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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Form 10-K

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

Commission file number 0-9808

Plains Resources Inc.

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

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 o

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. o

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

On February 28, 2003, there were 24,167,935 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 $592,221,000 on June 28, 2002 (based on $26.75 per share, the last sale price of the Common Stock as reported on the New York Stock Exchange on such date). On December 18, 2002 we completed the spin-off of Plains Exploration & Production Company (“PXP”). At the close of business on such date, our closing price per share as reported on the NYSE (on a “with dividend” basis) was $23.05. The closing price per share of PXP on such date as reported on the NYSE (on a “when issued” basis) was $9.10. Our closing price on December 19, 2002 and February 28, 2003, as reported on the NYSE, was $12.51 and $11.39, respectively. The aggregate market value of the common stock held by non-affiliates of the registrant was approximately $252,165,000 on February 28, 2003 (based on the closing price on that date).

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

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PLAINS RESOURCES INC.

2002 ANNUAL REPORT ON FORM 10-K

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

	•	the consequences of any potential change in the relationship between us and Plains Exploration & Production Company;
	•	the consequences of our and Plains Exploration’s officers and employees providing services to both us and Plains Exploration and not being required to spend any specified percentage or amount of time on our business;
	•	risks, uncertainties and other factors that could have an impact on Plains All American Pipeline, L.P., or PAA, which could in turn impact the value of our holdings in PAA (for a discussion of these risks, uncertainties and other factors, see PAA’s filings with the SEC);
	•	the effects of our indebtedness, which could adversely restrict our ability to operate, could make us vulnerable to general adverse economic and industry conditions, could place us at a competitive disadvantage compared to our competitors that have less debt, and could have other adverse consequences;
	•	uncertainties inherent in the development and production of oil and gas and in estimating reserves;
	•	unexpected future capital expenditures (including the amount and nature thereof);
	•	impact of oil and gas price fluctuations;
	•	the effects of competition;
	•	the success of our risk management activities;
	•	the availability (or lack thereof) of acquisition or combination opportunities;
	•	the impact of current and future laws and governmental regulations;
	•	environmental liabilities that are not covered by an effective indemnity or insurance, and
	•	general economic, market, industry or business conditions.

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

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      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.plainsresources.com. You may also obtain copies of our annual, quarterly and current reports, proxy statements and certain other information filed with the SEC, as well as amendments thereto, free of charge from our web site. These documents are posted to our web site as soon as reasonably practicable after we have filed or furnished these documents with the SEC.

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      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 volumes based on relative heat content, 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.
	LPG. Liquefied petroleum gas.
	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.
	MMBOE. One million BOE.
	MMcf. One million cubic feet of gas.
	Net acres. Gross acres multiplied by the percentage working interest.
	Net oil and gas wells. Gross wells multiplied by the percentage working interest.
	Net production. Production that is owned, less royalties and production due others.

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	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 oil, gas and gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
	Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes: (i) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (ii) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
	Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
	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) oil, gas, and gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (iii) oil, gas, and gas liquids, that may occur in undrilled prospects; and (iv) oil, gas, and 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

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	a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
	Reserve life. A measure of the productive life of an oil and gas property or a group of properties, expressed in years. Reserve life is calculated by dividing proved reserve volumes at year-end by production for that year.
	Reserve replacement cost. The cost per BOE of reserves added during a period calculated by using a fraction, the numerator of which equals the costs incurred for the relevant property acquisition, exploration, exploitation and development and the denominator of which equals changes in proved reserves due to revisions of previous estimates, extensions, discoveries, improved recovery and other additions and purchases of reserves in-place.
	Reserve replacement ratio. The proved reserve additions for the period divided by the production for the period.
	Royalty. An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
	Standardized measure. The present value, discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying sales prices in effect as of the dates of such estimates and held constant throughout the productive life of the reserves (except for consideration of price changes to the extent provided by contractual arrangements), and deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on current costs and assuming continuation of existing economic conditions). Future income taxes are calculated by applying the statutory federal and state income tax rate to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to oil and gas operations.
	Undeveloped acreage. Acreage held under lease, permit, contract or option that is not in a spacing unit for a producing well.
	Upstream. The portion of the oil and gas industry focused on acquiring, exploiting, developing, exploring for and producing oil and gas.
	Waterflood. A secondary recovery operation in which water is injected into the producing formation to maintain reservoir pressure and force oil toward and into the producing wells.
	Working interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

      References herein to “Plains Resources”, “Plains”, the “Company”, “we”, “us” and “our” mean Plains Resources Inc.

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Items 1 and 2.     Business and Properties.

General

      We are an independent energy company. We are principally engaged in the “midstream” activities of marketing, gathering, transporting, terminaling, and storage of oil through our equity ownership in Plains All American Pipeline, L.P., or PAA. PAA is a publicly traded master limited partnership actively engaged in the midstream energy markets. As of March 15, 2003 we owned 44% of the general partner of PAA and 12.4 million, or 24%, of the limited partner units of PAA, which represented approximately 24% aggregate ownership interest in PAA. See “— Plains All American Pipeline, L.P.”. We also participate in the “upstream” activities of acquiring, exploiting, developing, exploring for and producing oil through our wholly-owned subsidiary, Calumet Florida L.L.C., which has producing properties in the Sunniland Trend in south Florida.

      The book value of our investment in PAA represents 43% of our total assets as of December 31, 2002 and the book value of our Florida oil properties represents 31%. As of December 31, 2002, the present value of our proved oil reserves was approximately $87.9 million (see “ — Oil Production Operations”). We own 6.6 million common units, 1.3 million Class B common units and 4.5 million subordinated units of PAA. The closing price of publicly traded PAA common units, as reported on the New York Stock Exchange, was $24.40 on December 31, 2002. The Class B common units and the subordinated units are not publicly traded but do receive cash distributions from PAA. PAA’s partnership agreement contains provisions which, upon the occurrence of certain future events, will result in the conversion of the subordinated units to common units. See — “Plains All American Pipeline, L.P. — PAA Cash Distributions”. PAA’s financial performance directly impacts our financial performance and the market value performance of PAA’s limited partner interests directly impacts the value of our assets. As a result, we encourage you to review PAA’s SEC filings, including its Annual Report on Form 10-K for the year ended December 31, 2002, to review and assess, among other things, PAA’s financial performance and financial condition, PAA’s business, operations, and competition, and risk factors associated with PAA’s business.

      We also have an active treasury share repurchase program. Our Board of Directors has authorized the repurchase of up to eight million shares of our common stock. Through December 31, 2001, we had repurchased a total of 4.1 million shares at a total cost of approximately $91.3 million. No shares were repurchased in 2002. We have resumed making purchases under the treasury share program and through March 15, 2003 we have repurchased an additional 142,700 shares at a total cost of $1.6 million. We intend to make additional repurchases in 2003 and expect to fund the purchases from cash flows.

