Edgar Filing: PLAINS RESOURCES INC

Amendment No. 1 to Form 10-K for the Year Ended December 31, 2003

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K/A

Amendment No. 1

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

OF THE SECURITIES EXCHANGE ACT OF 1934

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

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2003

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

SECURITIES EXCHANGE ACT OF 1934

Commission file number: 0-9808

PLAINS RESOURCES INC.

(Exact name of registrant as specified in its charter)

Delaware

(State or other jurisdiction of

incorporation or organization)

13-2898764

(I.R.S. Employer

Identification No.)

700 Milam Street, Suite 3100

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)

(832) 239-6000

(Registrant’s telephone number, including area code)

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


Title of each class		Name of each exchange on which registered
Common Stock, par value $0.10 per share		New York Stock Exchange

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ü No

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).

Yes ü No

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 $243 million on June 30, 2003, the last business day of the registrant’s most recently completed second fiscal quarter (based on $14.15 per share, the last sale price of the Common Stock as reported on the New York Stock Exchange on such date).

On February 29, 2004, there were 23.8 million shares of the registrant’s Common Stock outstanding.

PLAINS RESOURCES INC.

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

FOR THE YEAR ENDED DECEMBER 31, 2003

Introductory Note and Table of Contents

Plains Resources Inc. hereby amends its Annual Report on Form 10-K for the fiscal year ended December 31, 2003 (originally filed on March 5, 2004) to include Items 10, 11, 12 and 13, which were not included in the original filing and to revise Item 7 and Item 9A. No other changes have been made to the Annual Report.


		Page
	Part I

Items 1 & 2.	Business and Properties	6

Item 3.	Legal Proceedings	23

Item 4.	Submission of Matters to a Vote of Security Holders	26

	Part II

Item 5.	Market for Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities	29

Item 6.	Selected Financial Data	30

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31

Item 7A.	Quantitative and Qualitative Disclosures About Market Risks	46

Item 8.	Financial Statements and Supplementary Data	48

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	48

Item 9A.	Controls and Procedures	48

	Part III

Item 10.	Executive Officers of the Registrant	48

Item 11.	Executive Compensation	50

Item 12.	Security Ownership of Certain Beneficial Owners and Management And Related Stockholder Matters	60

Item 13.	Certain Relationships and Related Transactions	62

Item 14.	Principal Accountant Fees and Services	63

	Part IV

Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	65

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

STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

•

the future profitability of Plains Resources;

•

the uncertainty of the market for the midstream activities of marketing, gathering, transporting, terminalling, and storage of crude oil that Plains Resources engages in through its significant equity ownership in Plains All American Pipeline, L.P., or PAA;

•

the risks associated with the finding and developing of upstream oil and gas reserves associated with Plains Resources’ Florida oil and gas operations;

•

the seasonality of Plains Resources’ financial results;

•

the favorable resolution of pending and future litigation;

•

the operating and financial performance of PAA;

•

the consequences of our and Plains Exploration & Production Company’s, or PXP, officers and employees providing services to both us and PXP 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 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 Securities and Exchange Commission, or 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.

AVAILABLE INFORMATION

We file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any document we file at the SEC’s Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the SEC’s Public Reference Room. Our SEC filings are also available to the public at the SEC’s web site at www.sec.gov. No information from such web site is incorporated by reference herein. Our web site is www.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.

GLOSSARY OF OIL AND GAS TERMS

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

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

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

BOE. One stock tank barrel equivalent of oil, calculated by converting gas volumes to equivalent oil 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.

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.

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.

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 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.

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.

PART I

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 February 29, 2004 we owned 44% of the general partner of PAA and 12.4 million, or 21%, of the limited partnership units of PAA, which represented approximately 22% 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. (“Calumet”), which has producing properties in the Sunniland Trend in south Florida.

