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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

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

OF THE SECURITIES EXCHANGE ACT OF 1934

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

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2002

OR

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

SECURITIES EXCHANGE ACT OF 1934

Commission file number: 001-31470

PLAINS EXPLORATION & PRODUCTION COMPANY

(Exact name of registrant as specified in its charter)

500 Dallas Street, Suite 700

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)

(713) 739-6700

(Registrant’s telephone number, including area code)

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

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

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

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

On March 25, 2003, there were 24,225,075 shares of the registrant’s Common Stock outstanding. The aggregate market value of the Common Stock held by non-affiliates of the registrant (treating all executive officers and directors of the registrant, for this purpose, as if they may be affiliates of the registrant) was approximately $199,380,000 on March 25, 2003 (based on $8.68 per share, the last sale price of the Common Stock as reported on the New York Stock Exchange on such date). ⁽¹⁾

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

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

PLAINS EXPLORATION & PRODUCTION COMPANY

2002 ANNUAL REPORT ON FORM 10-K

Table of Contents

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STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

All forward-looking statements in this Annual Report on Form 10-K are made as of the date hereof, and you should not place undue certainty on these statements without also considering the risks and uncertainties associated with these statements and our business that are addressed in this Annual Report on Form 10-K. Moreover, although we believe the expectations reflected in the forward-looking statements are based upon reasonable assumptions, we can give no assurance that we will attain these expectations or that any deviations will not be material. See Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Factors That May Affect Future Results” for an additional discussion of these risks and uncertainties.

AVAILABLE INFORMATION

We file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any document we file at the SEC’s Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the SEC’s Public Reference Room. Our SEC filings are also available to the public at the SEC’s web site at www.sec.gov. No information from such web site is incorporated by reference herein. Our web site is www.plainsxp.com. You may also obtain copies of our annual, quarterly and current reports, proxy statements and certain other information filed with the SEC, as well as amendments thereto, free of charge from our web site (under “Investor Information” on our web site). These documents are posted to our web site as soon as reasonably practicable after we have filed or furnished these documents with the SEC.

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GLOSSARY OF OIL AND GAS TERMS

The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and this Form 10-K:

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

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

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

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

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

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

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

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

Gas.    Natural gas.

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

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

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

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

MBOE.    One thousand BOE.

Mcf.    One thousand cubic feet of gas.

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

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

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MMBOE.    One million BOE.

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

MMcf.    One million cubic feet of gas.

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

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

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

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

NYMEX.    New York Mercantile Exchange.

Oil.    Crude oil, condensate and natural gas liquids.

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

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

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

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

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

Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing

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by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

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

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

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

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

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

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

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

Standardized measure.    The present value, discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying sales prices in effect as of the dates of such estimates and held constant throughout the productive life of the reserves (except for consideration of price changes to the extent provided by contractual arrangements), and deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on current costs and assuming continuation of existing economic conditions). Future income taxes are calculated by applying the statutory federal and state income tax rate to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to oil and gas operations.

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

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

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

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

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Items 1 and 2.    Business and Properties.

General

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

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

Corporate Reorganization and Spin-off

Prior to December 18, 2002 we were a wholly owned subsidiary of Plains Resources Inc., or Plains Resources. On December 18, 2002 Plains Resources distributed 100% of the issued and outstanding shares of our common stock to the holders of record of Plains Resources’ common stock as of December 11, 2002. Each Plains Resources stockholder received one share of our common stock for each share of Plains Resources common stock held. Prior to the spin-off, Plains Resources made an aggregate of $52.2 million in cash contributions to us and transferred to us certain assets and we assumed certain liabilities of Plains Resources, primarily related to land, unproved oil and gas properties, office equipment and pension obligations. We used the cash contributions to reduce outstanding debt under our revolving credit facility.

In contemplation of the spin-off, under the terms of a Master Separation Agreement between us and Plains Resources, on July 3, 2002 Plains Resources contributed to us 100% of the capital stock of its wholly owned subsidiaries that own oil and gas properties in offshore California and Illinois. As a result, we indirectly own our offshore California and Illinois properties and directly own our onshore California properties. Plains Resources also contributed to us $256.0 million of intercompany payables that we or our subsidiaries owed to it. On July 3, 2002 we issued $200 million of 8.75% Senior Subordinated Notes due 2012, or the 8.75% notes. On July 3, 2002 we also entered into a $300 million revolving credit facility. We distributed the net proceeds of $195.3 million from the 8.75% notes and $116.7 million of initial borrowings under our credit facility to Plains Resources.

Plains Resources received a favorable private letter ruling from the Internal Revenue Service stating that, for United States federal income tax purposes, the distribution of our common stock qualified as a tax-free distribution under Section 355 of the Internal Revenue Code. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.

Proposed Merger

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

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

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

The Boards of Directors of both companies have approved the merger agreement and each has recommended it to their respective stockholders for approval. The transaction is subject to stockholder approval from both companies and other customary conditions and is expected to close in the second quarter of 2003. Assuming the market price of our common stock is between $7.65 and $12.35, after the merger is completed, 3TEC common stockholders will own approximately 40% of the combined company and our stockholders will own approximately 60% of the combined company.

Oil and Gas Operations

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

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

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

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

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

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

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

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Oil and Gas Reserves

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

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 are to some degree speculative, the quantities of oil and gas that are ultimately recovered, production

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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. See Item 7A. “Quantitative and Qualitative Disclosures About Market Risk”.

Since December 31, 2001 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 and Development

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.