Spin-off of Plains Exploration & Production Company

      Prior to December 18, 2002 Plains Exploration & Production Company, or PXP, was our wholly owned subsidiary. On December 18, 2002 we distributed the issued and outstanding shares of PXP common stock to the holders of record of our common stock as of the close of business on December 11, 2002. Each of our stockholders received one share of PXP common stock for each share of our common stock held. Prior to the spin-off, we made an aggregate of $52.2 million in cash contributions to PXP and transferred certain assets and liabilities to PXP, primarily related to land, unproved oil and gas properties, office equipment and pension obligations.

      In contemplation of the spin-off, under the terms of a Master Separation Agreement between us and PXP, on July 3, 2002 we contributed to PXP 100% of the capital stock of our wholly owned subsidiaries that own oil and gas properties in offshore California and Illinois. As a result, PXP indirectly owned our offshore California and Illinois properties and directly owned our onshore California properties. We also contributed $256.0 million of intercompany receivables that PXP and its subsidiaries owed to us. On July 3, 2002 PXP issued $200 million of 8.75% Senior Subordinated

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      We received a letter ruling from the IRS on May 22, 2002, as supplemented on November 5, 2002, to the effect that the spin-off will qualify as a tax-free distribution. A letter ruling from the IRS, while generally binding on the IRS, may under certain circumstances be retroactively revoked or modified by the IRS. A letter ruling is based on the facts and representations presented in the request for that ruling. Generally, an IRS letter ruling will not be revoked or modified retroactively if there has been no misstatement or omission of material facts, the facts at the time of the transaction are not materially different from the facts upon which the IRS letter ruling was based, and there has been no change in the applicable law. We are not aware of any facts or circumstances that would cause the representations in the ruling request to be untrue or incomplete in any material respect.

      As a result of the spin-off the historical results of the operations of PXP are reflected in our financial statements as “discontinued operations”. Except as noted, discussions in this Form 10-K with respect to oil and gas operations relate to our activities other than the discontinued operations of PXP. In connection with the spin-off, we entered into certain agreements with PXP, see “— Spin-off Agreements” and “— Discontinued Operations”.

Plains All American Pipeline, L.P.

      As of March 15, 2003, our aggregate ownership interest in PAA was approximately 24%, which was comprised of (1) a 44% interest in the general partner of PAA, (2) 45%, or approximately 4.5 million, of the subordinated units and (3) 24%, or approximately 7.9 million, of the common units, including approximately 1.3 million class B common units.

      As a result of our June 2001 strategic restructuring (see “— Our June 2001 Strategic Restructuring”), our minority interest in PAA is accounted for using the equity method of accounting effective January 1, 2001. Under this method, we no longer consolidate the assets, liabilities and operating activities of PAA. Rather, our ownership interest in PAA is reflected as an investment in the balance sheet and we record our share of PAA’s results of operations.

     Operations

      PAA is a publicly traded master limited partnership that is engaged in the marketing, transportation and terminalling of oil and the marketing of liquefied petroleum gas. Terminals are facilities where oil is transferred to or from storage or a transportation system, such as a pipeline, to another transportation system, such as trucks or another pipeline. The operation of these facilities is called “terminalling”. PAA is the exclusive purchaser/marketer of all of our equity oil production.

      PAA’s operations are concentrated in Texas, Oklahoma, California and Louisiana and in the Canadian provinces of Alberta and Saskatchewan, and can be categorized into two primary business activities:

	•	Oil Pipeline Transportation Operations. PAA owns and operates over 5,600 miles of gathering and mainline oil pipelines located throughout the United States and Canada. Its activities from pipeline operations generally consist of transporting oil for a fee, third party leases of pipeline capacity, barrel exchanges and buy/sell arrangements.
	•	Gathering, Marketing, Terminalling and Storage Operations. PAA owns and operates approximately 22.7 million barrels of above-ground oil terminalling and storage facilities, including tankage associated with its pipeline systems. These facilities include an oil terminalling and storage facility at Cushing, Oklahoma. Cushing is one of the largest oil market hubs in the United States and the designated delivery point for NYMEX oil futures

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		contracts. PAA’s terminalling and storage operations generate revenue through a combination of storage and throughput charges to third parties. PAA also utilizes its storage tanks to counter-cyclically balance its gathering and marketing operations and to execute different hedging strategies to stabilize profits and reduce the negative impact of oil market volatility. PAA’s gathering and marketing operations include:

	•	the purchase of oil at the wellhead and the bulk purchase of oil at pipeline and terminal facilities;
	•	the transportation of oil on trucks, barges and pipelines;
	•	the subsequent resale or exchange of oil at various points along the oil distribution chain; and
	•	the purchase of LPG from producers, refiners and other marketers, and the sale of LPG to wholesalers, retailers and industrial end users.

     PAA Cash Distributions

      PAA’s partnership agreement requires that it distribute 100% of available cash within 45 days after the end of each quarter to unitholders of record and to its general partner. Available cash is generally defined as all cash and cash equivalents on hand at the end of each quarter less reserves established by PAA’s general partner for future requirements.

      Distributions to holders of subordinated units are subject to the rights of holders of common units to receive the minimum quarterly distribution, or MQD, of $0.45 per unit ($1.80 per unit on an annual basis). Common units accrue arrearages with respect to distributions for any quarter during the subordination period and subordinated units do not accrue any arrearages. The subordination period will end if PAA meets certain financial tests for three consecutive four-quarter periods. If PAA meets certain financial requirements, 25% of the subordinated units will convert in the fourth quarter of 2003 and the remainder will convert in the first quarter of 2004.

      Class B common units are initially pari passu with common units with respect to distributions, and are convertible into common units upon approval of a majority of the common unitholders. If we request that PAA call a meeting of common unitholders to consider approval of the conversion of Class B units into common units and the approval is not obtained within 120 days, each Class B common unitholder will be entitled to receive distributions, on a per unit basis, equal to 110% of the amount of distributions paid on a common unit, with such distribution right increasing to 115% if such approval is not secured within 90 days after the end of the 120-day period. Except for the vote to approve the conversion, Class B common units have the same voting rights as the common units.

      PAA’s general partner is entitled to receive incentive distributions if the amount distributed with respect to any quarter exceeds levels specified in its partnership agreement. Generally the general partner is entitled, without duplication, to 15% of amounts PAA distributes in excess of $0.450 per unit, 25% of the amounts PAA distributes in excess of $0.495 per unit and 50% of amounts PAA distributes in excess of $0.675 per unit.

      Based on PAA’s current annual distribution rate of $2.15 per unit, we would receive for 2003 an annual distribution from PAA of approximately $30.1 million, including $2.8 million for our general partner distribution (including $1.8 million for the general partner incentive distribution).

Our June 2001 Strategic Restructuring

      On June 8, 2001, we sold a portion of our interests in PAA to a group of investors and management of PAA for approximately $155.2 million. The assets we sold in this restructuring included 52%, or approximately 5.2 million, of the subordinated units of PAA, at $22 per unit, and an aggregate 54% ownership interest in the general partner of PAA. We received approximately $110 million in cash and 23,108 shares of our series F preferred stock valued at $45.2 million as

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      As a result of our strategic restructuring, all of our series F preferred stock and all but approximately 36,000 shares of our series H preferred stock were retired or converted. The remaining outstanding shares of our series H preferred stock were converted into 1.2 million shares of our common stock during the third quarter of 2001.