The book value of our ownership interest in PAA represents 57% of our total assets as of December 31, 2003, the book value of our Florida oil properties represents 30% and other assets (including $5 million of restricted cash) represent 13% of our total assets. As of December 31, 2003, the present value of our proved oil reserves was approximately $77.5 million (see “—Oil Production Operations”). The present value of our oil reserves as of December 31, 2003 as determined in accordance with SEC requirements is based on prices, costs and assumptions in effect on that date. The price in effect at December 31, 2003 was $32.52 per barrel before adjustment for location and quality differential. This present value does not necessarily represent the actual value of such reserves since actual future prices and costs may be significantly higher or lower than the prices and costs on December 31, 2003. We currently own 11.1 million common units and 1.3 million Class B common units of PAA. The closing price of publicly traded PAA common units, as reported on the New York Stock Exchange, was $31.91 on December 31, 2003. The Class B common units are not publicly traded but do receive cash distributions from PAA. PAA’s financial performance directly impacts our financial performance and the market value performance of PAA’s limited partnership 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, 2003, 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.

Our Board of Directors has authorized the repurchase of up to eight million shares of our common stock. Through December 31, 2003, we had repurchased a total of 4.9 million shares at a total cost of approximately $100.4 million.

Offer to Acquire Plains Resources

On November 19, 2003 we received a proposal from Vulcan Capital, Inc., our Chairman, James C. Flores, and our CEO and President, John T. Raymond, or the Vulcan Group, to acquire all of our outstanding stock for $14.25 per share in cash (the “Original Vulcan Proposal”). Vulcan Capital is the investment arm of Seattle-based investor Paul G. Allen. The offer indicated that commitments for all of the financing necessary to complete the transaction had been received.

In response to receipt of the Original Vulcan Proposal, the Board of Directors established a special committee comprised of board members William C. O’Malley and William M. Hitchcock. The special committee was authorized to review, evaluate, negotiate and make recommendations to the full Board of Directors with respect to the Original Vulcan Proposal. In addition, the special committee was authorized to review and evaluate alternative proposals that may be developed or received from other parties relating to a transaction with the Company. The special committee retained Petrie Parkman &

Co. as its financial advisor and Baker Botts L.L.P. and Morris, Nichols, Arsht & Tunnell as its legal counsel.

On January 22, 2004 the special committee, after a thorough review with its independent financial and legal advisors, announced that, after careful consideration, it had determined that the Original Vulcan Proposal was inadequate and not in the best interests of our stockholders. The Special Committee said it was prepared to enter into discussions or negotiations with the Vulcan Group or other parties relating to a transaction with the Company.

Following discussions and negotiations with the Vulcan Group and other interested parties, on February 18, 2004 the Special Committee voted unanimously to recommend to the PLX Board of Directors and to Plains Resources’ stockholders a $16.75 per share proposal from the Vulcan Group (the “Revised Vulcan Proposal”). Our Board of Directors, excluding Mr. Flores, has unanimously approved the merger agreement negotiated in connection with the Revised Vulcan Proposal and recommends that stockholders vote in favor of the transactions contemplated thereby.

The merger agreement contains customary fiduciary termination rights. If the merger agreement is terminated, under specified circumstances, we have agreed to reimburse all of the Vulcan Group’s reasonable out-of-pocket expenses. In addition, in certain circumstances we have agreed to pay a termination fee of $15 million. In all other circumstances, each party must pay all fees and expenses it incurs relating to the merger. The closing of the merger is subject to approval by the stockholders of Plains Resources and other customary closing conditions. The Company plans to hold a special meeting of stockholders to vote on the proposed transaction as soon as practicable. Completion of the transaction is expected during the second quarter of 2004. If the merger is consummated, Plains Resources will become a privately held company. Accordingly, upon closing, the registration of the Company’s common stock under the Securities Exchange Act of 1934 will terminate and the Company will cease filing reports with the SEC.

Plains Resources has filed a preliminary proxy statement for the special meeting of stockholders to vote on the proposed transaction, and the Vulcan Group will file other relevant documents with the SEC concerning the proposed transaction.