By implementing our exploitation plan, we seek to increase cash flows and enhance the value of our asset base. In doing so, we add to and enhance our proved reserves. During the three-year period ended December 31, 2002 our additions to proved reserves, excluding reserves added as a result of our acquisition activities, totaled 67.7 MMBOE or approximately 257% of cumulative net production for this period. We added these reserves at an aggregate average cost of $3.86 per BOE.

If the planned merger with 3TEC does not occur, during 2003 we expect to spend $70-$80 million developing, exploiting and maintaining our oil and gas properties, with approximately 80% of such expenditures allocated to our onshore California properties. Our 2003 capital program includes the drilling of approximately 175 to 190 wells. We believe that our properties hold potential for additional increases in production, reserves and cash flow.

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Exploitation projects.    The following table sets forth information with respect to our oil and gas properties (dollars in millions):

Onshore California

LA Basin.    In 1992 we acquired from ChevronTexaco (references herein to ChevronTexaco include its predecessor companies, Chevron U.S.A. Inc. and Texaco Inc. and their subsidiaries) substantially all of its producing oil properties in the LA Basin. These interests included the Inglewood, East Beverly Hills, San Vicente and South Salt Lake fields. Following the initial acquisition we expanded our holdings in this area by acquiring additional interests within the existing fields, including all of ChevronTexaco’s interest in its Vickers lease, which further consolidated our holdings in the Inglewood field. We refer to all of our properties in the LA Basin acquired before 1997 collectively as the “LA Basin properties”. We hold a 100% working interest in the LA Basin properties.

The LA Basin properties consist of oil reserves discovered at various times between 1924 and 1966. We have performed various exploitation activities, including drilling additional production and injection wells, returning previously marginal wells to economic production, optimizing pre-existing waterflood operations, initiating new waterfloods, optimizing artificial lift, increasing the capacity and efficiency of facilities, upgrading facilities to maintain regulatory compliance, reducing unit production expenses and improving marketing margins. Additionally, we continuously update and perform technical studies to identify new investment opportunities on these properties. Through these acquisition and exploitation activities, our net average daily production from this area has increased from approximately 6.7 MBOE per day in 1992 to 12.2 MBOE per day in 2002.

In December 1995 we amended our asset purchase agreement with ChevronTexaco to remediate sections of our LA Basin properties impacted by prior drilling and production operations. Under this agreement, ChevronTexaco agreed to investigate contamination at the LA Basin properties and potentially remediate specific areas contaminated with hazardous substances, such as volatile organic

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substances and heavy metals, and we agreed to excavate and remediate nonhazardous oil contaminated soils. We are obligated to construct and operate, for the next eight years, at least a five-acre parcel of land as bioremediation cells for oil contaminated soils designated for excavation and treatment by ChevronTexaco. Although we believe that we do not have any material obligations for operations conducted before our acquisition of the properties from ChevronTexaco other than our obligation to plug existing wells and those normally associated with customary oil field operations of similarly situated properties (such as our agreement with ChevronTexaco described above), these amounts may not be recoverable from ChevronTexaco, either under our agreement or the limited indemnity from ChevronTexaco contained in the original purchase agreement.

In 2002 we spent $32.3 million on capital projects, including drilling 20 production wells and four injection wells, performing numerous recompletions and workovers, and modifying various production and injection facilities. In 2003 we expect to drill 25 to 30 wells, perform workovers, stimulations and conversions, perform various technical studies including reservoir simulation, tracer surveys and reserve modeling and upgrade facilities to increase capacities and efficiencies.

We are also applying 3-D seismic technology to further evaluate the unproved reserves in our LA Basin properties, in particular at the Inglewood field. We expect to shoot a 3-D survey in 2003. Interpretation of the data should occur in 2003 and any drilling based on the results may take place in late 2003 and in 2004 and beyond. This will be the first application of 3-D seismic technology in an onshore LA Basin Field. Also in the Inglewood field, we have initiated a 20-well evaluation program using cased hole resistivity logging technology. This technology potentially identifies commercially producible sands behind casing in older wells. Furthermore, we expect these analyses to provide us with a more complete understanding of the field thereby potentially allowing us to improve the waterflood program. Finally, we anticipate the installation of an alternative to procuring electricity for a portion of the current load in the Inglewood field by installation of a cogeneration facility.

Montebello.    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 approximately 480 acres of surface fee land. Our net average daily production from this field has increased from 0.9 MBOE per day at the time of acquisition to 2.6 MBOE per day in 2002. Since the acquisition, we have drilled a total of 65 producing wells and 25 injection wells. In 2002 we spent $10.8 million on capital projects, which included drilling 18 production wells and 3 injection wells, performing numerous workovers, acquiring seismic and other technical data and increasing the capacity of the production and injection facilities. In 2003 we expect to perform several technical studies that may lead to additional drilling or other development opportunities that would likely be initiated beginning in 2004.

Arroyo Grande.    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 1,000 acres included in the 1,500-acre producing unit. The field is primarily under continuous steam injection and, at our acquisition date, was producing approximately 1.6 MBOE per day (approximately 1.5 MBOE net to our interest) of 14 degree API gravity oil from 70 wells. Since acquiring 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. We also curtailed steam injection by about 50% immediately following the acquisition due to low oil prices. Although oil prices subsequently rebounded, we maintained injection at this low rate pending our analysis of the saturation inputs provided by the infill drilling program, and in 2001 due to excessive gas fuel costs. As a result, base volumes declined considerably, but this decline was offset by the wells we drilled to downsize the injection patterns.