      The excess of the fair value of our Series F preferred stock redeemed as consideration over the carrying value of such series F preferred stock ($21.4 million) was deemed for accounting purposes to be a dividend to our preferred stockholders. As a result, for purposes of determining our basic and diluted earnings per share, we deducted this amount in determining our income available to our common stockholders.

      In exchange for the significant value we received for the subordinated units (which are subordinated in right to distributions from PAA and are not publicly traded) relative to the then current market price of the publicly traded common units, we entered into a value assurance agreement with each of the purchasers of the subordinated units. The value assurance agreements require us to pay to the holders an amount per fiscal year, payable on a quarterly basis, equal to the difference between $1.85 per unit and the actual amount distributed during that period. The value assurance agreements will expire upon the earlier of the conversion of the subordinated units to common units, or June 8, 2006.

      Also in connection with our strategic restructuring:

	•	we appointed James C. Flores as our Chairman of the Board and Chief Executive Officer and we appointed a new Chief Operating Officer, Chief Financial Officer, and General Counsel and Secretary;
	•	certain of our employees received transaction-related bonuses and other payments and vested in benefits in accordance with the terms of our employee benefit plans;
	•	we entered into a separation agreement with PAA whereby, among other things, (1) we agreed to indemnify PAA, its general partner, and its subsidiaries against (a) any claims related to the upstream business, whenever arising, and (b) any claims related to federal or state securities laws or the regulations of any self-regulatory authority, or other similar claims, resulting from alleged acts or omissions by us, our subsidiaries, PAA, or PAA’s subsidiaries occurring on or before June 8, 2001, and (2) PAA agreed to indemnify us and our subsidiaries against any claims related to the midstream business, whenever arising;
	•	we entered into a pension and employee benefits assumption and transition agreement pursuant to which we and the general partner of PAA agreed to the transition of certain employees to the general partner, our provision of certain benefits with respect to the transfer, and our provision of transition-related services; and
	•	we agreed to contribute 287,500 subordinated units to the general partner of PAA to be used for performance option grants to officers and key employees of the general partner.

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Oil Production Operations

      We have a 100% working interest in five producing fields in the Sunniland Trend in south Florida. We acquired 50% of our interest in these fields in 1993 and the remaining 50% in 1994. At the time of our initial acquisition, production net to the 100% working interest averaged approximately 1,800 barrels of oil per day and proved reserves were approximately 10 MMBbls. In 2002 net production from these properties averaged 2,658 barrels of oil per day and proved reserves were 16.3 MMBbls at December 31, 2002. In 2002 we spent $3.4 million on capital projects, primarily facility enhancements and abandonment of inactive wells. In 2003 we expect to spend $3.7 million on artificial lift projects, facility upgrades and idle well abandonments.

      The following tables set forth certain information with respect to the reserves of our Florida properties based upon reserve reports prepared by the independent petroleum consulting firm of Netherland, Sewell & Associates, Inc. The reserve volumes and values were determined under the method prescribed by the Securities and Exchange Commission, or SEC, which requires the application of year-end prices for each year, held constant throughout the projected reserve life. The amounts presented exclude reserves attributable to discontinued operations (see Note 20 to the consolidated financial statements).

(1)	The PV-10 and standardized measure have been reduced to reflect applicable abandonment costs. PV-10 represents the standardized measure before deducting estimated future income taxes.
(2)	Price in effect at year end with adjustments based on location and quality of oil.

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      There are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reservoir engineering is a subjective process of estimating the recovery from underground accumulations of oil that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree speculative, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil 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 Present Value of Proved Reserves shown above represents estimates only and should not be construed as the current market value of the estimated oil reserves attributable to our properties. The information set forth in the preceding tables includes revisions of reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent exploitation and development activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. 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”.

      In accordance with the SEC guidelines, the reserve engineers’ estimates of future net revenues from our properties and the present value thereof are made using oil sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. The oil price in effect at December 31, 2002 is based on the year-end oil price with variations based on location and quality of oil. The overall average year-end price used in the reserve report as of December 31, 2002 was $20.25 per barrel of oil. See “Product Markets and Major Customers”. Historically, the prices for oil have been volatile and are likely to continue to be volatile in the future. 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”.

      Since December 31, 2001, we have not filed any estimates of total proved net oil reserves with any federal authority or agency other than the SEC.

Productive Wells and Acreage

      As of December 31, 2002, we had working interests in 16 gross (16 net) active producing oil wells. At December 31, 2002 we had working interests in 12,025 gross, 12,025 net, developed acres and 73,842 gross, 71,627 net, undeveloped acres, all located in the state of Florida. Less than 10% of total net undeveloped acres are covered by leases that expire in the next five years.

Drilling Activities

      No wells were drilled in 2002. In 2001 we participated in 1 gross (0.5 net) dry exploratory well on a property outside Florida. In 2000 we drilled 2 gross (2 net) productive oil development wells on our Florida properties.

Production and Sales

      The following table presents certain information with respect to oil production and sales attributable to our properties, the revenue derived from the sale of such production, average sales

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(1)	Oil transportation costs are included in costs and expenses in the consolidated statement of income.

      PAA is the exclusive purchaser of all of our equity oil production. We are currently negotiating a new oil marketing agreement with PAA to, among other things, add a definitive term to the agreement and provide that PAA will use its reasonable best efforts to obtain the best price for our oil production. There can be no assurance, however, that we will enter into a new oil marketing agreement with PAA.

Product Markets and Major Customers

      Our revenues are highly dependent upon the prices of, and demand for, oil. Historically, the markets for oil have been volatile, and are likely to continue to be volatile in the future. The prices we receive for our oil production and the levels of such production are subject to wide fluctuations and depend on numerous factors beyond our control, including the condition of the United States and world economies (particularly the manufacturing sector), foreign imports, political conditions in other oil-producing countries, the actions of the Organization of Petroleum Exporting Countries and domestic government regulation, legislation and policies. Decreases in the prices of oil 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. 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”.

      To manage our exposure to commodity price risks, we utilize various derivative instruments to hedge our exposure to price fluctuations on oil sales. Our hedging arrangements provide us protection on the 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 revenue on the hedged volumes than we would receive in the absence of hedges. See Item 7A — “Quantitative and Qualitative Disclosures about Market Risks”.

      Substantially all of our production is transported by pipelines, trucks and barges 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 production.

      PAA is the exclusive purchaser of all of our equity oil production. The following table reflects for the year ended December 31, 2000, during which period PAA was consolidated in our financial

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(1)	Pertains to operations of PAA. Represents percent of oil and gas sales revenues plus marketing, transportation, storage and terminalling revenues.
(2)	Represents entities that purchased our equity oil production from PAA.

      If we were to lose PAA as the exclusive purchaser of our equity production, we believe such loss would not have a material adverse effect on our results of operations. We believe PAA could be replaced by other purchasers under contracts with similar terms and conditions.

      We recommend you review PAA’s Annual Report on Form 10-K for the year ended December 31, 2002, and other applicable SEC filings by PAA, for a discussion of PAA’s major customers.