Spin-off of Plains Exploration & Production Company

Prior to December 18, 2002 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 compensation 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 Notes due 2012, or the 8.75% notes, and entered into a $300 million revolving credit facility. PXP distributed to us the net proceeds of $195.3 million from the 8.75% notes and $116.7 million of initial borrowings under the credit facility. We used such amounts to redeem our 10.25% senior subordinated notes on August 2, 2002 ($287.0 million) and to repay amounts outstanding under our credit facility ($25.0 million).

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 qualifies 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”.

Our June 2001 Strategic Restructuring

In a series of transactions in June 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% of the subordinated units of PAA 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 consideration for the sale. In addition, in September 2001 PAA management exercised an option to acquire an additional 2% ownership interest in the general partner of PAA by paying us $1.5 million in cash and notes.

Plains All American Pipeline, L.P.

As of February 29, 2004, our aggregate ownership in PAA was approximately 22%, which was comprised of (1) a 44% interest in the general partner of PAA, (2) 19%, or 11.1 million, of the common units and (3) all of the 1.3 million class B common units.

Operations

PAA is a publicly traded master limited partnership that is engaged in the marketing, gathering, transporting terminalling and storage of oil and the gathering, marketing and storage of liquefied petroleum gas and other petroleum products. 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 approximately 7,000 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 24.0 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 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.

Prior to the fourth quarter of 2003 PAA had outstanding 10.0 million subordinated units, of which we owned 4.5 million units. The subordinated units were not publicly traded and were subordinated in the right to distributions. Common units accrue arrearages with respect to distributions for any quarter during the subordination period and subordinated units do not accrue any arrearages. PAA met certain financial requirements and 25% of the subordinated units converted to common units in the fourth quarter of 2003. The remaining subordinated units converted to common units in February 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 PAA’s partnership agreement. Generally, the general partner is entitled, without duplication, to 15% of amounts PAA distributes in excess of $0.45 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 $0.5625 per unit distribution paid in the first quarter of 2004 ($2.25 per unit annualized), we would receive an annual distribution from PAA of approximately $32.6 million for 2004, including $4.1 million for our general partner distribution (including $2.9 million for the general partner incentive distribution).

Oil Production Operations

Calumet has a 100% working interest in five producing fields in the Sunniland Trend in south Florida. Calumet acquired 50% of its interest in these fields in 1993 and the remaining 50% in 1994. In 2003 net production from these properties averaged 2,315 barrels of oil per day and proved reserves were 14.5 MMBbls at December 31, 2003. In 2003 we spent $3.3 million on capital projects, primarily facility enhancements and abandonment of inactive wells. In 2004 we expect to spend $3.5 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 for 2002 and 2001 exclude reserves attributable to discontinued operations. See “Spin Off of Plains Exploration & Production Company” and Note 2 to the consolidated financial statements.


	As of or for the Year Ended December 31,
	2003			2002			2001
	Oil (MBbls)
Proved Reserves
Beginning balance		16,313			17,343			18,775
Revision of previous estimates		(921	)		(60	)		(2,470	)
Extensions, discoveries, improved recovery and other additions		—			—			1,992
Production		(845	)		(970	)		(954	)

Ending balance		14,547			16,313			17,343

Proved Developed Reserves
Beginning balance		14,499			15,456			17,853

Ending balance		12,730			14,499			15,456

PV-10 ($/000s) (1)
Proved developed	$	60,936		$	73,656		$	21,124
Proved undeveloped		16,517			14,258			5,421

Total Proved	$	77,453		$	87,914		$	26,545

Standardized measure	$	65,558		$	73,339		$	26,545

Average year-end realized oil price, per Bbl (2)	$	20.78		$	20.25		$	9.82
December 31 NYMEX WTI spot price, per Bbl	$	32.52		$	31.20		$	19.84

(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.

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 PV-10 and standardized measure shown above represents estimates only and should not be construed as the current 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, 2003 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, 2003 was $20.78 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, 2002, 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, 2003, we had working interests in 16 gross (16 net) active producing oil wells. At December 31, 2003 we had working interests in 12,025 gross, 12,025 net, developed acres and 73,427 gross, 71,524 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 2003 or 2002. In 2001 we participated in 1 gross (0.5 net) dry exploratory well on a property outside Florida.