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In 2001 we spent $10.6 million on capital projects in the Arroyo Grande field, the most significant of which was drilling 19 production and 11 injection wells and installing a gas processing facility to reduce third-party fuel gas purchases. During 2002 we reduced capital expenditures to $1.5 million to allow time to assess the results of the 2001 drilling program and prepare to expand our steam flood in 2003-2004. We are also reviewing a plan to optimize steam handling and produced water disposal. In 2003 we expect to drill 15 to 20 wells and install a small cogeneration facility to reduce electricity costs and provide additional steam. Our net average daily production from this field was 1.9 MBOE per day during 2002.

Mt. Poso.    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 recompletion and drilling program targeting the Pyramid Hills formation, completing a 107-well drilling program in 2000-2001. During 2002 we reduced capital expenditures to focus on optimizing operating costs, including the installation of electrical generation facilities, and reviewing past drilling results to identify future drilling potential. In 2002 we spent $0.8 million on capital projects to optimize our producing infrastructure. In 2003 we expect to drill 75 to 100 new wells. Our net average daily production from this field was 1.5 MBOE during 2002.

Offshore California

Point Arguello.    In July 1999 we acquired ChevronTexaco’s 26.3% working interest 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. ChevronTexaco 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 ChevronTexaco’s 26.3% share of all other abandonment costs.

Effective August 1, 2002 we acquired an additional 26.3% working interest from subsidiaries of Phillips Petroleum Company in the Point Arguello unit and the various partnerships owning the related transportation, processing and marketing infrastructure with effect from April 1, 2002. The seller retained responsibility for certain abandonment costs, including: (1) removing, dismantling and disposing of the existing offshore platforms; (2) removing and disposing of all pipelines; and (3) removing, dismantling, disposing and remediating all existing onshore facilities. We assumed the seller’s share of all other abandonment costs. As consideration for receiving the transferred properties and assuming the obligations described above we received $2.4 million. In addition, we received $2.7 million as our share of revenues less costs for the period prior to ownership from April 1 to July 31, 2002. This transaction doubled our working interest in the Point Arguello unit to 52.6%.

In 2002 we spent $6.2 million on capital projects, which included drilling 4 development wells, one of which was a dry hole, converting wells to electric submersible lift systems, and various workovers and stimulations. In 2003 we expect to drill one to two new wells and continue with our successful workover and high volume lift programs. At the time we acquired our interest in Point Arguello, our net average daily production from this unit was 5.2 MBOE. During 2002, including the effect of the interest acquired effective August 1, 2002, our net average daily production was 4.9 MBOE.

Rocky Point.    Part of one of our leases in the Point Arguello unit is partially unitized in the Rocky Point unit, which is adjacent to the Point Arguello unit. As a result, we are the operator and have an agreement that entitles us to participate with at least a 52.6% working interest in the development of the Rocky Point unit. We are particularly interested in this unit because five exploratory wells were drilled into it in 1983-1984, and these wells tested at 3,500, 1,629, 1,100, 604 and 120 Bbls per day. Accordingly, we are currently seeking regulatory approval to allow near-term development of our lease

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in the Rocky Point unit by drilling extended-reach wells from the Point Arguello platforms. While we must obtain a larger rig and several regulatory permits and other agreements among the working interest owners, we believe that if we resolve these issues, we may be able to drill in the Rocky Point unit. There can be no assurance, however, that any such drilling can or will occur or that we will recover economic quantities of oil and gas from the Rocky Point unit. The other two leases that compose the Rocky Point unit are subject to litigation between the federal government and the state of California concerning the state’s ability to review MMS approvals of lease suspensions for consistency with the state’s Coastal Management Program and cannot be developed until the resolution of such litigation.

Illinois Basin

In December 1995 we acquired our properties in the Illinois Basin from Marathon Oil Company, which produced an average of 2.5 MBbls of oil per day in 2002 and accounted for 10% of our total sales volumes. In 2002, we spent $7.0 million on capital projects, which included drilling 38 development wells. In 2003 we expect to drill 35 to 45 wells and form new waterflood units to increase operations and recovery efficiency. In addition, we are continuing to evaluate the feasibility and potential implementation of a pilot program to field test an alkaline-surfactant enhanced oil recovery process.

Other

Our 2002 capital expenditures include $8.4 million of capitalized interest and general and administrative costs allocable directly to acquisition, exploitation and development activities and $2.6 million attributable to other projects.

Exploitation, Development, Exploration and Acquisition Expenditures

The following table summarizes the costs incurred during the last three years for our exploitation and development, exploration and acquisition activities (in thousands):

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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 received and our average production expenses during the years ended December 31, 2002, 2001 and 2000.

Plains All American Pipeline, L.P., or PAA, is the exclusive purchaser of all of our equity oil production. See—Product Markets and Major Customers.

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 sales. Our hedging arrangements provide us protection on the

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hedged volumes if oil prices decline below the prices at which these hedges are set. However, ceiling prices in our hedges may cause us to receive less revenues on the hedged volumes than we would receive in the absence of hedges. We do not currently have any gas hedges. See Item 7A. “Quantitative and Qualitative Disclosures About Market Risk”.

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.

PAA is currently the exclusive purchaser of all of our equity oil production. We pay PAA a marketing and administration fee of $0.20 per barrel 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.

We are currently negotiating a new marketing agreement with PAA to, among other things, add a definitive term to the agreement and provide that PAA will use its reasonably best efforts to obtain the best price for our oil production.

Productive Wells and Acreage

As of December 31, 2002 we had working interests in 2,148 gross (2,132 net) active producing oil wells. The following table sets forth information with respect to our developed and undeveloped acreage as of December 31, 2002.