Competition

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

      We recommend you review PAA’s Annual Report on Form 10-K for the year ended December 31, 2002, and other applicable SEC filings by PAA, for a discussion of PAA’s competition.

Regulation

      We recommend you review PAA’s Annual Report on Form 10-K for the year ended December 31, 2002, and other applicable SEC filings by PAA, for a discussion of regulations related to the midstream business. Our discussion on regulation below relates primarily to our upstream business.

      Our upstream 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 such rules and regulations can result in substantial penalties. The regulatory burden on the oil 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.

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     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 U.S. Environmental Protection Agency, or EPA, 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.

     Regulation of Production

      The production of oil and gas is subject to regulation 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 State of Florida has 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. Florida also has the right to restrict production to the market demand for oil and gas. Moreover, Florida imposes an ad valorem, production or severance tax with respect to production and sale of oil and gas within its jurisdiction.

     Pipeline Regulation

      In our upstream business, we have pipelines to deliver our production to sales points. Our pipelines are subject to certain regulations of the U.S. Department of Transportation, or DOT. 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. We believe that our pipeline operations are in substantial compliance with applicable requirements.

     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 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 the oil and gas 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 such laws and regulations on our operations. If a person violates these environmental laws and regulations and any

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      Although we obtained environmental studies on our properties in Florida, and we believe that such properties have been operated in accordance with standard oil field practices, current or future local, state and federal environmental laws and regulations may require substantial expenditures to remediate the properties or to otherwise comply with such rules and regulations.

      A portion of our Florida properties are located within the Big Cypress National Preserve and our operations therein are subject to regulations administered by the National Park Service, or NPS. Under such regulations, a master plan of operations has been approved by the Regional Director of the NPS. The master plan of operations is a comprehensive plan of practices and procedures for our drilling and production operations designed to minimize the effect of such operations on the environment. We must modify the master plan of operations and secure permits from the NPS for new wells that require the use of additional land for drilling operations. The master plan of operations also requires that we restore the surface property affected by drilling and production operations upon cessation of these activities. We do not anticipate that expenditures required to comply with such regulations will have a material adverse effect on our operations.

Other Business Matters

      Without successful drilling, acquisition or exploitation operations, our oil and gas reserves and revenues will decline. Drilling activities are subject to numerous risks, including the risk that no commercially viable oil or gas production will be obtained. Our decision to purchase, explore, exploit or develop an interest or property will depend in part on the evaluation of data obtained through geophysical and geological analyses and engineering studies, the results of which are often inconclusive or subject to varying interpretations. See “— Oil and Gas Reserves”. The cost of drilling, completing and operating wells is often uncertain. Drilling may be curtailed, delayed or canceled as a result of many factors, including title problems, weather conditions, compliance with government permitting requirements, shortages of or delays in obtaining equipment, reductions in product prices or limitations in the market for products. The availability of a ready market for our oil production also depends on a number of factors, including the demand for and supply of oil and the proximity of reserves to pipelines or trucking and terminal facilities. See “— Product Markets and Major Customers”.

      Substantially all of our oil production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services to us for a reasonable fee could cause us to seek transportation alternatives, which in turn could result in increased transportation costs to us or involuntary curtailment of a significant portion of our oil and gas production.

      Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and gas, including blowouts, cratering, oil spills and fires, each of which could result in damage to or destruction of oil and gas wells, production facilities or other property, or injury to persons. The relatively deep drilling conducted by us from time to time involves increased drilling risks of high pressures and mechanical difficulties, including stuck pipe, collapsed casing and separated cable.

      Our upstream properties may experience damage as a result of an accident or other natural disaster. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damages and suspension of operations. We maintain insurance of various types that we consider to be adequate to cover our upstream operations and properties. The insurance covers all of our upstream assets in amounts

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      The occurrence of a significant event not fully insured or indemnified against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe that we are adequately insured for public liability and property damage to others with respect to our operations. With respect to all of our coverage, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable.

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 interferes with the use of such 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, minimal investigation of title is made at the time of acquisition of undeveloped properties. Title investigation is made and title opinions of local counsel are generally obtained only before commencement of drilling operations. We believe that we have satisfactory title to all of our other assets. Although title to such properties are subject to encumbrances in certain cases, such as customary interests generally retained in connection with acquisition of real property, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens and minor easements, restrictions and other encumbrances to which the underlying properties were subject at the time of acquisition by us, we believe that none of such burdens will materially detract from the value of such properties or from our interest therein or will materially interfere with their use in the operation of our business.

Spin-off Agreements

      In connection with the spin-off of PXP, we entered into the following agreements:

     Master Separation Agreement

      Overview. We entered into a master separation agreement on July 3, 2002 with PXP. The master separation agreement provides for the separation of substantially all of our upstream assets and liabilities, other than our Florida operations. The master separation agreement provides for, among other things:

	•	the separation;
	•	cross-indemnification provisions;
	•	allocation of fees related to these transactions between us and PXP;
	•	other provisions governing our relationship with PXP, including mandatory dispute arbitration, sharing information, confidentiality and other covenants;
	•	a noncompetition provision; and
	•	us entering into the ancillary agreements discussed below with PXP.

      Separation. To effect the separation, on July 3, 2002, we transferred to PXP assets and liabilities related to our upstream business other than our Florida operations, including the capital stock of Arguello Inc., Plains Illinois Inc., PMCT, Inc. and Plains Resources International Inc.,

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      We agreed to take such further actions as PXP may reasonably request to more effectively complete the transfers of assets and liabilities described above, to protect and enjoy all rights and benefits we 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 PXP for all liabilities associated with the current and historical businesses and operations PXP conducts after giving effect to the separation, regardless of the time those liabilities arise, and to place sole financial responsibility for liabilities associated with our other businesses with us and our other subsidiaries. The master separation agreement also contains indemnification provisions under which we and PXP 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 PXP against liabilities arising from misstatements or omissions in the various offering documents for the exchange offer related to PXP’s 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 us. PXP agrees to indemnify us and our other subsidiaries against liabilities arising from misstatements or omissions in the various offering documents for the exchange offer related to PXP’s 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 and provided by us for inclusion in such documents.

      The master separation agreement contains a general release under which we released PXP, and PXP released us and our subsidiaries, affiliates, successors and assigns from any liabilities arising from events between us or our subsidiaries on the one hand, and PXP on the other hand, occurring on or before the separation, including events in connection with activities to implement the separation and the spin-off. The general release does not apply to obligations under the master separation agreement or any ancillary agreement, to liabilities transferred to PXP, to future transactions between us and PXP, or to specified contractual arrangements.

      Other provisions. The master separation agreement also provides for: (1) mandatory arbitration to settle disputes between us, and our subsidiaries, and PXP; (2) exchange of information between PXP 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 PXP 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 PXP 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) we and our 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) PXP will be prohibited from engaging in any of the “midstream” activities of marketing, gathering, transporting, terminalling and

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     Employee Matters Agreement

      The employee matters agreement provided that those employees who work for PXP after the spin-off were transferred to PXP 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 our common stock at the time of the spin-off were “split” into (1) an equal number of options to acquire our common stock and (2) an equal number of stock appreciation rights, or SARs, with respect to PXP common stock.