Production and Sales

The following table presents certain information with respect to oil production and sales attributable to our properties, average sales prices received and average production costs during the three years ended December 31, 2003, 2002 and 2001.


	Year Ended December 31,
	2003			2002			2001
Production (MBbls)		845			970			954
Sales (MBbls)		926			869			1,060
Sales Price per Bbl
Average NYMEX price	$	30.99		$	26.15		$	26.01
Differential		(7.06	)		(3.97	)		(9.77	)

		23.93			22.18			16.24
Hedging		(0.33	)		(0.71	)		(1.11	)

		23.60			21.47			15.13
Derivative cash settlements		(2.57	)		—			—

		21.03			21.47			15.13
Costs and Expenses per Bbl
Production expenses		7.99			6.72			6.63
Production and ad valorem taxes		1.22			0.67			0.35
Oil transportation expenses		4.22			4.34			4.20

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. 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, 2003, 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, 2003, 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, 2003, 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.

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 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 related permits, they may be subject to significant administrative, civil and criminal penalties, injunctions and construction bans or delays. If we were to discharge hydrocarbons or hazardous substances into the environment, we could, to the extent the event is not insured, incur substantial expense, including both the cost to comply with applicable laws and regulations and claims made by neighboring landowners and other third parties for personal injury and property damage.

Although we obtained environmental studies when we acquired our properties in the Sunniland Trend, 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 Sunniland Trend properties is 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 Production Operations”. 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”.

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.

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 considered reasonable. The insurance policies are subject to deductibles that we consider reasonable and not excessive. Our insurance does not cover every potential risk associated with our operations. 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.

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

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 storing oil and gas (except to the extent any such activities are ancillary to, or in support of, any of PXP’s upstream activities).

The technical services agreement provides that PXP will provide services with respect to the operations of Calumet 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 29, 2004, we had 12 full-time employees (not including our Chief Executive Officer, Chief Financial Officer and General Counsel, who also devote time and efforts to PXP), none of whom is represented by any labor union. All of our full-time employees 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 and financial condition, as well as adversely affect the value of an investment in our common stock.

We are highly dependent upon the earnings and distributions of PAA.

In 2003, we had oil revenues from our upstream operations of $21.9 million while distributions received from PAA attributable to our general and limited partner interests totaled $30.9 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.

In addition, cash from PAA distributions on its general partner and limited partner interests is one of our primary sources of our 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.

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 from PAA to support our trade receivables. Accordingly, a material adverse change in PAA’s financial condition could adversely impact our ability to collect our receivables from PAA and thereby affect our financial condition.

We urge you to review PAA’s SEC filings, including its Annual Report on Form 10-K for the year ended December 31, 2003, for risks associated with PAA’s business.

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

We have a substantial amount of debt and the ability to incur substantially more debt. We have a secured term loan facility, of which $50.0 million was outstanding at December 31, 2003. The term loan is collateralized by a pledge of the equity of our subsidiaries and 5.2 million of our PAA common units. We also delivered mortgages on Calumet’s oil and gas properties to secure the loan. The term loan is repayable in 12 quarterly installments of $5.0 million that commenced on August 31, 2003 with a final maturity on May 31, 2006.

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;

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enter into leases;

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sell assets;

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make loans or investments;

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change the nature of our business or operations;

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guarantee other indebtedness;

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enter into certain types of hedge agreements;

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enter into take-or-pay arrangements;

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merge or consolidate; and

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enter into transactions with affiliates.

If the Revised Vulcan Proposal is consummated, our credit facility will terminate and the amount outstanding would be paid in full. 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;

•

limit our flexibility in planning for, or reacting to, changes in the industry in which we operate; and

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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.

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

Revenues from our upstream operations are 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:

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supply and demand for oil and expectations regarding supply and demand;

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weather;

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actions by the Organization of Petroleum Exporting Countries, or OPEC;

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political conditions in other oil-producing countries including the possibility of insurgency or war in such areas;

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general economic conditions in the United States and worldwide; and

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governmental regulations.

