 100% of the capital stock of its wholly owned subsidiaries that own oil and gas properties in offshore California and Illinois. As a result, we indirectly own our offshore California and Illinois properties and directly own our onshore California properties. Plains Resources also contributed to us $256.0 million of intercompany payables that we or our subsidiaries owed to it. On July 3, 2002 we and Plains E&P Company, our wholly owned subsidiary that has no material assets and was formed for the sole purpose of being a corporate co-issuer of certain of our indebtedness, issued $200 million of 8.75% Senior Subordinated Notes due 2012, or the 8.75% notes. On July 3, 2002 we also entered into a $300 million revolving credit facility. We distributed the net proceeds of $195.3 million from the 8.75% 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.

Oil and Gas Operations

We own a 100% working interest in and operate all of our onshore California and Illinois Basin properties. On a pro forma basis for the 3TEC merger, we operated approximately 85% of our 2003 production. As a result, we benefit from economies of scale and control the level, timing and allocation of a significant amount of our capital expenditures and expenses. Our onshore California reserves are generally mature but underdeveloped, have produced significant volumes since initial discovery and have significant estimated remaining reserves while our East Texas and Gulf Coast properties generally have higher initial production rates.

We have a large inventory of projects in our core areas that we believe will support at least three years of development and exploitation activity at historical levels of capital investment. In addition, we have exploration projects at various levels of maturity including a recently acquired 102 square mile 3-D seismic survey in South Louisiana where we operate.

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We actively manage our exposure to commodity price fluctuations by hedging significant portions of our 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 25%-40% of our production for the following year. We may hedge to the higher end of the range depending on attractive price levels and expected capital spending requirements. For example, assuming fourth quarter production levels are held constant at 39.0 MBOE per day, as of February 29, 2004 our hedge positions would have resulted in our having hedged approximately 69% of production for 2004, 45% of production for 2005 and 39% of production for 2006.

As of December 31, 2003 we had estimated proved reserves of 281 MMBOE, of which 81% was comprised of oil and 58% was proved developed. We have a reserve life of over 19 years and a proved developed reserve life of over 11 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, 2003 and based on year-end 2003 spot market prices of $32.52 per Bbl of oil and $5.97 per MMBtu of gas, our reserves had a PV-10 of $2.0 billion and a standardized measure of $1.3 billion.

The following table sets forth information with respect to our oil and gas properties as of and for the year ended December 31, 2003 (dollars in millions):

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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. 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.

There are numerous uncertainties inherent in estimating quantities and values of proved reserves, and in projecting future rates of production and timing of development expenditures. Many of the factors that impact these estimates are beyond our control. Reservoir engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. Because all reserve estimates

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are to some degree speculative, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures, and future oil and gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the PV-10 shown above represents estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties.

In accordance with SEC guidelines, the reserve engineers’ estimates of future net revenues from our properties, and the present value of the properties, are made using oil and gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where the guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations but excluding the effect of any hedges we have in place. Historically, the prices for oil and gas have been volatile and are likely to continue to be volatile in the future.

Since December 31, 2002 we have not filed any estimates of total net proved oil or gas reserves with any federal authority or agency other than the SEC.

Exploitation, Development and Exploration

Exploitation strategy.    We implement our exploitation plan with respect to our properties by:

After we acquire a property, we may also seek to increase our interest in the property by acquiring nearby acreage, pursuing farm-in drilling arrangements and purchasing minority interests in the property.

Exploration strategy.    We implement our exploitation plan with respect to our properties by:

Description of Properties

Los Angeles and San Joaquin Basins in California

LA Basin

In 1992 we acquired substantially all of our producing oil properties in the LA Basin. These interests included the Inglewood and Inglewood satellite fields. Following the initial acquisition, we expanded our holdings by acquiring all of ChevronTexaco’s interest in their Inglewood Vickers lease, which further consolidated our holdings in this field. We essentially hold a 100% working interest in the LA Basin properties and operate approximately 536 production and 208 waterflood injection wells in the fields.

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The LA Basin properties consist of oil producing reservoirs discovered between 1924 and 1966. Since 1992 we have drilled many production and injection wells, returned previously marginal wells to economic production, optimized pre-existing waterflood operations, initiated new waterfloods, optimized and installed innovative artificial lift systems, increased the capacity and efficiency of water and gas-handling facilities, upgraded tank batteries and facilities to maintain regulatory compliance, reduced unit production expenses and improved marketing margins. Additionally, we continuously update and execute new technical studies to identify more investment opportunities on these properties.

Seismic technology is being utilized in 2004 to further evaluate the unproved reserves in our LA Basin properties and enhance development of proved undeveloped reserves: conventional 3-D at the Inglewood field and innovative, passive seismic at one of the Inglewood satellite fields. Interpretation of the Inglewood 3-D data was initiated in 2003, and will continue in 2004. Drilling based on the results will take place in 2004 and beyond. This is the first application of 3-D seismic technology for exploitation of an onshore LA Basin oil field.

In March 1997 we expanded our operations in the LA Basin by acquiring ChevronTexaco’s interest in the Montebello field, which included a 100% working interest (99.2% net revenue interest) in 55 producing oil wells and related facilities and ownership of approximately 480 acres of surface fee land. A 2-D seismic line was completed in 2002 and in 2004 we expect to evaluate additional seismic and technical studies that may lead to additional seismic iniatives potentially including 3-D seismic or passive seismic data acquisition. The potential value of our real estate holdings at Montebello will be evaluated in what may be a multi-year process beginning in 2004.

In 2003 we spent $34.3 million on capital projects in the LA Basin. We drilled 15 production wells and 10 injection wells, performed several recompletions, oil fracture and acid-stimulations, and completed a 21.5 square mile 3-D seismic survey over the Inglewood oilfield and contiguous areas. In 2004 we will drill additional wells, workover other wells, stimulate and convert several wells to waterflood injectors, execute various technical studies including reservoir simulation, and complete a 3-D geologic model of Inglewood incorporating seismic interpretation, and upgrade facilities to increase capacities and efficiencies. Several of the drilled wells are designed to produce deeper reservoirs at Inglewood that have been extensively studied and are under exploited, potentially holding significant reserves on our leasehold. Our net average daily production from these properties was 14.4 MBOE per day in 2003.