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Drilling Activities

Information with regard to our drilling activities during the years ended December 31, 2002, 2001 and 2000 is set forth below:

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

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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 believe that we are affected in a significantly different manner by these laws and regulations than are our competitors. Due to the myriad of 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 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.

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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 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. The permits required for various of our operations are subject to revocation, modification and renewal by issuing authorities.

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

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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.

Plugging, Abandonment and Remediation Obligations

Consistent with normal industry practices, substantially all of our oil and gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. Typically when producing oil and gas assets are purchased, 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 Illinois 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 the 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 or that any portion of such amounts will be recoverable under the indemnity.

We estimate our 2003 cash expenditures related to plugging, abandonment and remediation will be approximately $2.3 million (including the costs required to be expended in connection with the purchase of certain of our onshore California properties). Due to the long life of our onshore reserve base we do not expect our cash outlays for such expenditures for these properties will increase significantly in the next several years. Although our offshore California properties have a shorter reserve life, third parties have retained the majority of the obligations for abandoning these properties.

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 154 inactive wells at December 31, 2002). 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 our separation from Plains Resources, we entered into the following agreements:

Master Separation Agreement

Overview.    To effect our separation from Plains Resources, we entered into a master separation agreement on July 3, 2002 with Plains Resources simultaneous with entering into our financing. The

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master separation agreement provides for the separation of substantially all of the upstream assets and liabilities of Plains Resources, other than its Florida operations. The master separation agreement provides for, among other things:

Separation.    To effect the separation, on July 3, 2002, Plains Resources transferred to us assets and liabilities related to Plains Resources’ upstream business other than its Florida operations, including the capital stock of Arguello Inc., Plains Illinois Inc., PMCT, Inc. and Plains Resources International Inc., miscellaneous upstream assets and related hedging agreements. We assumed the liabilities associated with the transferred assets and businesses. Plains Resources also transferred to us additional assets and liabilities, including remaining upstream agreements and permits that require consent to transfer and office furniture and equipment, and we will sublease a portion of Plains Resources’ office space. Except as set forth in the master separation agreement, no party is making any representation or warranty as to the assets or liabilities transferred as a part of the separation, and all assets are being transferred on an “as is, where is” basis.

Plains Resources agreed to take such further actions as we may reasonably request to more effectively complete the transfers of assets and liabilities described above, to protect and enjoy all rights and benefits Plains Resources had with respect thereto and as otherwise appropriate to carry out the transactions contemplated by the master separation agreement.

Indemnification.    The master separation agreement provides for cross-indemnities intended to place sole financial responsibility on us for all liabilities associated with the current and historical businesses and operations we conduct after giving effect to the separation, regardless of the time those liabilities arise, and to place sole financial responsibility for liabilities associated with Plains Resources’ other businesses with Plains Resources and its other subsidiaries. The master separation agreement also contains indemnification provisions under which we and Plains Resources each indemnify the other with respect to breaches by the indemnifying party of the master separation agreement or any of the ancillary agreements described below. We agree to indemnify Plains Resources and its other subsidiaries against liabilities arising from misstatements or omissions in the various offering documents for the exchange offer related to our 8.75% notes or the spin-off including related prospecti or in documents to be filed with the SEC in connection therewith, except for information regarding Plains Resources provided by Plains Resources for inclusion in such documents. Plains Resources agrees to indemnify us against liabilities arising from misstatements or omissions in the various offering documents for the exchange offer related to our 8.75% notes or the spin-off, including related prospecti or in documents to be filed with the SEC in connection therewith if such information was provided by Plains Resources.

The master separation agreement contains a general release under which we released Plains Resources and its subsidiaries, affiliates, successors and assigns, and Plains Resources released us from any liabilities arising from events between us on the one hand, and Plains Resources or its subsidiaries on the other hand, occurring on or before the separation, including events in connection with activities to implement the separation, this offering and the spin-off. The general release does not

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apply to obligations under the master separation agreement or any ancillary agreement, to liabilities transferred to us, to future transactions between us and Plains Resources, or to specified contractual arrangements.

Other provisions.    The master separation agreement also provides for: (1) mandatory arbitration to settle disputes between us and Plains Resources and its subsidiaries; (2) exchange of information between Plains Resources and us for purposes of conducting our operations, meeting regulatory requirements, responding to regulatory or judicial proceedings, meeting SEC filing requirements, and other reasons; (3) coordination of the conduct of our annual audits and quarterly reviews so that we may both file our annual and quarterly reports in a timely manner; (4) preservation of legal privileges and (5) maintaining confidentiality of each other’s information.

In addition, we and Plains Resources agree to use reasonable efforts to amend the omnibus agreement with PAA to terminate the noncompetition provisions therein and to enter into a new oil marketing agreement with PAA so that the agreement only applies to us and to add a definite term to the agreement, and other amendments.

Non-competition.    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.)

Employee Matters Agreement

We entered into an employee matters agreement with Plains Resources. The employee matters agreement does not address the treatment of Messrs. Flores, Raymond and Stephens, whom we call the executives, except with respect to the treatment of their existing options to acquire Plains Resources common stock.

Other employees.    The employee matters agreement provided that those employees who work for us after the spin-off were transferred to us immediately before the spin-off. Neither their transfer nor the spin-off was treated as a termination of their employment for purposes of any benefits under any plans.

Stock options and restricted stock awards.    Under the employee matters agreement, as a result of the spin-off, all outstanding options to acquire Plains Resources common stock at the time of the spin-off were “split” into (1) an equal number of options to acquire Plains Resources common stock and (2) an equal number of stock appreciation rights, or SARs, with respect to our common stock.