Prices of oil will affect:

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our revenues, cash flows and earnings;

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our ability to attract capital to finance our operations and the cost of such capital;

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the amount that we are allowed to borrow; and

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the value of our oil and gas properties.

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

Our success in our upstream business 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, barges 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.

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

The war in Iraq and recent terrorist attacks of unprecedented scope have caused instability in the world financial markets and may generate global economic instability. The continued threat of terrorism and the impact of military or other action have led to and will likely lead to increased volatility in prices for oil and gas and could affect the markets for our operations. Further, the United States government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These developments have subjected our operations to increased risk and, depending on the ultimate magnitude, could have a material adverse affect on our business.

If we do not replace the reserves that we have produced, our reserves and revenues will decline.

The future success of our upstream business 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.

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

The proved oil 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:

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historical production from the area compared with production from other comparable producing areas;

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the assumed effects of regulations by governmental agencies;

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assumptions concerning future oil and gas prices; and

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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:

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the quantities of oil and gas that are ultimately recovered;

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the timing of the recovery of oil and gas reserves;

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the production and operating costs incurred; and

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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:

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the amount and timing of actual production;

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supply and demand for oil and gas; and

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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.

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

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, and restrictive regulations that increase costs, reduce availability of equipment or supplies, reduce demand or limit our production may impact our operations more than if our reserves were more geographically diversified.

Our crude oil produced in Florida has a high sulfur content which limits its use in certain refineries and therefore limits its marketability.

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

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

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well blowouts;

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cratering;

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explosions;

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uncontrollable flows of oil, gas or well fluids;

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fires;

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pollution; and

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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. We have increased deductibles and decreased or eliminated certain types of coverages to mitigate cost increases. 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.

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

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

Environmental liabilities could adversely affect our financial condition.

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

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well drilling or workover, operation and abandonment;

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waste management;

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land reclamation; and

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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.

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

Our 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:

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diversion of management’s attention;

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the need to integrate acquired operations;

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potential loss of key employees of the acquired companies;

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potential lack of operating experience in a geographic market of the acquired business; and

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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.

Our ability to make upstream acquisitions is limited by our spin-off agreements.

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

We reduce our exposure to the volatility of oil 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 production. If these payments become too large, the remainder of our business may be adversely affected. In addition, our hedging agreements expose us to risk of financial loss if the counterparty to a hedging contract defaults on its contract obligations.

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

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

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

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.

To preserve the tax-free status of the spin off, we may be limited in taking future actions.

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

PLX Stockholder Suits

Beginning November 21, 2003, six putative class action lawsuits were filed against Plains Resources, our directors and Mr. Raymond, in the Court of Chancery in the State of Delaware, in and for New Castle County, seeking to enjoin the sale of Plains Resources. The lawsuits, and dates of filing, are as follows:

No. 071-N, Twist Partners LLP v. Flores et al. (filed Nov. 21, 2003)

No. 073-N, Klein v. Flores et al. (filed Nov. 21, 2003)

No. 074-N, Levy v. Flores et al. (filed Nov. 21, 2003)

No. 075-N, Lanza v. Flores et al. (filed Nov. 21, 2003)

No. 076-N, Burt v. Flores et al. (filed Nov. 21, 2003)

No. 143-N, South Broadway Capital v. Flores et al. (filed Dec. 30, 2003)

that the price would soon rebound to the levels at which it traded in 2003 and late 2002. The complaint further alleged that Mr. Flores, Mr. Raymond, and Vulcan Capital determined to “usurp this hidden value for themselves,” thereby allegedly denying our minority stockholders the opportunity to obtain fair value for their equity interest. The Twist Partners November 21, 2003 complaint alleged that all individual defendants breached fiduciary duties of due care and loyalty to our stockholders. Vulcan Capital was alleged to have aided and abetted these alleged breaches of fiduciary duty. The complaint alleged, among other things, that the November 20, 2003 announcement of a November 19, 2003 buyout offer represented “a paltry premium of 7.6 percent to Plains’ current trading price and . . . a very significant discount to what it had traded at earlier in the year.” As of the November 21, 2003 filing of the complaint, Twist Partners alleged that the individually named defendants had failed to auction the Company, had failed to conduct an active market check, had not appointed an independent person to negotiate on behalf of our stockholders.