San Joaquin Basin

In 1998 we acquired the Mt. Poso field from Aera Energy LLC. The Mt. Poso field is located near Bakersfield, California, in Kern County. Since acquisition, we have undertaken an aggressive drilling program targeting the Pyramid Hill formation, completing a 107-well drilling program in 2000-2001. In 2002, we completed the installation of electrical generation facilities. In 2003 capital investment was $10.2 million as 96 new wells were drilled and successfully fracture-stimulated. Our net average daily production from this field was 1.6 MBOE during 2003. The Mt. Poso oilfield is being exposed to the marketplace for potential divestment in 2004.

Other Onshore California

In November 1997 we acquired a 100% working interest (94% net revenue interest) in the Arroyo Grande field located in San Luis Obispo County, California, from subsidiaries of Shell Oil Company. We also acquired surface and related development rights to approximately 1,047 acres (net to our interest) included in the 1,500-acre producing unit. The field is primarily under continuous steam injection and in 2003 our net production from the field averaged 1.7 MBOE per day. Since acquiring

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this property, we have drilled additional wells to downsize the injection patterns in the currently developed area from five acres to one and a quarter acres to accelerate recoveries, and realigned steam injection within these areas to increase the efficiency of the recovery process. In 2003 we spent $5.5 million, drilled 14 producing wells and 4 steam injection wells, and installed a cogeneration facility rated to produce approximately 70% of current electrical demand in order to reduce electricity costs and provide additional steam.

Santa Maria Basin Offshore California

Point Arguello.    In 1999 and 2002 we acquired separate 26.3% working interests in the Point Arguello unit and the various partnerships owning the related transportation, processing and marketing infrastructure. We are the operator for the Point Arguello unit, which consists of three offshore platforms. The sellers of those interests retained responsibility for certain abandonment costs, including: (1) removing, dismantling and disposing of the existing offshore platforms; (2) removing and disposing of all existing pipelines; and (3) removing, dismantling, disposing and remediating all existing onshore facilities. We assumed the sellers’ 52.6% share of all other abandonment costs, primarily well-bore abandonments and conductor removals.

In 2003 we spent $8.2 million on exploitation capital projects, which included drilling two development wells and converting two wells to electric submersible lift systems. In 2004 we expect to continue with our successful workover and high volume lift programs in the unit. In January 2003 our net average daily oil production for the unit was 6.2 MBOE and ended the year at 5.4 MBOE per day for December. Our net average daily oil production for the unit for the year 2003 was 5.7 MBOE

P-0451 E/2 Development.    We have applied for and received all the appropriate permits or modifications to existing permits from federal, state, and local agencies to allow for drilling into the east half of offshore lease P-0451 or E/2 P-0451. The West half of lease P-0451 has already been developed as part of the Point Arguello unit. In 1983-1984 five exploratory wells were drilled into the P-0451 and adjacent P-0452 leases. These wells tested at rates of 3,500, 1,629, 1,100, 604, and 120 barrels of oil per day, respectively, from an oil accumulation considered separate from the Point Arguello field. Based on geologic and geophysical interpretations, we believe approximately 60 percent of that accumulation underlies the E/2 P-0451. We are the operator of P-0451 and have agreements in place between the P-0451 owners and the Point Arguello unit owners that will allow us to participate with at least a 52.6% working interest in the development of the P-0451 E/2 lease. We are now upgrading and mobilizing a rig which will be capable of developing this reservoir by means of extended reach wells drilled from two of the three Point Arguello unit platforms. It is anticipated the drilling will commence in the first half of 2004. While there can be no assurance that drilling will recover economic quantities of oil and gas from the E/2 P-0451, the earlier exploration work indicates a potentially economically viable reservoir.

Gulf Coast Basin Onshore and Offshore Louisiana

We are expanding along the Gulf Coast of Louisiana from the established base of proven reserves and undeveloped acreage acquired in the 2003 3TEC merger. We have entered into additional joint ventures which, as operator, will allow us to continue our expansion in our core areas. In 2003 we spent $37.3 million on exploration and development projects (all subsequent to the 3TEC merger). Our net average daily oil and gas production for this area was 1.2 MBbls of oil per day and 27.2 MMcf of gas per day in December 2003.

State Waters.    We have multiple drilling projects in Breton Sound, Main Pass and Chandeleur Sound (Breton Sound Area or BSA). During 2001-2002, 3TEC participated in six exploratory wells in Louisiana state waters, of which five were gas discoveries. In 2003 an additional eight exploratory

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wells were drilled in the Breton/Chandeleur Sound areas. Seven were successful. We are continuing our work in the area to drill additional identified prospects. To complement and extend our success in the Breton Sound Area, we acquired a 56.25% interest in 32 new prospects we will operate in an area we refer to as Breton Sound Extension or “BSE”. Drilling in BSE began in November 2003 with three successful wells and no dry holes drilled by year-end. Additionally, we acquired a 37.5% interest in an ongoing 178 square mile 3-D seismic acquisition program to the west of BSA. We refer to this new 178 square mile area as Breton Sound Extension-West or BSE-W. To further build on our activities in this area we acquired previously shot 3-D seismic data in an approximately 79 square mile area east of our original BSA activity area. We refer to this area as Breton Sound Extension East or BSE-E. PXP will operate in this area with a 75% interest. The 3-D data will be reprocessed to assist in the identification and validation of prospect locations.

South Louisiana.    We are building an inventory of prospects based on our 102 square miles of new 3-D seismic data in the Garden City area. PXP operates this area with a 66.7% interest.

East Texas Basin in East Texas and North Louisiana

As a result of the 3TEC merger we acquired interests included in the Rosewood, White Oak/Glenwood, Beckville, Carthage, East Henderson and Oak Hill fields in east Texas. The predominant producing formation is the Cotton Valley Sand gas reservoir with indicated additional pay in the shallower Travis Peak and Pettit formations. There are many proven undeveloped Cotton Valley drilling locations under regulatory field rules that now permit wells to be drilled on 80 acre spacing as opposed to 160 acre or larger spacing. At year-end 2003 we had 142 identified proved undeveloped locations in this area. During 2003 we or our predecessor 3TEC drilled nine development wells and participated in 36 wells drilled by others. All wells encountered productive intervals except one which was abandoned for mechanical reasons above the target interval. In 2003 we spent $16.3 million on exploitation and development projects on these properties (all subsequent to the 3TEC merger). Our net average daily oil and gas production for this area was 0.5 MBbls of oil per day and 38.2 MMcf of gas per day in December 2003.