      The exercise price for our original stock options was also “split” between our new stock options and the SARs based on the relationship of the closing price (with dividend) of our common stock on the spin-off date ($23.05 per share) less the closing price (on a “when-issued” basis) of PXP common stock on the spin-off date ($9.10 per share), both as reported on the NYSE, and such closing price of PXP common stock ($9.10 per share).

      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 our common stock were “split” into (1) restricted stock awards for an equal number of shares of our common stock and (2) restricted stock awards for an equal number of shares of PXP common stock. An employee’s or a director’s service with PXP counts towards the vesting of their “split” Plains Resources stock options and restricted stock awards even though the employee is no longer employed by us or the director no longer serves on our board of directors. With respect to employees and directors who stay with us, their service at Plains Resources counts towards the vesting of their SARs even though they are not employed by PXP or do not serve on PXP board of directors.

      Unless a person is employed by or serves as a director for both PXP 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 PXP 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) PXP established a nonqualified deferred compensation plan for certain executive officers and, to the extent that any of the executives are participants in our deferred compensation plan, the related assets and liabilities under our plan were transferred to the PXP plan, (2) we transferred our 401(k) plan and welfare benefit plans to PXP and formed a similar 401(k) plan and similar welfare benefit plans, and (3) PXP established plans that mirror our fringe benefits and company policies.

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

     Tax Allocation Agreement

      On July 3, 2002, we entered into the tax allocation agreement, which we and PXP amended and restated on November 20, 2002. This agreement provides that, until the spin-off, PXP continued to be included in our consolidated federal income tax group, and PXP’s federal income tax liability was included in our consolidated federal income tax liability. The amount of taxes that PXP pays or receives with respect to our consolidated or combined returns in which PXP is included generally are to be determined by multiplying PXP’s net taxable income included in our consolidated tax return by the highest marginal tax rate applicable to the income. We are not required to pay PXP for the use

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      In general, the agreement provides that PXP is included in our 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 PXP during the period in which PXP is included in our consolidated group, PXP could be liable if any federal tax liability is incurred, but not discharged, by any other member of our consolidated group. In addition, to the extent our net operating losses are used in the consolidated return to offset PXP’s taxable income from operations during the period January 1, 2002 through the spin-off, PXP will reimburse us for the reduction in PXP’s federal income tax liability resulting from the utilization of such net operating losses, but such reimbursement shall not exceed $3 million exclusive of any interest accruing under the agreement. A receivable from PXP for $3.0 million is reflected in Other Assets in our consolidated balance sheet at December 31, 2002 for the use of our net operating losses.

      Under the terms of this agreement, PXP agrees to indemnify us if the spin-off is not tax-free to us as a result of various actions taken by PXP or with respect to PXP’s failure to take various actions.

      In addition, PXP agrees that, during the three-year period following the spin-off, without our prior written consent, PXP will not engage in transactions that could adversely affect the tax treatment of the spin-off unless it obtains a supplemental tax ruling from the IRS or a tax opinion acceptable to us 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 us to ensure PXP would be able to comply with its obligation under this agreement.

      PXP also agrees 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 we will transfer to PXP 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, PXP will grant to us 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 PXP’s written consent, except that we may grant our subsidiaries sublicenses to use the Plains Marks.

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

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

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     Plains Exploration & Production Transition Services Agreement

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

	•	management services, including managing PXP’s operations, evaluating investment opportunities for PXP, overseeing PXP’s upstream activities, and staffing;
	•	tax services, including preparing tax returns and preparing financial statement disclosures;
	•	accounting services, including maintaining general ledgers, preparing financial statements and working with PXP’s auditors;
	•	payroll services, including payment processing and complying with regulations relating to payroll services;
	•	insurance services, including maintaining for the interim period the existing insurance that we provide for PXP;
	•	employee benefits services, including administering and maintaining the employee benefit plans that cover PXP’s employees;
	•	legal services, including typical and customary legal services; and
	•	financial services, including helping PXP raise capital, preparing budgets and executing hedges.

      Through December 31, 2002 we have charged PXP $10.8 million of the $30.0 million allowed under this agreement to reimburse us for our costs of providing such services. We will continue to provide services under this agreement until June 16, 2003, unless we and PXP decide to terminate the agreement earlier. We do not expect to make significant additional charges to PXP under this agreement.

      This transition services agreement provides that we will not be liable to PXP 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 PXP for any liabilities arising from such gross negligence or misconduct. PXP will indemnify us for any liabilities arising directly from the performance of the services by us, 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.

     Plains Resources Transition Services Agreement

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

	•	tax services, including preparing tax returns and preparing financial statement disclosures;
	•	accounting services, including maintaining general ledgers, preparing financial statements and working with our auditors;
	•	payroll services, including payment processing and complying with regulations relating to payroll services;
	•	employee benefits services, including administering and maintaining the employee benefit plans that cover our employees;

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	•	legal services, including typical and customary legal services; and
	•	financial services, including helping us raise capital, preparing budgets and executing hedges.

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

	•	the Plains Resources transition services agreement does not cover management services, insurance services or operational services;
	•	the tax services provided under the Plains Resources transition services agreement are not subject to the tax allocation agreement; and
	•	the legal services provided under the Plains Exploration & Production transition services agreement include legal services that we have historically provided for us and our subsidiaries.

      PXP will charge us on a monthly basis its costs of providing such services. No amounts had been charged under this agreement through December 31, 2002.

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

      PXP will be obligated to provide the services with substantially the same degree of care as it employs for its own operations. PXP may change the manner in which it provides the services so long as it deems such change to be necessary or desirable for its own operations.

      This transition services agreement provides that PXP 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. PXP will indemnify us for any liabilities arising from such gross negligence or misconduct. We will indemnify PXP for any liabilities arising directly from PXP’s performance of the services, except for liabilities caused by PXP’s gross negligence or willful misconduct. PXP disclaims all warranties and makes 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 PXP decide to terminate the agreement earlier. We and PXP 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 PXP, PXP 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.

      We will reimburse PXP for its costs to provide these services. No amounts had been charged under this agreement through December 31, 2002.

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

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      We and PXP may agree to specific performance metrics that it must meet. Where no metrics are provided, PXP 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 it exercises in performing similar services for its subsidiaries, and (3) in cases where there is common personnel, equipment or facilities for services provided to PXP’s subsidiaries and us, not favor us or PXP’s subsidiaries over the other. PXP may change the manner in which it provides the services so long as it is making similar changes to the services it provides to its subsidiaries. PXP is not obligated to provide any service to the extent it is impracticable as a result of causes outside of its control.

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

      PXP will provide the services until (1) Calumet is no longer our subsidiary, (2) Calumet transfers substantially all of its assets to a person that is not a subsidiary of us, (3) the third anniversary of the date of this agreement or (4) when all the services are terminated as provided in the agreement. We may terminate the agreement as to some or all of the services at any time by giving PXP at least 90 days’ written notice.