The relief sought by Twist Partners includes certification of a class action, an injunction preventing consummation of the buyout offer (or rescinding it if consummated), compensatory and/or rescissory damages to the class, interest, attorneys’ fees, expert fees, and other costs, along with such other relief as the Court might find just and proper.

Substantially the same allegations and prayer for relief were made in each of the first five suits which was filed (Twist Partners, Klein, Levy, Lanza, and Burt). (Klein, Lanza, and Levy additionally alleged that Mr. Flores and Mr. Raymond dominated and controlled the rest of our Board of Directors.) The Klein complaint was subsequently amended to name and seek relief from Vulcan Energy rather than Vulcan Capital. These five cases were consolidated on December 11, 2003 under the action No. 071-N, In re Plains Resources Inc. Shareholders Litigation, and defendants are not required to respond to the originally filed complaints.

On December 30, 2003, a sixth complaint was filed by South Broadway Capital alleging substantially the same allegations and prayer for relief as the complaints consolidated under No. 071-N, In re Plains Resources Inc. Shareholders Litigation. Plaintiff’s Delaware counsel of record for South Broadway Capital are also plaintiff’s counsel of record in No. 071-N, In re Plains Resources Inc. Shareholders Litigation. The defendants expect that the South Broadway Capital action will be consolidated with the other five shareholder suits.

•

the resulting controlling interest in PAA (for which plaintiffs allege the fair market value of the premium for such control is between $360 and $540 million);

•

incentive distribution rights in Plains AAP (for which plaintiffs allege an estimated present value of $54.4 million);

•

limited partner interest in PAA;

•

our proved oil reserves (of which plaintiffs allege the market value is 15% higher than our standardized measure);

•

certain unspecified tax credits not reflected on our balance sheet; and

•

other unspecified assets, net of liabilities.

The amended consolidated complaint also alleges that:

•

Mr. O’Malley has “significant business and/or personal relationships” with Mr. Flores and Mr. Raymond and is not capable of being a truly independent member of the special committee;

•

the Leucadia proposal was rejected without adequate consideration by the special committee;

•

the special committee’s January 22, 2004 statement that it was “prepared to enter into discussions or negotiations with . . . other parties relating to a transaction” was materially false and misleading, and that the special committee “never intended to entertain proposals from anyone other than Vulcan and/or the Company’s directors”;

•

the Vulcan Capital proposal is not the result of a full and fair auction process or active market check, that the $16.75 per share price was reached without a full and thorough investigation, that the price and process are intrinsically unfair and inadequate; and

•

our directors failed to make an informed decision with respect to the Vulcan Capital proposal.

Also on February 24, 2004, Donald Gilbert filed a putative class action lawsuit against Plains Resources, our directors, Mr. Raymond and Vulcan Capital in the 157th District Court for Harris County, Texas (No. 2004-10509, Gilbert v. Plains Resources Inc. et al.). The petition has not been served at this time. Its factual allegations repeat some but not all of those made in the consolidated amended complaint filed in In re Plains Resources Inc. Shareholders Litigation in Delaware. The Texas suit particularly alleges that “members of the Class will be irreparably harmed in that they will not receive fair value for Plains Resources’ assets and business and will be prevented from obtaining the real value of their equity ownership in the Company,” and that unless an injunction is entered, Vulcan Capital and Messrs. Flores and Raymond “will continue to aid and abet a process that inhibits the maximization of shareholder value.” For purported causes of action, the Texas lawsuit alleges that our directors breached fiduciary duties of loyalty and due care by allegedly failing to (1) inform themselves of our market value before taking action, (2) act in the best interest of our shareholders, (3) maximize shareholder value, (4) obtain the best financial and unspecified other terms when our independent existence will be materially altered by a transaction, and (5) act in accordance with their fundamental duties of due care and loyalty. It further alleges that Vulcan Capital and Messrs. Flores and Raymond aided and abetted our directors’ alleged breaches of fiduciary duties. The relief sought includes (1) declaration of a class action, (2) declaration that the proposed merger agreement “was entered into in breach of the fiduciary duties of” our directors, (3) injunction prohibiting us from proceeding with and consummating the proposed merger, (4) injunction requiring the implementation of procedures to obtain the highest price, (5) injunction requiring our directors “to exercise their fiduciary duties to obtain a transaction which is in the best interests of shareholders until the process for the sale or auction of the Company is completed and the highest possible price is obtained,” (6) unspecified “appropriate damages,” (7) “costs and disbursements,” including reasonable attorneys’ and experts’ fees, and (8) other and further relief which the Court may deem just and proper.