White Oak/Glenwood Fields.    In connection with the 3TEC merger, we acquired an interest in 247 producing wells in the fields. Our working interest varies from well to well and ranges from 3% to 39%.

Beckville Field.    We are the operator of the Beckville field with a working interest that varies from well to well and ranges from 48% to 100%. In December 2003 we operated 35 producing wells in this field.

We have a non-exclusive seismic license to access 1,465 square miles of 3D seismic data within the area encompassed within Texas and Louisiana. We also have a joint venture with another company whereby collectively we will evaluate 374 square miles of this data located in south Texas for the purposes of generating exploration prospects.

Other

Illinois Basin.    In 2003 our production from these properties averaged 2.3 MBOE of oil per day. We have an agreement to sell these properties via the sale of the stock of our Illinois subsidiary with an expected closing in mid-March 2004.

Property Divestments.    The Company periodically evaluates and from time to time has elected to sell certain of its mature producing properties that it considers to be nonstrategic or fully valued. Such sales enable the Company to focus on its core properties, maintain financial flexibility, reduce overhead and redeploy the proceeds therefrom to activities that the Company believes potentially have a higher financial return. In 2003, we sold our interest in 36 predominantly non-operated and noncore

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fields in the Permian Basin, the Texas Panhandle, east Texas, the Mid-continent Area, Alabama, Arkansas, Mississippi, North Dakota and New Mexico for aggregate proceeds of approximately $23 million. Production from these fields was approximately 800 net equivalent barrels per day and proved reserves were 3.6 MMBOE.

Acquisition, Exploration, Exploitation and Development Expenditures

The following table summarizes the costs incurred during the last three years for our acquisition, exploration exploitation and development activities.

Exploitation and development costs include expenditures of $30.2 million in 2003, $27.3 million in 2002 and $58.5 million in 2001 related to the development of proved undeveloped reserves included in our proved oil and gas reserves at the beginning of each year. Exploitation and development costs include capital costs required to maintain our proved developed producing reserves. Amounts presented do not include the cumulative effect adjustment for the January 1, 2003 adoption of SFAS 143 of $15.9 million.

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Production and Sales

The following table presents information with respect to oil and gas production attributable to our properties, the revenues we derived from the sale of this production, average sales prices we realized and our average production expenses during the years ended December 31, 2003, 2002 and 2001.

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Product Markets and Major Customers

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 production and the levels of our production are subject to wide fluctuations and depend on numerous factors beyond our control, including seasonality, economic conditions, foreign imports, political conditions in other oil-producing and gas-producing countries, the actions of OPEC, and domestic government regulation, legislation and policies. Decreases in oil and gas prices 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 to commodity price risks, we use various derivative instruments to hedge our exposure to price fluctuations on oil and gas sales. Our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. However, ceiling prices in our hedges may cause us to receive less revenue on the hedged volumes than we would receive in the absence of hedges.

Deregulation of gas prices has increased competition and volatility of gas prices. Prices received for our gas are subject to seasonal variations and other fluctuations. All of our gas production is currently sold under various arrangements at spot indexed prices.

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 decreases in a significant portion of our oil and gas production.

Pursuant to an oil marketing agreement, PAA is the exclusive purchaser of all of our equity oil production from properties owned prior to the 3TEC merger. The marketing agreement provides that PAA will purchase for resale at market prices all of our equity oil production from properties owned prior to the merger. We pay PAA a marketing and administration fee and reimburse PAA for its reasonable expenses incurred in transporting or exchanging our oil. We have agreed to renegotiate the marketing and administration fee in good faith every three years. Under the marketing agreement, PAA has also agreed to, upon our request and reimbursement for its reasonable expenses, market certain of our gas and gas liquids and negotiate our gas purchase agreements. If we were to lose PAA as the exclusive purchaser of our equity production, we believe PAA could be replaced by other purchasers under contracts with similar terms and conditions. However, PAA’s role as the exclusive purchaser for all of our equity oil production does have 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. During 2003, 2002 and 2001 no other purchaser accounted for more than 10% of our total revenues.

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Productive Wells and Acreage

As of December 31, 2003 we had working interests in 2,188 gross (2,170 net) active producing oil wells and 767 gross (331 net) active producing gas wells. The following table sets forth information with respect to our developed and undeveloped acreage as of December 31, 2003.

Drilling Activities

Information with regard to our drilling activities during the years ended December 31, 2003, 2002 and 2001 is set forth below:

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Real Estate

We currently own surface and mineral rights in the following tracts of real property, portions of which are used in our oil and gas operations:

In the course of our business, certain of our properties may be subject to easements or other incidental property rights and legal requirements that may affect the use and enjoyment of our property. For instance, 183 of our acres in the Montebello field have been designated as California Coastal Sage Scrub.

Title to Properties

Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. We do not believe that any of these burdens materially interfere with our use of the properties in the operation of our business.

We believe that we have generally satisfactory title to or rights in all of our producing properties. As is customary in the oil and gas industry, we make minimal investigation of title at the time we acquire undeveloped properties. We make title investigations and receive title opinions of local counsel only before we commence drilling operations. We believe that we have satisfactory title to all of our other assets. Although title to our properties is subject to encumbrances in certain cases, we believe that none of these burdens will materially detract from the value of our properties or from our interest therein or will materially interfere with our use in the operation of our business.

Competition

Our competitors include major integrated oil and gas companies and numerous independent oil and gas companies, individuals and drilling and income programs. Many of our larger competitors possess and employ financial and personnel resources substantially greater than ours. These competitors are able to pay more for productive oil and gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and gas industry.