Employees

      As of February 28, 2003, we had 14 full-time employees (not including our Chief Executive Officer and Chief Financial Officer, who also devote a portion of their time and efforts to PXP), none of whom is represented by any labor union. Of such full-time employees, 12 are field personnel involved in oil and gas producing activities.

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 ad financial condition, as well as adversely affect the value of an investment in our common stock.

      As of December 31, 2002, the present value of our proved oil reserves was approximately $87.9 million. We own 6.6 million common units, 1.3 million Class B common units and 4.5 million subordinated units of PAA. The closing price of publicly traded PAA common units, as reported on the New York Stock Exchange, was $24.40 on December 31, 2002. The Class B common units and the subordinated units are not publicly traded but do receive cash distributions from PAA. PAA’s partnership agreement contains provisions which, upon the occurrence of certain future events, will result in the conversion of the subordinated units to common units. In 2002, we had oil revenues of $18.7 million while distributions received from PAA attributable to our general and limited partner interests totaled $29.1 million.

      PAA’s financial performance will directly affect our financial performance and the market value performance of PAA’s limited partner interests will directly impact the value of our assets. A significant decline in PAA’s earnings would have a corresponding negative impact on our earnings. Likewise, a significant decline in the value of PAA’s common units would have a corresponding negative impact on the value of our assets.

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      In addition, cash from PAA distributions on its general partner and limited partner interests is one of our primary sources of liquidity. If PAA could not, for any reason, make its minimum quarterly distribution payments on its limited partner and general partner interests, this would impair our ability to meet our short and long-term cash needs, including normal recurring operating needs, debt service obligations, contingencies and capital expenditures. Further, PAA’s inability to make its minimum quarterly distribution payments would trigger our payment obligations under the value assurance agreements, which would compound the negative impact on our ability to meet our short and long-term capital needs.

      We have also entered into an oil marketing agreement with PAA under which PAA is the exclusive purchaser of all of our net oil production. We generally do not require letters of credit or other collateral form 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.

      We urge you to review PAA’s SEC filings, including its Annual Report on Form 10-K for the year ended December 31, 2002, for risks associated with PAA’s business.

      We have a substantial amount of debt and the ability to incur substantially more debt. We have a $45.0 million secured term loan facility, which is collateralized by a pledge of the equity of our subsidiaries and 4,950,000 of our PAA common units. The term loan is repayable in 10 quarterly installments of $4.5 million each commencing on February 28, 2003 with a final maturity on May 31, 2005.

      We and all of our subsidiaries must comply with various covenants contained in our secured term loan facility, which, among other things, limit the ability of us and our subsidiaries to:

	•	incur additional debt or liens;
	•	enter into leases;
	•	sell assets;
	•	make loans or investments;
	•	change the nature of our business or operations;
	•	guarantee other indebtedness;
	•	enter into certain types of hedge agreements;
	•	enter into take-or-pay arrangements;
	•	merge or consolidate; and
	•	enter into transactions with affiliates.

      In addition, if an event of default exists, the term loan prohibits us from paying dividends or repurchasing or redeeming shares of any class of our capital stock.

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

	•	increase our vulnerability to general adverse economic and industry conditions;
	•	limit our ability to fund future working capital and capital expenditures, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flow to payments on our debt or to comply with any restrictive terms of our debt;

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	•	limit our flexibility in planning for, or reacting to, changes in the industry in which we operate; and
	•	place us at a competitive disadvantage as compared to our competitors that have less debt.

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

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

	•	supply and demand for oil and expectations regarding supply and demand;
	•	weather;
	•	actions by the Organization of Petroleum Exporting Countries, or OPEC;
	•	political conditions in other oil-producing countries including the possibility of insurgency or war in such areas;
	•	general economic conditions in the United States and worldwide; and
	•	governmental regulations.

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

	•	our revenues, cash flows and earnings;
	•	our ability to attract capital to finance our operations and the cost of such capital;
	•	the amount that we are allowed to borrow; and
	•	the value of our oil and gas properties.

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

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      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 future success depends in part 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.

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

	•	inadequate capital or other factors, such as title problems;
	•	weather;
	•	compliance with governmental regulations or price controls;
	•	mechanical difficulties; or
	•	shortages or delays in the delivery of equipment.

      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 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.

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      The proved oil 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 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:

	•	historical production from the area compared with production from other comparable producing areas;
	•	the assumed effects of regulations by governmental agencies;
	•	assumptions concerning future oil and gas prices; and
	•	assumptions concerning future operating costs, severance and excise taxes, development costs and workover and remedial costs.

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

	•	the quantities of oil and gas that are ultimately recovered;
	•	the timing of the recovery of oil and gas reserves;
	•	the production and operating costs incurred; and
	•	the amount and timing of future development expenditures.

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

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

	•	the amount and timing of actual production;
	•	supply and demand for oil and gas; and
	•	changes in governmental regulations or taxation.

      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.

      All of our oil reserves are located in Florida. 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,

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

	•	well blowouts;
	•	cratering;
	•	explosions;
	•	uncontrollable flows of oil, gas or well fluids;
	•	fires;
	•	pollution; and
	•	releases of toxic gas.

      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.

      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. 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 incur liability at a time when we are not able to obtain liability insurance, then our business, results of operations and financial condition could be materially adversely affected.

      Our business is subject to federal, state and local laws and regulations as interpreted by governmental agencies and other bodies, including those in Florida, 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.

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

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	•	well drilling or workover, operation and abandonment;
	•	waste management;
	•	land reclamation;
	•	financial assurance under the Oil Pollution Act of 1990; and
	•	controlling air, water and waste emissions.

      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.

      Our growth strategy may include acquiring midstream and upstream 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:

	•	diversion of management’s attention;
	•	the need to integrate acquired operations;
	•	potential loss of key employees of the acquired companies;
	•	potential lack of operating experience in a geographic market of the acquired business; and
	•	an increase in our expenses and working capital requirements.

      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.

      In addition, under the spin-off agreements, until July 3, 2005, we are prohibited from acquiring any upstream business or properties in the United States outside of Florida. Thus, until after July 3, 2005, our upstream acquisition prospects are limited to Florida and outside of the United States.

      We reduce our exposure to the volatility of oil prices by actively hedging a portion of our production. Hedging also prevents us from receiving the full advantage of increases in oil 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

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      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.

      Because certain of our officers and directors provide services to PXP, conflicts of interest could arise between PXP, on the one hand, and us, on the other. Additionally, some of these officers and directors own and are awarded from time to time shares, or options to purchase shares, or stock appreciation rights of PXP. Accordingly, their financial interests may not always be aligned with ours 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 PXP.

      If we experience a change of control, fail to continue the active conduct of our trade or business or fail to comply with the representations underlying our tax ruling or supplemental tax ruling relating to the spin-off, the tax-free treatment of the spin off might be lost. If there are any corporate level taxes incurred by us as a result of the spin-off for any other reason, we would be responsible for 50% of any such liability and PXP would be responsible for the remaining 50%. The amount of any tax payments would be substantial and may result in events of default under our loan facility. 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 discussed above, we may be highly limited in our ability to take the following steps in the future:

	•	issue equity in public or private offerings;
	•	issue equity as part of the consideration in acquisitions of additional assets; or
	•	undergo a change of control.