The exercise price for the original Plains Resources stock options was also “split” between the new Plains Resources stock options and the SARs based on the following relative amounts: the closing price (with dividend) of Plains Resources common stock on the spin-off date less the closing price (on a “when-issued” basis) of our common stock on the spin-off date, both as reported on the NYSE, and such closing price of our common stock.

Also, unless otherwise provided for in the agreement governing the restricted stock award, at the time of the spin-off all restricted stock awards for Plains Resources common stock were “split” into (1) restricted stock awards for an equal number of shares of Plains Resources common stock and (2) restricted stock awards for an equal number of shares of our common stock.

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All recipients of our SARs and restricted stock awards received the benefit of prior service credit at Plains Resources and have the same amount of vesting as they had under their related Plains Resources stock options and restricted stock awards, and vesting terms remain unchanged. Also, an employee’s or a director’s service with us counts towards the vesting of their “split” Plains Resources stock options and restricted stock awards even though the employee is no longer employed by Plains Resources or the director no longer serves at Plains Resources. Likewise, with respect to employees and directors who stay with Plains Resources, their service at Plains Resources counts towards the vesting of their SARs even though they are not employed by us or do not serve on our board of directors.

Unless a person is employed by or serves as a director for both Plains Resources and us, termination of employment or service as a director for any reason at either company will count as termination for the same reason at the other company for purposes of vesting and termination of options, SARs, and restricted stock awards. If a person is employed by or serves as a director for both Plains Resources and us, termination for any reason at one company will not count as termination at the other company.

Other plans.    Under the employee matters agreement (1) we established a nonqualified deferred compensation plan for certain executive officers and, to the extent that any of the executives are participants in the Plains Resources deferred compensation plan, the related assets and liabilities under the Plains Resources plan were transferred to our plan, (2) Plains Resources transferred its 401(k) plan and welfare benefit plans to us and formed a similar 401(k) plan and similar welfare benefit plans, and (3) we established plans that mirror the fringe benefits and company policies of Plains Resources.

Other.    Under the employee matters agreement, Plains Resources retained liability for all incurred but not reported claims occurring before the spin-off, and we are liable for all claims incurred on or after the spin-off related to our employees.

Tax Allocation Agreement

On July 3, 2002, we entered into the tax allocation agreement, which we and Plains Resources amended and restated on November 20, 2002. This agreement provides that, until the spin-off, we continued to be included in Plains Resources’ consolidated federal income tax group, and our federal income tax liability was included in the consolidated federal income tax liability of Plains Resources. The amount of taxes that we pay or receive with respect to consolidated or combined returns of Plains Resources in which we are included generally are to be determined by multiplying our net taxable income included in the Plains Resources consolidated tax return by the highest marginal tax rate applicable to the income. Plains Resources is not required to pay us for the use of our tax attributes that come into existence before the spin-off until such time as we would otherwise be able to utilize such attributes.

In general, the agreement provides that we are included in Plains Resources’ consolidated group for federal income tax purposes until the time of the spin-off. Each member of a consolidated group is jointly and severally liable for the federal income tax liability of each other member of the consolidated group. Accordingly, although this agreement allocates tax liabilities between us and Plains Resources during the period in which we are included in Plains Resources’ consolidated group, we could be liable if any federal tax liability is incurred, but not discharged, by any other member of Plains Resources’ consolidated group. In addition, to the extent Plains Resources’ net operating losses are used in the consolidated return to offset our taxable income from operations during the period January 1, 2002 through the spin-off, we will reimburse Plains Resources for the reduction in our federal income tax liability resulting from the utilization of such net operating losses, but such reimbursement shall not

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exceed $3 million exclusive of any interest accruing under the agreement. Such liability is reflected in our consolidated financial statements at December 31, 2002.

Under the terms of this agreement, we agree to indemnify Plains Resources if the spin-off is not tax-free to Plains Resources as a result of various actions taken by us or with respect to our failure to take various actions.

In addition, we agree that, during the three-year period following the spin-off, without the prior written consent of Plains Resources, we will not engage in transactions that could adversely affect the tax treatment of the spin-off unless we obtain a supplemental tax ruling from the IRS or a tax opinion acceptable to Plains Resources of nationally recognized tax counsel to the effect that the proposed transaction would not adversely affect the tax treatment of the spin-off or provide adequate economic security to Plains Resources to ensure we would be able to comply with our obligation under this agreement. We may not be able to control some of these events that could trigger this indemnification obligation.

We also agree to be liable for transfer taxes associated with the transfer of assets and liabilities in connection with the separation and the spin-off.

Intellectual Property Agreement

On July 3, 2002 we entered into the intellectual property agreement, which provides that Plains Resources will transfer to us ownership and all rights associated with certain trade names, trademarks, service marks and associated goodwill, including Arguello, Plains, Plains Energy, Plains E&P, Plains Exploration & Production, Plains Illinois, Plains Petroleum, Plains Resources, Plains Resources International, PLX, PMCT, Stocker Resources and the Plains logo. In addition, we will grant to Plains Resources a full license to use certain trade names including Plains Energy and Plains Resources, referred to as the Plains Marks, subject to certain limitations. These licenses are not transferable or assignable without our written consent, except that Plains Resources may grant its subsidiaries sublicenses to use the Plains Marks.

Plains Resources will not attempt to register a trade name or trademark that incorporates or is confusingly similar to the Plains Marks. Also, if Plains Resources develops new trademarks using the name “Plains,” it must first obtain our written approval. We will own such new trademarks and they will be considered subject to the terms of this agreement.