Regulation

Our operations are subject to extensive regulations. Many federal, state and local departments and agencies are authorized by statute to issue, and have issued, laws and regulations binding on the oil and gas industry and its individual participants. The failure to comply with these rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability. However, we do not

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believe that we are affected in a significantly different manner by these laws and regulations than are our competitors. Due to the myriad complex federal, state and local regulations that may affect us directly or indirectly, you should not rely on the following discussion of certain laws and regulations as an exhaustive review of all regulatory considerations affecting our operations.

OSHA.    We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, or OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard, the United States Environmental Protection Agency community-right-to know regulations, and similar state statutes require that we maintain certain information about hazardous materials used or produced in our operations and that we provide this information to our employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances.

MMS.    The Minerals Management Service, or MMS, has broad authority to regulate our oil and gas operations on offshore leases in federal waters. It must approve and grant permits in connection with our drilling and development plans. Additionally, the MMS has promulgated regulations requiring offshore production facilities to meet stringent engineering and construction specifications restricting the flaring or venting of gas, governing the plugging and abandonment of wells and controlling the removal of production facilities. Under certain circumstances, the MMS may suspend or terminate any of our operations on federal leases, as discussed in “Risk Factors—Governmental agencies and other bodies, including those in California, might impose regulations that increase our costs and may terminate or suspend our operations,” and has proposed regulations that would permit it to expel unsafe operators from offshore operations. The MMS has also established rules governing the calculation of royalties and the valuation of oil produced from federal offshore leases and regulations regarding costs for gas transportation. Delays in the approval of plans and issuance of permits by the MMS because of staffing, economic, environmental or other reasons could adversely affect our operations.

Regulation of production.    Oil and gas production is regulated under a wide range of federal and state statutes, rules, orders and regulations. State and federal statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. The states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the regulation of the spacing, plugging and abandonment of wells. Many states also restrict production to the market demand for oil and gas, and several states have indicated interest in revising applicable regulations. These regulations limit the amount of oil and gas we can produce from our wells and limit the number of wells or the locations at which we can drill. Also, each state generally imposes an ad valorem, production or severance tax with respect to production and sale of oil, gas and natural gas liquids within its jurisdiction.

Pipeline regulation.    We have pipelines to deliver our production to sales points. Our pipelines are subject to regulation by the United States Department of Transportation with respect to the design, installation, testing, construction, operation, replacement, and management of pipeline facilities. In addition, we must permit access to and copying of records, and must make certain reports and provide information, as required by the Secretary of Transportation. The states in which we have pipelines have comparable regulations. Some of our pipelines related to the Point Arguello unit are also subject to regulation by the Federal Energy Regulatory Commission, or FERC. We believe that our pipeline operations are in substantial compliance with applicable requirements.

Sale of gas.    The FERC regulates interstate gas pipeline transportation rates and service conditions. Although the FERC does not regulate gas producers such as us, the agency’s actions are

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intended to foster increased competition within all phases of the gas industry. To date, the FERC’s pro-competition policies have not materially affected our business or operations. It is unclear what impact, if any, future rules or increased competition within the gas industry will have on our gas sales efforts.

The FERC, the United States Congress or state regulatory agencies may consider additional proposals or proceedings that might affect the gas industry. We cannot predict when or if these proposals will become effective or any effect they may have on our operations. We do not believe, however, that any of these proposals will affect us any differently than other gas producers with which we compete.

Environmental.    Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to safety, health and environmental protection, including the generation, storage, handling, emission and transportation of materials and the discharge of materials into the environment. Other statutes that provide protection to animal and plant species and which may apply to our operations include, but are not necessarily limited to, the Marine Mammal Protection Act, the Marine Protection, Research and Sanctuaries Act, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities, limit or prohibit construction, drilling and other activities on certain lands lying within wilderness or wetlands and other protected areas; and impose substantial liabilities for pollution resulting from our operations.

As with our industry generally, our compliance with existing and anticipated laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, upgrade and close equipment and facilities. Although these regulations affect our capital expenditures and earnings, we believe that they do not affect our competitive position because our competitors that comply with such laws and regulations are similarly affected. Environmental laws and regulations have historically been subject to change, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. If a person violates these environmental laws and regulations and any related permits, they may be subject to significant administrative, civil and criminal penalties, injunctions and construction bans or delays. If we were to discharge hydrocarbons or hazardous substances into the environment, we could, to the extent the event is not insured, incur substantial expense, including both the cost to comply with applicable laws and regulations and claims made by neighboring landowners and other third parties for personal injury and property damage.

Permits.    Our operations are subject to various federal, state and local regulations that include requiring permits for the drilling of wells, maintaining bonding and insurance requirements to drill, operate, plug and abandon, and restore the surface associated with our wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandonment of wells, the disposal of fluids and solids used in connection with our operations and air emissions associated with our operations. Also, we have permits from the city and county of Los Angeles, California, the city of Culver City, California, the county of Kern, California, and the county of Santa Barbara, California to operate crude oil, natural gas and related pipelines and equipment that run within the boundaries of these governmental entities. The permits required for various aspects of our operations are subject to revocation, modification and renewal by issuing authorities.

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

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non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. 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 receive an indemnity with respect to those costs.

Although we obtained environmental studies on our properties in California and we believe that such properties have been operated in accordance with standard oil field practices, certain of the fields have been in operation for over 90 years, and current or future local, state and federal environmental laws and regulations may require substantial expenditures to comply with such rules and regulations. In connection with the purchase of certain of our onshore California properties, we received a limited indemnity for certain conditions if they violate applicable local, state and federal environmental laws and regulations in effect on the date of such agreement. We believe that we do not have any material obligations for operations conducted prior to our acquisition of these properties, other than our obligation to plug existing wells and those normally associated with customary oil field operations of similarly situated properties. Current or future local, state or federal rules and regulations may require us to spend material amounts to comply with such rules and regulations, and there can be no assurance that any portion of such amounts will be recoverable under the indemnity.

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 2005, we are required to spend at least $600,000 per year (and $300,000 per year from 2006 through 2010) to remediate oil contaminated soil from existing well sites that require remediation.