Item 3.     Legal Proceedings

      On September 18, 2002 Stocker Resources Inc., or Stocker, which was the general partner of PXP before it was 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 filed 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. Stocker was merged into us in December 2002. Under our master separation agreement with PXP, we are indemnified for damages we incur as a result of this action. We intend to defend our rights vigorously in this matter.

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      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 Resources

      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, Executive Chairman of the Board since December 2002. He was our Chairman of the Board and Chief Executive Officer from May 2001 to 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. Mr. Flores has been Chairman of the Board, Chief Executive Officer and a Director of PXP since September 2002.

      William M. Hitchcock, age 63, Director since 1977. Mr. Hitchcock is a partner and has been President, since December 1996, of Pembroke Capital LLC, an investment firm. In addition, he is Chief Executive Officer of Camelot Oil & Gas, a private oil and gas company. He is also a director of Maxx Petroleum, Ltd., an oil and gas company, Thoratec Laboratories Corporation, a medical device company, and Luna Imaging, Inc., a digital imaging company. From 1992 to 1995, Mr. Hitchcock served as President of Plains Resources International Inc., which was formerly one of our wholly-owned subsidiaries. In addition, he was our Chairman of the Board from August 1981 to October 1992, except for the period from April 1987 to October 1987, when he served as our Vice Chairman.

      D. Martin Phillips, age 49, Director since June 2001. Mr. Phillips has been a Managing Director and principal of EnCap Investments L.L.C., or EnCap, a funds management and investment banking firm that focuses exclusively on the oil and gas industry, since November 1989. From 1978 to when he joined EnCap, Mr. Phillips served as Senior Vice President in the Energy Banking Group of NCNB Texas National Bank in Dallas, Texas. Mr. Phillips also serves as a director of Mission Resources Corporation, Breitburn Energy Company LLC, 3TEC Energy Corporation and the Houston Producers’ Forum, of which he formerly served as president.

      Robert V. Sinnott, age 53, Director since 1994. Mr. Sinnott has been Senior Vice President of Kayne Anderson Investment Management, Inc., an investment management firm, since 1992. He is also a director of Glacier Water Services, Inc., a vended water company, and Plains All American GP LLC, which is the general partner of Plains AAP, L.P., which is in turn the general partner of Plains All American Pipeline, L.P., or PAA. Mr. Sinnott was Vice President and Senior Securities Officer of the Investment Banking Division of Citibank from 1986 to 1992.

      J. Taft Symonds, age 63, Director since 1987. Mr. Symonds has been Chairman of the Board of Symonds Trust Co. Ltd., an investment firm, and Chairman of the Board of Maurice Pincoffs Company, Inc., an international marketing firm, since 1978. He is also Chairman of the Board of Tetra Technologies, Inc., a specialty chemical and chemical process company, and a director of

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     Executive Officers

      John T. Raymond, age 32, Chief Executive Officer and President since December 2002. Mr. Raymond served as our President and Chief Operating Officer from November 2001 to December 2002 and as 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 LP, which is the general partner of PAA. Mr. Raymond has also been President and Chief Operating Officer of PXP since September 2002.

      Stephen A. Thorington, age 47, Executive Vice President and Chief Financial Officer since February 2003. He served as Acting Executive Vice President and Chief Financial Officer from December 2002 to February 2003 when he was appointed to his current position. Mr. Thorington has also been Executive Vice President and Chief Financial Officer of PXP since September 2002. 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.

      Franklin R. Bay, age 45, is our Senior Vice President of Corporate Development, Chief Legal Officer and Secretary. Mr. Bay has been our Senior Vice President of Corporate Development since February 2002, and he was appointed as Chief Legal Officer and Secretary in December 2002. Pursuant to a transaction services agreement between us and PXP, Mr. Bay also provides some corporate development services to PXP. Prior to joining Plains, Mr. Bay served in various capacities with Enron Corp. for approximately five years, including Vice President of Commercial Operations for Northern Natural Gas Pipeline Company, General Counsel of the Gas Pipeline Group and Head of Broadband Services Emerging Business Group. His previous experience also includes serving in the first Bush Administration as the Deputy General Counsel at the Department of Energy and Deputy Legal Adviser at the State Department. Additionally, he practiced law for nine years with Fulbright & Jaworski and Hutcheson & Grundy and he previously served as a second lieutenant in the United States Marine Corps.

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

Price Range of Common Stock

      Our common stock is listed and traded on the New York Stock Exchange under the symbol “PLX”. Prior to December 21, 2001 our common stock was traded on the American Stock Exchange. The number of stockholders of record of our common stock as of February 28, 2003 was 1,046.

      The following table sets forth the range of high and low closing sales prices for our common stock as reported on the applicable Stock Exchange Composite Tapes for the periods indicated below.

Dividend Policy

      We have not paid cash dividends on shares of our common stock since our inception and do not anticipate paying any cash dividends on our common stock in the foreseeable future. In addition, the amount of dividends we can pay is restricted by provisions of our loan facility.

Series D Cumulative Convertible Preferred Stock

      We have outstanding 46,600 shares of Series D Cumulative Convertible Preferred Stock, or Series D Preferred, that have an aggregate stated value of $23.3 million and are redeemable at our option at 140% of stated value. If not previously redeemed or converted, the Series D Preferred will automatically convert into shares of common stock in 2012. Each share of Series D Preferred has a stated value of $500 and bears an annual dividend of $30.00 per share, paid on a quarterly basis.

      As a result of the spin-off, the number of shares of our common stock into which the Series D Preferred is convertible increased from 932,000 shares to 1,671,416 shares as a result of the reduction in the conversion price from $25.00 per share of common stock to $13.94 per share. The reduction in the conversion price of the Series D Preferred was determined by multiplying the former conversion price of the Series D Preferred ($25.00) by a fraction, the denominator of which was $22.27 (the closing price per share of our common stock as of the record date for the spin-off), and the numerator of which was $12.42 (the closing price per share of our common stock as of the record date for the spin-off less the agreed on fair market value per share of the PXP common stock distributed in the spin-off). The holder of the Series D Preferred did not receive any PXP securities as a result of the spin off.

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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. As a result of the reduction in our ownership interest in PAA in 2001, our investment in PAA is accounted for using the equity method of accounting effective January 1, 2001. In prior periods, PAA is included on a consolidated basis. As a result of the spin-off the historical results of the operations of PXP are reflected in our financial statements as “discontinued operations”. This selected financial data should be read in conjunction with the consolidated financial statements, including the notes thereto, and “Item 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations” (in thousands, except per share information).

(table and footnotes continued on following page)

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(1)	Relates to the sale of assets by PAA.
(2)	Relates to losses resulting from unauthorized trading activity by a former employee of PAA.
(3)	Amounts in 2002 and 1999 relate to public offerings by PAA. Amount in 2001 relates to sale of a portion of our interest in PAA and public offering by PAA. Amount in 1998 relates to formation of PAA.
(4)	Amount for 2001 includes a $21.4 million deemed dividend and a $2.5 million cash payment related to the redemption and conversion of series F preferred stock in connection with our strategic restructuring. See Items 1 and 2 — “Business and Properties — Our June 2001 Strategic Restructuring”.
(5)	PAA was formed in 1998 and its first distributions were paid in 1999.