The intellectual property agreement provides that Plains Resources will conform the nature and quality of its products and services offered in connection with the Plains Marks to our reasonable design and quality standards. Further, Plains Resources will use the Plains Marks only in connection with its business.

Plains Exploration & Production Transition Services Agreement

On July 3, 2002 we entered into the Plains Exploration & Production transition services agreement, which provides that Plains Resources will provide us the following services, on an interim basis:

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Through December 31, 2002 Plains Resources has charged us $10.8 million of the maximum $30.0 million allowed under the agreement to reimburse it for its costs of providing such services. Plains Resources will continue to provide services under this agreement until June 16, 2002 unless we and Plains Resources decide to terminate the agreement earlier. We do not expect to incur significant additional charges under this agreement.

This transition services agreement provides that Plains Resources will not be liable to us with respect to the performance of the services, except in the case of gross negligence or willful misconduct in providing the services. Plains Resources will indemnify us for any liabilities arising from such gross negligence or misconduct. We will indemnify Plains Resources for any liabilities arising directly from the performance of the services by Plains Resources, except for liabilities caused by gross negligence or willful misconduct of Plains Resources. Plains Resources will disclaim all warranties and makes no representations as to the quality, suitability or adequacy of the services provided.

Plains Resources Transition Services Agreement

On July 3, 2002 we entered into the Plains Resources transition services agreement, under which we will provide Plains Resources the following services on an interim basis beginning on a date to be determined by both us and Plains Resources upon the transfer by Plains Resources of substantially all of its employees to us:

The services provided by us under the Plains Resources transition services agreement and the services provided by Plains Resources under the Plains Exploration & Production transition services agreement are substantially similar, except that:

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We will charge Plains Resources on a monthly basis our costs of providing such services.

In addition, we and Plains Resources may identify additional services that we will provide to Plains Resources under this agreement in the future. The terms and costs of these additional services will be mutually agreed upon by us and Plains Resources. We may allow one of our subsidiaries or a qualified third party to provide the services under this agreement, but we will be responsible for the performance of the services.

We will be obligated to provide the services with substantially the same degree of care as we employ for our own operations. We may change the manner in which we provide the services so long as we deem such change to be necessary or desirable for our own operations.

This transition services agreement provides that we will not be liable to Plains Resources with respect to the performance of the services, except in the case of gross negligence or willful misconduct in providing the services. We will indemnify Plains Resources for any liabilities arising from such gross negligence or misconduct. Plains Resources will indemnify us for any liabilities arising directly from our performance of the services, except for liabilities caused by our gross negligence or willful misconduct. We will disclaim all warranties and make no representations as to the quality, suitability or adequacy of the services provided.

The term of this agreement expires on June 8, 2003 unless we and Plains Resources decide to terminate the agreement earlier. We and Plains Resources may agree to extend the term if necessary or desirable.

Technical Services Agreement

On July 3, 2002 we entered into the technical services agreement, which provides that, beginning on a date to be determined by us and Plains Resources, we will provide Calumet Florida certain engineering and technical support services required to support operation and maintenance of the oil and gas properties owned by Calumet, including geological, geophysical, surveying, drilling and operations services, environmental and other governmental or regulatory compliance related to oil and gas activities and other oil and gas engineering services as requested, and accounting services.

Plains Resources will reimburse us for our costs to provide these services.

In addition, we and Plains Resources may identify additional services that we will provide to Plains Resources under this agreement in the future. The terms and costs of these additional services will be mutually agreed upon by us and Plains Resources. We may allow one of our subsidiaries or a qualified third party to provide the services under this agreement, but we will be responsible for the performance of the services.

We and Plains Resources may agree to specific performance metrics that we must meet. Where no metrics are provided, we will (1) perform the services in accordance with the policies and procedures in effect before this agreement, (2) exercise the same care and skill as we exercise in performing similar services for our subsidiaries, and (3) in cases where there is common personnel, equipment or facilities for services provided to our subsidiaries and Plains Resources, not favor Plains Resources or our subsidiaries over the other. We may change the manner in which we provide the services so long as we are making similar changes to the services we are providing to our subsidiaries.

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We are not obligated to provide any service to the extent it is impracticable as a result of causes outside of our control.

The technical services agreement provides that we will not be liable to Plains Resources or Calumet with respect to the performance of the services, except in the case of gross negligence or willful misconduct in providing the services. We will indemnify Plains Resources and Calumet for any liabilities arising from such gross negligence or misconduct. Plains Resources will indemnify us for any liabilities arising directly from the performance of the services, except for liabilities caused by our gross negligence or willful misconduct. We disclaim all warranties and make no representations as to the quality, suitability or adequacy of the services provided.

We will provide the services 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 this 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.

Employees

As of February 28, 2003 we had 354 full-time employees, 252 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.

Risks Relating to Our Business

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. In July 2002 we issued $200 million of 8.75% notes which are supported by guarantees of our subsidiaries. In addition, we have a $300.0 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 28, 2003 we had $33.5 million outstanding under this credit facility.

We have been assigned a Ba3 senior implied rating and our 8.75% 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:

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

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.

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:

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

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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 war in Iraq, recent terrorist activities and the potential for other global events could adversely affect our business.

The United States is at war with Iraq. Additionally, on September 11, 2001, the United States was the target of terrorist attacks of unprecedented scope, and the United States and other countries instituted military action in response. These conditions 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. In particular, it appears the price of oil has become increasingly volatile since commencement of war in Iraq. Further, the United States government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. 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 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 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

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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:

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.