Spin-off Agreements

In connection with the spin-off we entered into certain agreements with Plains Resources, including a master separation agreement; an intellectual property agreement; the Plains Exploration & Production transition services agreement; the Plains Resources transition services agreement; and a technical services agreement. For the year ended December 31, 2003, Plains Resources billed us $0.1 million for services provided to us under these agreements and we billed Plains Resources $0.5 million for services we provided under these agreements.

The master separation agreement provides that for a period of three years, (1) Plains Resources and its subsidiaries will be prohibited from engaging in or acquiring any business engaged in any of the “upstream” activities of acquiring, exploiting, developing, exploring for and producing oil and gas in any state in the United States (except Florida), and (2) we will be prohibited from engaging in any of the “midstream” activities of marketing, gathering, transporting, terminalling and storing oil and gas (except to the extent any such activities are ancillary to, or in support of, any of our upstream activities).

The technical services agreement provides that we will provide services with respect to the operations of Plains Resources “upstream” subsidiary, Calumet Florida Inc. until (1) Calumet is no longer a subsidiary of Plains Resources, (2) Calumet transfers substantially all of its assets to a person that is not a subsidiary of Plains Resources, (3) the third anniversary of the date of the agreement or (4) when all the services are terminated as provided in the agreement. Plains Resources may terminate the agreement as to some or all of the services at any time by giving us at least 90 days’ written notice.

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Employees

As of February 29, 2004 we had 424 full-time employees, 213 of whom were field personnel involved in oil and gas producing activities. We believe our relationship with our employees is good. None of our employees is represented by a labor union.

Risk Factors

You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock.

Our levels of indebtedness may limit our financial and operating flexibility.

We have a substantial amount of debt and the ability to incur substantially more debt. We have outstanding a total of $275.0 million of 8.75% senior subordinated notes due in 2012 which are supported by guarantees of our subsidiaries. In addition, we have a $500.0 million revolving credit facility, which is collateralized by a pledge of the equity of our subsidiaries and substantially all of our other assets and supported by guarantees of our subsidiaries. At February 29, 2004 we had $212.0 million outstanding under this credit facility. We will incur substantial additional indebtedness in connection with the Nuevo acquisition.

We have been assigned a Ba3 senior implied rating and our 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 Ratings Group. All of these ratings are below investment grade. As a result, at times we may have difficulty accessing capital markets or raising capital on favorable terms as we will incur higher borrowing costs than our competitors that have higher ratings. Therefore, our financial results may be negatively affected by our inability to raise capital or the cost of such capital as a result of our credit ratings.

We and all of our restricted subsidiaries must comply with various covenants contained in our revolving credit facility, the indenture related to our senior subordinated notes and any of our future debt arrangements which, among other things, limit the ability of us and those subsidiaries to:

Our substantial debt could have important consequences to you. For example, it could:

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In addition, if we fail to comply with the terms of any of our debt, our lenders will have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. Realization of any of these factors could adversely affect our financial condition.

Plains will incur significant charges and expenses as a result of the Nuevo acquisition which will reduce the amount of capital available to fund its operations.

Plains and Nuevo expect to incur approximately $32 million of costs related to the merger. These expenses will include investment banking, bank commitment, legal, accounting and reserve engineering fees, printing costs, transition costs, severance payments to Nuevo management and other related charges. We may also incur unanticipated costs in the acquisition. As a result, we will have less capital available to fund its exploitation, exploration and development activities.

Our results of operations could be adversely affected as a result of goodwill impairments.

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.

Volatile oil and gas prices could adversely affect our financial condition and results of operations.

Our success is largely dependent on oil and gas prices, which are extremely volatile. Any substantial or extended decline in the price of oil and gas below current levels will have a material adverse effect on our business operations and future revenues. Moreover, oil and gas prices depend on factors we cannot control, such as:

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With respect to our business, prices of oil and gas will affect:

Any prolonged, substantial reduction in the demand for oil and gas, or distribution problems in meeting this demand, could adversely affect our business.

Our success is materially dependent upon the demand for oil and gas. The availability of a ready market for our oil and gas production depends on a number of factors beyond our control, including the demand for and supply of oil and gas, the availability of alternative energy sources, the proximity of reserves to, and the capacity of, oil and gas gathering systems, pipelines or trucking and terminal facilities. We may also have to shut-in some of our wells temporarily due to a lack of market or adverse weather conditions including hurricanes. If the demand for oil and gas diminishes, our financial results would be negatively impacted.

In addition, there are limitations related to the 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, any of which could have a negative impact on our results of operation and cash flows.

The United States’ activities in Iraq, recent terrorist activities and the potential for other global events could adversely affect our business.

The United States’ activities in Iraq and recent terrorist attacks of unprecedented scope have caused instability in the world financial markets and may generate global economic instability. The continued threat of terrorism and the impact of military or other action have led to and will likely lead to increased volatility in prices for oil and gas and could affect the markets for our operations. Further, the United States government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. As a result of such a terrorist attack or of terrorist activities in general, the ability to obtain insurance coverages and other coverages and endorsements at prices that we consider reasonable may not be available. These developments have subjected our operations to increased risk and, depending on the ultimate magnitude, could have a material adverse affect on our business.

Our oil production in California and Illinois is dedicated to a single customer and, as a result, our credit exposure to that customer is significant.

We have entered into an oil marketing agreement with Plains All American Pipeline, L.P., or PAA, under which PAA is the exclusive purchaser of all of our net oil production in California. We generally do not require letters of credit or other collateral from PAA to support our trade receivables. Accordingly, a material adverse change in PAA’s financial condition could adversely impact our ability to collect our receivables from PAA and thereby affect our financial condition.

If we are unable to replace the reserves that we have produced, our reserves and revenues will decline.

Our future success depends on our ability to find, develop and acquire additional oil and gas reserves that are economically recoverable which, in itself, is dependent on oil and gas prices. Without

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continued successful exploitation, acquisition or exploration activities, our reserves and revenues will decline as a result of our current reserves being depleted by production. We may not be able to find or acquire additional reserves at acceptable costs.

We may not be successful in acquiring, exploiting, developing or exploring for oil and gas properties.