PAA Suit

On December 18, 2003, Alfons Sperber filed suit in the Court of Chancery in the State of Delaware, in and for New Castle County against Plains Resources, PAA, Plains AAP, L.P. (“Plains AAP”), PAA GP LLC, and several individual defendants (No. 123-N, Sperber v. Plains Resources, Inc. et al.). The Sperber suit was putatively brought on behalf of all limited partners and unit holders in PAA and alleges (1) breach of the fiduciary duties owed to PAA and its unit holders and limited partners by PAA; Plains AAP, L.P.; PAA GP, L.L.C.; and the individually named directors of PAA GP, L.L.C.; and (2) breach of the fiduciary duties owed to PAA and its unit holders and limited partners by Plains Resources Inc. and its individually named directors as controlling stockholder of PAA GP, L.L.C.

Sperber’s factual allegations concerning the buyout proposal are substantially the same as those alleged in the consolidated Plains Resources stockholders litigation. In addition, Sperber alleged that as a result of the buyout proposal, Mr. Flores and Mr. Raymond will effectively control PAA. Sperber alleged that PAA had made no disclosure concerning the buyout proposal, and that no actions had been taken to protect the interests of PAA, its limited partners, or its unitholders with respect to the Plains Resources buyout proposal. Sperber specifically alleged that defendants have breached their contractual and/or fiduciary duties by failing to seek, pursuant to their respective governing documents, to acquire Plains Resources or the PAA units and general partnership interests held by Plains Resources; failing to amend the PAA GP Amended and Restated Limited Liability Company Agreement and/or PAA’s Amended and Restated Limited Partnership Agreement to limit the power of Messrs. Flores and Raymond and Vulcan Capital over selection of five of the seven members of the PAA GP board and the chief executive officer of PAA GP, failing to ensure that the transaction does not adversely affect PAA’s interests under the Crude Oil Marketing Agreement, dated as of November 23, 1998, by and among Plains Resources, Plains Illinois Inc., Stocker Resources, LP, Calumet Florida, Inc., and Plains Marketing, LP and the Omnibus Agreement among Plains Resources, PAA, Plains Marketing, LP, All American Pipeline, LP and Plains All American Inc., dated as of November 23, 1998, or to obtain fair value for any waiver of those interests; failing to convene the conflicts committee to determine whether the proposed transaction is fair and reasonable to PAA; and failing to appoint a special committee of independent directors to consider the effects of the transaction. Sperber alleged that all defendants to that action owe fiduciary duties to PAA, its limited partners, and its unitholders which allegedly have been breached by the failure to take actions to protect the interests of PAA, its limited partners, and its unitholders.

The Sperber complaint requests the following relief: certification of a class action, an injunction preventing consummation of the buyout offer (or rescinding it if consummated), an injunction requiring PAA and Plains AAP to act to protect the interest of PAA, its limited partners, and its unitholders, a declaration that the individual defendants breached their fiduciary duties to the plaintiff and the putative class, an accounting of all assets, money, and other value improperly received from Plains Resources, disgorgement and imposition of a constructive trust on all property and profits defendants received as a result of wrongful conduct, damages to the class, interest, attorneys’ fees, and other costs, along with such other relief as the Court might find just and proper. Pursuant to an agreement among counsel, no response to the Sperber complaint is required until March 10, 2004.