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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.

Substantially all of our oil and gas reserves are located in California and Illinois. 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 reserves average 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.

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:

In addition, our operations in California are especially susceptible to damage from natural disasters such as earthquakes and fires and involve increased risks of personal injury, property damage and marketing interruptions because of the population density of southern California. Any of these operating hazards could cause serious injuries, fatalities 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.

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Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences. Our insurance might be inadequate to cover our liabilities. For example, we are not fully insured against earthquake risk in California because of high premium costs. Insurance covering earthquakes or other risks may not be available at premium levels that justify its purchase in the future, if at all. The insurance market in general and the energy insurance market in particular have been difficult markets over the past several years. Upon renewal in June 2002, our cost of insurance increased substantially over the prior year’s amount. In addition, we increased deductibles and decreased or eliminated certain types of coverages to mitigate the cost increase. Insurance costs are expected to continue to increase over the next few years and we may decrease coverage and retain more risk to mitigate future cost increases. If we incur substantial liability and the damages are not covered by insurance or are in excess of policy limits, or if we incurs 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.

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.

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.

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

We conducts operations offshore California. 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.

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

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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.

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.

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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.

We do not have key man insurance. For information on our executive officers, our key employees, see Item 4. Submission of Matters to a Vote of Security Holders.

We and Plains Resources share and, therefore will compete for, the time and effort of our personnel who provide services to Plains Resources, including directors and officers.

Because certain of our officers and directors provide services to Plains Resources, conflicts of interest could arise between Plains Resources, on the one hand, and us or you, on the other. Additionally, some of these officers and directors own and are awarded from time to time shares, or options to purchase shares, of Plains Resources. Accordingly, their financial interests may not always be aligned with ours or yours and could create, or appear to create, potential conflicts of interest when these officers and directors are faced with decisions that could have different implications for us and Plains Resources.

Risks Relating to the Reorganization and Spin-off

Our historical financial results as a subsidiary of Plains Resources may not be representative of our results as a separate company.

The historical financial information included in this document does not necessarily reflect what our financial position, results of operations and cash flows would have been had we been a separate, stand-alone entity during the periods presented. Our costs and expenses reflect charges from Plains Resources for centralized corporate services and infrastructure costs. These allocations have been determined based on what we and Plains Resources considered to be reasonable reflections of the utilization of services provided to us or for the benefits we received. This historical financial information is not necessarily indicative of what our results of operations, financial position and cash flows will be in

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the future. We may experience significant changes in our cost structure, funding and operations as a result of our reorganization and spin-off from Plains Resources, including increased costs associated with reduced economies of scale, and increased costs associated with being a publicly traded, stand-alone company.

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 Plains stock appreciation rights.

SARs are subject to variable accounting treatment. As a result, at the end of each quarter, we will compare the closing price of our common stock on the last day of the quarter to the exercise price of each outstanding or unexercised SAR that is vested or for accounting purposes is deemed vested at the end of the quarter. For example, if a SAR is scheduled to vest on December 31, for accounting purposes one-fourth of the shares are deemed to vest at the end of each quarter even though no

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vesting legally occurs until December 31. To the extent the closing price at the end of each quarter exceeds the exercise price of each SAR, we will recognize such excess as an accounting charge for the SARs deemed vested to the extent such excess has not previously been recognized as expense. If the quarter-end closing price decreases compared to prior periods, we will recognize credits to income, to the extent we have previously recognized expense. These quarterly charges and credits will make our results of operations depend, in part, on fluctuations in the price of our common stock and could have a material adverse effect on our results of operations. We will incur cash expenditures as SARs are exercised, but our common share count will not increase.

We recognized compensation expense of $2.7 million, representing the difference in our common stock price on December 18, 2002, the date of the spin-off, and the exercise price of each SAR deemed vested on that date. In addition, we recognized compensation expense of $1.0 million, representing the increase in our stock price and the vesting deemed to have occurred from the spin-off date to December 31, 2002. As of December 31, 2002, we had approximately 4.0 million SARs outstanding with an average exercise price of $8.68, of which 2.6 million of the SARs were deemed vested.

Item 3.    Legal Proceedings

On September 18, 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 is seeking a declaratory judgment that it was entitled to terminate the contract and that Commonwealth has no basis for proceeding against Stocker’s related $1.5 million performance bond. Also on September 18, 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. Commonwealth is seeking unspecified damages. In December 2002, Stocker was merged into Plains Resources. Under our master separation agreement with Plains Resources, we must indemnify Plains Resources for damages it incurs as a result of this action. We understand that Plains Resources intends to defend its rights vigorously in this matter.

In the ordinary course of our business, we are a claimant or defendant in various legal proceedings. 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.

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 28, 2003 and their business experience for the last five years.

Directors

James C. Flores, age 43, Chairman of the Board, Chief Executive Officer and a Director since September 2002. Mr. Flores was Chairman of the Board and Chief Executive Officer of Plains Resources from May 2001 until December 2002 and has been Executive Chairman of the Board of that

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company since December 2002. He was President and Chief Executive Officer of Ocean Energy, Inc., an oil and gas company, from July 1995 until March 1999, and a director of Ocean Energy, Inc. from 1992 until March 1999. In March 1999 Ocean Energy, Inc. was merged into Seagull Energy Corporation, which was the surviving corporation of the merger, and which was renamed Ocean Energy, Inc. 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 56, Director since March 2003. Mr. Buckwalter 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 boards of the Texas Medical Center, the Federal Reserve Bank of Dallas, Houston Branch and he is currently serving as Chairman of the Board of Trustees for Texas Southern University Foundation.