The successful acquisition, exploitation or development of, or exploration for, oil and gas properties requires an assessment of recoverable reserves, future oil and gas prices and operating costs, potential environmental and other liabilities, and other factors. These assessments are necessarily inexact. As a result, we may not recover the purchase price of a property from the sale of production from the property, or may not recognize an acceptable return from properties we do acquire. In addition, our exploitation and development and exploration operations may not result in any increases in reserves. Our’ operations may be curtailed, delayed or canceled as a result of:

In addition, exploitation and development costs may greatly exceed initial estimates. In that case, we would be required to make unanticipated expenditures of additional funds to develop these projects, which could materially adversely affect our business, financial condition and results of operations.

Furthermore, exploration for oil and gas, particularly offshore, has inherent and historically higher risk than exploitation and development activities. Future reserve increases and production may be dependent on our success in our exploration efforts, which may be unsuccessful.

Estimates of oil and gas reserves depend on many assumptions that may be inaccurate. Any material inaccuracies could adversely affect the quantity and value of our oil and gas reserves.

The proved oil and gas reserve information included in this document represents only estimates. These estimates are based on reports prepared by independent petroleum engineers. The estimates were calculated using oil and gas prices in effect on the date indicated in the reports. Any significant price changes will have a material effect on the quantity and present value of our reserves.

Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including:

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Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating reserves:

Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. Actual production, revenues and expenditures with respect to reserves will vary from estimates and the variances may be material.

The discounted future net revenues included in this document should not be considered as the market value of the reserves attributable to our properties. As required by the SEC, the estimated discounted future net revenues from proved reserves are generally based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net revenues will also be affected by factors such as:

In addition, the 10% discount factor, which the SEC requires to be used to calculate discounted future net revenues for reporting purposes, is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and gas industry in general.

The geographic concentration and lack of marketable characteristics of our oil reserves may have a greater effect on our ability to sell our oil compared to other companies.

A substantial portion of our oil and gas reserves are located in California. Because our reserves are not as diversified geographically as many of our competitors, our business is more subject to local conditions than other, more diversified companies. Any regional events, including price fluctuations, natural disasters, and restrictive regulations, that increase costs, reduce availability of equipment or supplies, reduce demand or limit our production may impact our operations more than if our reserves were more geographically diversified.

Our California oil production averages 23 degrees API gravity, which is heavier than premium grade light oil. Due to the processes required to refine this type of oil and the transportation requirements, it is difficult to market our oil outside California. Additionally, the margin (sales price minus production costs) on heavy oil sales is generally less than that of lighter oil due to price differentials, and the effect of material price decreases will more adversely affect the profitability of heavy oil production compared with lighter oil grades.

Operating hazards, natural disasters or other interruptions of our operations could result in potential liabilities, which may not be fully covered by our insurance.

The oil and gas business involves certain operating hazards such as:

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In addition, our operations in California are especially susceptible to damage from natural disasters such as earthquakes, mudslides and fires. Any of these operating hazards could cause serious injuries, fatalities, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages, or property damage, which could expose us to liabilities. The payment of any of these liabilities could reduce, or even eliminate, the funds available for exploration, development, and acquisition, or could result in a loss of our properties.

Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities. The insurance market in general and the energy insurance market in particular have been difficult markets over the past several years. As a result, we do not believe that insurance coverage for the full potential liability, especially environmental liability, is currently available at reasonable cost. If we incur substantial liability and the damages are not covered by insurance or are in excess of policy limits, or if we incur liability at a time when we are not able to obtain liability insurance, then our business, results of operations and financial condition could be materially adversely affected.

Our offshore operations are subject to substantial regulations and risks, which could adversely affect our ability to operate and our financial results.

We conduct operations offshore California and Louisiana. Our offshore activities are subject to more extensive governmental regulation than our other oil and gas activities. In addition, we are vulnerable to the risks associated with operating offshore, including risks relating to:

If we experience any of these events, we may incur substantial liabilities, which could adversely affect our operations and financial results.

Governmental agencies and other bodies, including those in California, might impose regulations that increase our costs and may terminate or suspend our operations.

Our business is subject to federal, state and local laws and regulations as interpreted by governmental agencies and other bodies, including those in California, vested with much authority relating to the exploration for, and the development, production and transportation of, oil and gas, as well as environmental and safety matters. Existing laws and regulations could be changed, and any changes could increase costs of compliance and costs of operating drilling equipment or significantly limit drilling activity.

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Under certain circumstances, the United States Minerals Management Service, or MMS, may require that our operations on federal leases be suspended or terminated. These circumstances include our failure to pay royalties or our failure to comply with safety and environmental regulations. The requirements imposed by these laws and regulations are frequently changed and subject to new interpretations.

Environmental liabilities could adversely affect our financial condition.

The oil and gas business is subject to environmental hazards, such as oil spills, gas leaks and ruptures and discharges of petroleum products and hazardous substances, and historic disposal activities. These environmental hazards could expose us to material liabilities for property damages, personal injuries or other environmental harm, including costs of investigating and remediating contaminated properties. In addition, we also may be liable for environmental damages caused by the previous owners or operators of properties we have purchased or are currently operating. A variety of stringent federal, state and local laws and regulations govern the environmental aspects of our business and impose strict requirements for, among other things:

Any noncompliance with these laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities. Additionally, our compliance with these laws may, from time to time, result in increased costs to our operations or decreased production, and may affect our costs of acquisitions.

In addition, environmental laws may, in the future, cause a decrease in our production or cause an increase in our costs of production, development or exploration. Pollution and similar environmental risks generally are not fully insurable.

Some fields in our onshore California and Illinois Basin properties have been in operation for more than 90 years, and current or future local, state and federal environmental and other laws and regulations may require substantial expenditures to remediate the properties or to otherwise comply with these laws and regulations. In addition, approximately 183 acres of our 480 acres in the Montebello field have been designated as California Coastal Sage Scrub, a known habitat for the gnatcatcher, which is a species of bird designated as a federal threatened species under the Endangered Species Act. A variety of existing laws, rules and guidelines govern activities that can be conducted on properties that contain coastal sage scrub and gnatcatchers and generally limit the scope of operations that we can conduct on this property. The presence of coastal sage scrub and gnatcatchers in the Montebello field and other existing or future laws, rules and guidelines could prohibit or limit our operations and our planned activities for this property.