      The following information should be read in connection with the information contained in the consolidated financial statements and notes thereto included elsewhere in this report.

      We are an independent energy company. We are principally engaged in the “midstream” activities of marketing, gathering, transporting, terminalling, and storage of oil through our equity ownership in PAA. PAA is a publicly traded master limited partnership actively engaged in the midstream energy markets. As of March 15, 2003 we owned 44% of the general partner of PAA and 12.4 million limited partner units of PAA, which represented approximately 24% aggregate ownership interest in PAA. We also participate in the “upstream” activities of acquiring, exploiting, developing, exploring for and producing oil through our wholly-owned subsidiary, Calumet Florida L.L.C., which has producing properties in the Sunniland Trend in south Florida.

      The book value of our investment in PAA represents 43% of our total assets as of December 31, 2002 and the book value of our Florida oil properties represents 31%. As of December 31, 2002, the present value of our proved oil reserves was approximately $87.9 million (see “— Oil Production Operations”). We own 6.6 million common units, 1.3 million Class B common units and 4.5 million subordinated units of PAA. The closing price of publicly traded PAA common units, as reported on the New York Stock Exchange, was $24.40 on December 31, 2002. The Class B common units and the subordinated units are not publicly traded but do receive cash distributions from PAA. PAA’s partnership agreement contains provisions which, upon the occurrence of certain future events, will result in the conversion of the subordinated units to common units. See — “Plains All American Pipeline, L.P. — PAA Cash Distributions”. PAA’s financial performance directly impacts our financial performance and the market value performance of PAA’s limited partner interests directly impacts the value of our assets. As a result, we encourage you to review PAA’s SEC filings, including its Annual Report on Form 10-K for the year ended December 31, 2002, to review and assess, among other things, PAA’s financial performance and financial condition, PAA’s business, operations, and competition, and risk factors associated with PAA’s business.

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Spin-off of Plains Exploration & Production Company

      On December 18, 2002 we distributed 100% of the issued and outstanding shares of common stock of PXP, to the holders of record of our common stock as of the close of business on December 11, 2002. Each stockholder received one share of PXP common stock for each share of our common stock held. Prior to the spin-off, we borrowed $45 million under a new term loan facility and used a portion of the proceeds to make a $40 million cash capital contribution to PXP. In addition, prior to the spin-off we made a $7.2 million cash contribution to PXP and transferred to PXP certain assets and PXP assumed certain liabilities, primarily related to land, unproved oil and gas properties, office equipment and pension obligations.

      We received a favorable private letter ruling from the IRS 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. The spin-off was completed to, among other things:

	•	allow us to obtain cost savings through improved access to capital markets for our midstream affiliate, PAA;
	•	allow PXP and us to focus corporate strategies and management teams for each business; and
	•	simplify our corporate structure.

      In contemplation of the spin-off, under the terms of a Master Separation Agreement between us and PXP, on July 3, 2002 we contributed to PXP 100% of the capital stock of our wholly owned subsidiaries that own oil and gas properties in offshore California and Illinois. We also contributed to PXP $5.0 million in cash and $256.0 million of intercompany payables that PXP or its subsidiaries owed to us. On July 3, 2002 PXP issued $200 million of 8.75% Senior Subordinated Notes due 2012, or the 8.75% Notes, and entered into a $300 million revolving credit facility. PXP distributed the net proceeds of $195.3 million from the 8.75% notes and $116.7 million of initial borrowings under its credit facility to us. Of such distribution, we used:

	•	$287.0 million to redeem our 10.25% senior subordinated notes; and
	•	$25 million to repay and terminate our revolving credit facility.

      As a result of the spin-off, the number of shares of our common stock into which shares of our Series D Preferred Stock, or Series D Preferred, is convertible increased from 932,000 shares to 1,671,416 shares as a result of the reduction in the conversion price from $25.00 per share of common stock to $13.94 per share. We have 46,600 shares of Series D Preferred outstanding with a stated value per share of $500 ($23.3 million aggregate stated value) that bears an annual dividend of $30.00 per share.

      As a result of the spin-off the historical results of the operations of PXP are reflected in our financial statements as “discontinued operations”. Except where noted, discussions in this Form 10-K with respect to oil and gas operations relate to our activities other than the discontinued operations.

General

     Upstream Operations

      We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration, exploitation and development activities are capitalized. Our revenues are derived from the sale of oil. We recognize revenues when our production is sold and title is transferred. Our revenues are highly dependent upon the prices of, and demand for oil. 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 our levels of production are subject to wide fluctuations and depend on numerous factors beyond our control, including supply and demand, economic conditions,

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      To manage our exposure to commodity price risks, we use various derivative instruments to hedge our exposure to oil sales price fluctuations. Our hedging arrangements provide us protection on the hedged volumes if oil prices decline below the prices at which these hedges are set. However, if oil prices increase, ceiling prices in our hedges may cause us to receive lower revenues on the hedged volumes than we would receive in the absence of hedges. Gains and losses from hedging transactions are recognized as revenues when the associated production is sold.

      Our oil production expenses include salaries and benefits of personnel involved in production activities, electric costs, maintenance costs, production, ad valorem and severance taxes, and other costs necessary to operate our producing properties. Depletion of capitalized costs of producing oil and gas properties is provided using the units of production method based upon proved reserves. For the purposes of computing depletion, proved reserves are redetermined as of the end of each year and on an interim basis when deemed necessary. General and administrative expenses consist primarily of salaries and related benefits of administrative personnel, office rent, systems costs and other administrative costs.

     Midstream Operations

      We account for our investment in PAA using the equity method of accounting. We record equity in earnings of PAA based on our aggregate ownership interest, as adjusted for general partner incentive distributions. Equity in earnings for our general partner interest is based on our 44% share of 2% of PAA’s net income plus the amount of the general partner incentive distribution. Equity in earnings for our limited partner units is based on our ownership percentage of limited partner units (25% at December 31, 2002) multiplied by 98% of PAA’s net income less the general partner incentive distribution. Increased earnings attributable to the general partner incentive distributions will be somewhat offset because of our ownership of limited partner units. Cash distributions received from PAA are not reflected in earnings, but reduce our investment in PAA.

      When PAA sells additional limited partner units and we do not purchase additional units, our ownership interest in PAA is reduced, creating an “implied sale” of a portion of our investment. We have recognized gains from PAA equity issuances representing the difference between our carrying cost and the fair value of the interest deemed sold.

Results of Operations

      Our 2001 and 2000 income statements reflect the results of operations of PXP as discontinued operations. Also, as a result of the sale of a portion of our interest in PAA and the resulting change to the equity method of accounting for our investment in PAA in 2001, our income statement presentation for 2000 is not comparable to our income statement presentations for subsequent periods. The following table reflects our 2002 and 2001 income statements compared to a proforma income statement for 2000 adjusted to reflect PAA on the equity method of accounting. Our

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