Jerry L. Dees, age 63, Director since September, 2002. Mr. Dees retired in 1996 as Senior Vice President, Exploration and Land, for Vastar Resources, Inc. (previously ARCO Oil and Gas Company), a position he had held since 1991. From 1987 to 1991 he was Vice President of Exploration and Land for ARCO Alaska, Inc., and from 1985 to 1987 he held various positions as Exploration Manager of ARCO. From 1980 to 1985 Mr. Dees was Manager of Exploration Geophysics for Cox Oil and Gas Producers. Mr. Dees was a director of Plains Resources from 1997 until 2002.

Tom H. Delimitros, age 62, Director since September, 2002. Mr. Delimitros 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 two privately-owned companies—ImageLinks, Inc., and InterCorp International Inc.—both of which sell products and services to energy 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. Mr. Delimitros was a director of Plains Resources from 1988 until 2002.

John H. Lollar, age 64, Director since September, 2002. Mr. Lollar 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. 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. Mr. Lollar was a director of Plains Resources from 1995 until 2002.

Executive Officers

John T. Raymond, age 32, President and Chief Operating Officer since September 2002. Since December 2002 Mr. Raymond has also served as Chief Executive Officer of Plains Resources. From November 2001 until December 2002 he was Plains Resources’ President and Chief Operating Officer. Previously, he was its Executive Vice President and Chief Operating Officer from May 2001 to November 2001. In addition, Mr. Raymond served as Director of Corporate Development of Kinder Morgan, Inc. from January 2000 to May 2001, and as Vice President of Corporate Development of Ocean Energy, Inc. from April 1998 to January 2000. Mr. Raymond also served as Vice President of Howard Weil Labouisse Friedrichs, Inc., an energy investment company, from 1992 to April 1998. In addition, Mr. Raymond is a director of Plains All American GP LLC, which is the general partner of Plains AAP.

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Stephen A. Thorington, age 47, Executive Vice President and Chief Financial Officer since September 2002. Mr. Thorington has also served as Executive Vice President and Chief Financial Officer of Plains Resources since February 2003 and from December 2002 until February 2003 he served as Acting Executive Vice President and Chief Financial Officer. Mr. Thorington 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.

Timothy T. Stephens, age 50, Executive Vice President—Administration, Secretary and General Counsel since September 2002. Mr. Stephens was Plains Resources’ Executive Vice President—Administration, Secretary and General Counsel from May 2001 until September 2002. From March 2000 to May 2001 Mr. Stephens practiced as a private business consultant to various clients. In February 1998 Mr. Stephens was hired by the board of directors of Abacan Resources Corporation, an oil and gas company, to help the company overcome significant financial difficulties. He served as Chairman, President and Chief Executive Officer of Abacan until March 2000 when the company, after a two-year restructuring, was placed into statutory receivership with the agreement of its senior creditor. Previously, Mr. Stephens was President of Seven Seas Petroleum from February 1995 to May 1997, and Vice President of Enron Capital & Trade Resources Corp. from July 1991 to February 1995.

Cynthia A. Feeback, age 45, Senior Vice President—Accounting and Treasurer since September 2002. Ms. Feeback was Plains Resources’ Senior Vice President—Accounting and Treasurer from July 2001 until September 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.

Thomas M. Gladney, age 50, Senior Vice President of Operations since September 2002. Mr. Gladney was Plains Resources’ Senior Vice President of Operations from November 2001 until September 2002. He was President of Arguello, Inc., a subsidiary of ours, 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.

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. During 2002 the high and low closing sales prices of our common stock as reported on the applicable New York Stock Exchange Composite Tape were $10.00 and $9.75, respectively.

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% notes restrict our ability to pay cash dividends.

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Recent Sales of Unregistered Securities

On September 28, 1990 we were formed as a California limited partnership. On September 18, 2002 we converted into a Delaware limited partnership, and then converted into a Delaware corporation. As a result of the conversion, on September 18, 2002 our limited partnership interests were converted into 975 shares of our common stock which were issued to Plains Resources Inc. and 25 shares of our common stock which were issued to Stocker Resources Inc., a wholly owned subsidiary of Plains Resources. No additional consideration was received for these shares. On September 30, 2002 we declared a stock dividend in an amount equal to 24,199 shares of our common stock for each share of our common stock outstanding, resulting in the issuance of 24,199,000 shares of our common stock to Plains Resources and Stocker. All such issuances were exempt from registration under Section 4(2) of the Securities Act of 1933, as amended, or the Securities Act, as issuances not involving any public offering of securities.

On July 3, 2002 we issued, at an issue price of 98.376%, $200.0 million of 8.75% senior subordinated notes due 2012. The 8.75% notes were issued to J.P. Morgan Securities Inc., Goldman, Sachs & Co., Banc One Capital Markets, Inc., BNP Paribas Securities Corp., Fleet Securities, Inc. and Fortis Investment Services LLC in an exempt transaction under Rule 144A and Regulation S of the Securities Act. These notes are our unsecured general obligations, are subordinated in right of payment to all of our existing and future domestic restricted subsidiaries. We filed a registration statement with the SEC and all holders of these notes have exchanged these notes for registered notes having substantially the same terms. We distributed the net proceeds of $195.3 million from the sale of these notes, together with $116.7 million in initial borrowings under our credit facility, to Plains Resources, which used the proceeds to redeem its 10.25% senior subordinated notes and repay $25.0 million outstanding under its credit facility.

We have not sold any other securities, registered or otherwise, within the past three years.

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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 (in thousands, except per share data):