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Our acquisition strategy could fail or present unanticipated problems for our business in the future, which could adversely affect our ability to make acquisitions or realize anticipated benefits of those acquisitions.

Our growth strategy may include acquiring oil and gas businesses and properties. We may not be able to identify suitable acquisition opportunities or finance and complete any particular acquisition successfully. Furthermore, acquisitions involve a number of risks and challenges, including:

Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows from the acquired businesses or realize other anticipated benefits of those acquisitions.

We intend to continue hedging a portion of our production, which may result in our making cash payments or prevent us from receiving the full benefit of increases in prices for oil and gas.

We reduce our exposure to the volatility of oil and gas prices by actively hedging a portion of our production. Hedging also prevents us from receiving the full advantage of increases in oil or gas prices above the fixed amount specified in the hedge agreement. In a typical hedge transaction, we have the right to receive from the hedge counterparty the excess of the fixed price specified in the hedge agreement over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we must pay the counterparty this difference multiplied by the quantity hedged even if we had insufficient production to cover the quantities specified in the hedge agreement. Accordingly, if we have less production than we have hedged when the floating price exceeds the fixed price, we must make payments against which there are no offsetting sales of production. If these payments become too large, the remainder of our business may be adversely affected. In addition, our hedging agreements expose us to risk of financial loss if the counterparty to a hedging contract defaults on its contract obligations.

Loss of key executives and failure to attract qualified management could limit our growth and negatively impact our operations.

Successfully implementing our strategies will depend, in part, on our management team. The loss of members of our management team could have an adverse effect on our business. Our exploration and exploitation success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced engineers, geoscientists and other professionals. Competition for experienced professionals is extremely intense. If we cannot attract or retain experienced technical personnel, our ability to compete could be harmed. Plains does not have key man insurance.

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Under our tax allocation agreement with our former parent Plains Resources, if we take actions that cause the distribution of our stock by Plains Resources to its stockholders to fail to qualify as a tax-free transaction, we will be required to indemnify Plains Resources for the resulting tax liability and may not have sufficient financial resources to achieve our growth strategy or ability to repay debt or may prevent a change in control of us.

We have agreed with Plains Resources that we will not take any action inconsistent with any information, covenant or representation provided to the Internal Revenue Service in connection with obtaining the tax ruling stating that the spin-off will generally be tax-free to Plains Resources and its stockholders and we further agreed to be liable for any taxes arising from a breach of that agreement. In addition, we have agreed that, for three years following the spin-off, we will not engage in any transaction that could adversely affect the tax treatment of the spin-off without the prior written consent of Plains Resources, unless we obtains a supplemental tax ruling from the Internal Revenue Service or a tax opinion acceptable to Plains Resources of nationally recognized tax counsel to the effect that the proposed transaction would not adversely affect the tax treatment of the spin-off. Moreover, we will be liable to Plains Resources for any corporate level taxes incurred by Plains Resources as a result of the spin-off or to specified transactions involving us following the spin-off including the acquisition of 50% of our common stock by any person or persons. To the extent the taxes arise as a result of a change of control of Plains Resources, failure of Plains Resources to continue the active conduct of its trade or business or failure of Plains Resources to comply with the representations underlying its tax ruling or a supplemental tax ruling relating to the spin-off, Plains Resources will be solely responsible for the taxes resulting from the spin-off. If there are any corporate level taxes incurred by Plains Resources as a result of the spin-off and not due to any of the factors discussed in the two preceding sentences, we would be responsible for 50% of any such liability. The amount of any indemnification payments would be substantial and would likely result in events of default under all of our credit arrangements. As a result, we likely would not have sufficient financial resources to achieve our growth strategy or, possibly, repay our indebtedness after making these payments.

As a result of the tax principles and agreements with Plains Resources discussed above, we may be highly limited in our ability to take the following steps in the future:

Our net income could be adversely affected by stock appreciation rights charges.

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 with respect to our common stock.

Stock appreciation rights are subject to variable accounting treatment. As a result, at the end of each quarter, we compare the per share closing price of our common stock to the exercise price of each stock appreciation right that is vested or for accounting purposes is deemed vested at the end of the quarter. To the extent the closing price exceeds the exercise price, we will recognize the excess as an accounting charge to the extent we did not previously recognize such excess. If, at the end of the quarter, the per share closing price of our common stock decreased, the stock appreciation right accounting charge would decrease, resulting in increased net income for Plains. In 2003 we recognized $18.0 million of SAR expense.

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Item 3.    Legal Proceedings

We are a defendant in various lawsuits arising in the ordinary course of our business. While the outcome of these lawsuits cannot be predicted with certainty and could have a material adverse effect on our financial position, we do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.

In September 2002, Stocker Resources Inc., or Stocker, our general partner before we converted from a limited partnership to a corporation, filed a declaratory judgment action against Commonwealth Energy Corporation, or Commonwealth, in the Superior Court of Orange County, California relating to the termination of an electric service contract. Stocker was seeking a declaratory judgment that it was entitled to terminate the contract and that Commonwealth had no basis for proceeding against Stocker’s related $1.5 million performance bond. Also in September 2002, Stocker was named a defendant in an action brought by Commonwealth in the Superior Court of Orange County, California for breach of the electric service contract. In January 2004 Plains Resources signed a settlement agreement with Commonwealth. Under the terms of our master separation agreement with Plains Resources, we indemnified them for damages they might incur as a result of this action. As such, we reimbursed Plains Resources’ settlement amount.

Item 4.    Submission of Matters to a Vote of Security Holders

No matters were submitted to a vote of the security holders, through solicitation of proxies or otherwise, during the fourth quarter of the fiscal year covered by this report.

Directors and Executive Officers of Plains Exploration & Production Company

Listed below are our directors and executive officers, their age as of February 29, 2003 and their business experience for the last five years.

Directors

James C. Flores, age 44, Chairman of the Board, Chief Executive Officer and a Director since September 2002 and President since March 2004.    He also has been Plains Resources’ Chairman of the Board since December 2002. He was Chairman of the Board and Chief Executive Officer of Plains Resources from May 2001 to December 2002. He was Co-founder and Chairman from inception of Ocean Energy Inc., an oil and gas company, and, at various times, President and Chief Executive Officer from 1992 until March 1999. In March 1999 Ocean Energy, Inc. was merged into Seagull Energy Corporation where Mr. Flores served as Chairman of the Board of the new Ocean Energy, Inc. from March 1999 until January 2000, and as Vice Chairman from January 2000 until January 2001. From January 2001 to May 2001 Mr. Flores managed various private investments.

Alan R. Buckwalter, III, age 57, Director since March 2003.    He retired in January 2003 as Chairman of JPMorgan Chase Bank, South Region, a position he had held since 1998. From 1990 to 1998 he was President of Texas Commerce Bank-Houston, the predecessor entity of JPMorgan Chase Bank. Prior to 1990 Mr. Buckwalter held various executive management positions within the organization. Mr. Buckwalter currently serves on the board of Service Corporation International (SCI), the Texas Medical Center, the Greater Houston Area Red Cross, the University of St. Thomas and St. Luke’s Hospital System. He sits on the Audit Committee and is Chairman of the Compensation Committee for SCI.

Jerry L. Dees, age 64, Director since September 2002.    He also was a director of Plains Resources from 1997 to December 2002. He retired in 1996 as Senior Vice President, Exploration and

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Land, for Vastar Resources, Inc. (previously ARCO Oil and Gas Company), a position he had held since 1991. From 1987 to 1991 he was Vice President of Exploration and Land for ARCO Alaska, Inc., and from 1985 to 1987 he held various positions as Exploration Manager of ARCO. From 1980 to 1985 Mr. Dees was Manager of Exploration Geophysics for Cox Oil and Gas Producers.

Tom H. Delimitros, age 63, Director since September 2002.    He also was a director of Plains Resources from 1988 to December 2002. He has been a General Partner of AMT Venture Funds, a venture capital firm, since 1989. He is also a director of Tetra Technologies, Inc., a publicly-traded energy services company. He currently serves as Chairman for three privately-owned companies. Previously, he has served as President and CEO for Magna Corporation, (now Baker Petrolite, a unit of Baker Hughes). From 1983 to 1988, Mr. Delimitros was a General Partner of Sunwestern Investment Funds and Senior Vice President of Sunwestern Management, Inc.

John H. Lollar, age 65, Director since September 2002.    He also was a director of Plains Resources from 1995 to December 2002. He has been the Managing Partner of Newgulf Exploration L.P. since December 1996. He is also a director of Lufkin Industries, Inc., a manufacturing firm, where he is a member of the Compensation Committee and Chair of the Audit Committee. Mr. Lollar was Chairman of the Board, President and Chief Executive Officer of Cabot Oil & Gas Corporation from 1992 to 1995, and President and Chief Operating Officer of Transco Exploration Company from 1982 to 1992.

Executive Officers

Stephen A. Thorington, age 48, Executive Vice President and Chief Financial Officer since September 2002.    He also has been Plains Resources’ Executive Vice President and Chief Financial Officer since February 2003. He was Plains Resources’ Acting Executive Vice President and Chief Financial Officer from December 2002 to February 2003. Previously, he was Senior Vice President—Finance and Corporate Development of Ocean Energy, Inc. from July 2001 to September 2002 and Senior Vice President—Finance, Treasury and Corporate Development of Ocean Energy, Inc. from March 1999 to July 2001. He also served as Vice President, Finance and Treasurer of Seagull Energy Corporation from May 1996 to March 1999. Mr. Thorington served as a Managing Director of Chase Securities, Inc. from April 1994 to May 1996.

John F. Wombwell, age 42, has been Executive Vice President, General Counsel and Secretary of our company and of Plains Resources since September 2003. Prior to Plains Exploration and Production Company, Mr. Wombwell was General Counsel of ExpressJet Airlines, Inc. from April 2002 to September 2003 and Integrated Electrical Services, Inc. from January 1998 to April 2002. Prior to that time, Mr. Wombwell was a partner at the law firm of Andrews & Kurth L.L.P., where he practiced law in the area of corporate and securities matters, representing a variety of public companies.

Thomas M. Gladney, age 51, Executive Vice President—Exploration & Production since June 2003.    He was our Senior Vice President of Operations from September 2002 to June 2003. He also was Plains Resources’ Senior Vice President of Operations from November 2001 to December 2002. He was President of Arguello, Inc., a subsidiary of Plains, from December 1999 to November 2001. From July 1999 to December 1999 he served as a Project Manager for Torch Energy Services, a contract operating services company. From January 1999 to June 1999 he served as a Project Manager for Venoco Inc., an oil and gas company. From September 1998 to January 1999 he was a self-employed engineering services consultant. From 1992 to September 1998 he was Offshore Operations Manager for Oryx Energy Company. Previously, he served as Gulf Coast Reserve Development Manager of Oryx Energy/Sun E&P from 1988 to 1992.

Cynthia A. Feeback, age 46, Senior Vice President—Accounting and Treasurer since September 2002.    She also was Plains Resources’ Senior Vice President—Accounting and Treasurer from July

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2001 to December 2002. She was its Vice President—Accounting and Assistant Treasurer from May 1999 to July 2001, and its Assistant Treasurer, Controller and Principal Accounting Officer from May 1998 to May 1999. Previously, Ms. Feeback served as its Controller and Principal Accounting Officer from 1993 to 1998, Controller from 1990 to 1993, and Accounting Manager from 1988 to 1990.

Item 5.    Market for Registrant’s Common Stock and Related Stockholder Matters

Price Range of Common stock

Our common stock is listed on the New York Stock Exchange under the symbol “PXP” and began trading on December 18, 2002. The number of stockholders of record of our common stock on February 29, 2004 was 1,352. The following table sets forth the range of high and low sales prices for our common stock as reported on the New York Stock Exchange Composite Tape for the periods indicated below:

Dividend Policy

We do not anticipate declaring or paying any cash dividends in the future. We intend to retain our earnings to finance the expansion of our business and for general corporate purposes. Our board of directors will have the authority to declare and pay dividends on our common stock in its discretion, as long as we have funds legally available to do so. Our credit facility and the indenture relating to our 8.75% senior subordinated notes restrict our ability to pay cash dividends.

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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.