Other

The previously reported lawsuit regarding the termination of an electric services contract with Commonwealth Energy Corporation was settled in January 2004 by Plains Exploration under its indemnity obligation to us. All claims of the lawsuit have been released.

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 any pending 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 29, 2004, and their business experience for the last five years.

Directors

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

William M. Hitchcock, age 64, Director since 1977. Mr. Hitchcock is a partner and has been President since 1996 of Pembroke Financial Partners LLC, a NASD 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 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.

William C. O’Malley, age 66, Director since April 2003. Mr. O’Malley is a director (since 1994) of and former Chairman of the Board of Tidewater Inc., a public offshore marine transportation, shipyard facilities and containerized shipping company. He was Tidewater Inc.’s Chief Executive Officer from 1994 to 2002 and served as its President from 1994 to 2001. Mr. O’Malley has been a director of Hibernia Corporation, the holding company for Hibernia National Bank, since 1995. He is also a director of BE&K Inc., an engineering and construction contractor. Mr. O’Malley is a certified public accountant and a former partner with Arthur Young, a predecessor accounting firm to Ernst & Young LLP.

D. Martin Phillips, age 50, Director since June 2001. Mr. Phillips has been a Managing Director and principal of EnCap Investments L.P., 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. From 1999 to June 2003, Mr. Phillips served as a director of 3TEC Energy Corporation. Mr. Phillips also currently serves as a director of seven privately held EnCap portfolio companies and Small Steps Nurturing Center. He formerly served as president of the Houston Producers’ Forum.

Robert V. Sinnott, age 54, 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, the general partner of Plains AAP, L.P., which is in turn the general partner of 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 64, 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., an oilfield services company, and a director of Plains All American GP LLC, the general partner of Plains AAP LP, which is in turn the general partner of PAA.

Executive Officers

John T. Raymond, age 33, Chief Executive Officer 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, the general partner of Plains AAP LP, which is in turn the general partner of PAA. Mr. Raymond served as President and Chief Operating Officer of PXP from September 2002 to March 2004.

Stephen A. Thorington, age 48, 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 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.

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

PART II

Item 5.

MARKET FOR REGISTRANT’S COMMON STOCK, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Price Range of Common Stock

Our common stock is listed and traded on the New York Stock Exchange under the symbol “PLX”. The number of stockholders of record of our common stock as of February 29, 2004 was 933.

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.


	High		Low
2003
1st Quarter	$	12.70	$	10.41
2nd Quarter		14.50		10.90
3rd Quarter		14.54		12.45
4th Quarter		16.10		12.55
2002
Before Spin-off
1st Quarter		24.99		22.35
2nd Quarter		27.75		24.60
3rd Quarter		26.95		21.92
4th Quarter		25.88		20.18
After Spin-off
4th Quarter		12.51		11.85

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.

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 spin-off, the historical results of the operations of PXP are reflected in our financial statements as “discontinued operations”. As a result of the reduction in our ownership interest in PAA in 2001, our ownership interest 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. 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).


	Year Ended December 31,
	2003			2002			2001			2000			1999
Revenues
Crude oil sales to PAA	$	22,164		$	19,275		$	17,211		$	17,213		$	16,136
Hedging		(307	)		(613	)		(1,181	)		(6,570	)		(3,658	)
Marketing, transportation, storage and terminalling		—			—			—			6,425,644			10,796,998
Gain on sale of assets (1)		—			—			—			48,188			16,457

		21,857			18,662			16,030			6,484,475			10,825,933

Costs and Expenses
Production expenses		8,532			6,421			7,397			5,912			5,118
Oil transportation expenses		3,906			3,775			4,449			3,752			3,740
Other operating expenses		137			115			—			—			—
General and administrative		6,973			5,747			11,083			44,468			27,035
Marketing, transportation, storage and terminalling		—			—			—			6,292,615			10,689,308
Unauthorized trading losses and related expenses (2)		—			—			—			7,963			166,440
Depreciation, depletion, amortization and accretion		4,995			4,139			4,816			28,362			23,669

		24,543			20,197			27,745			6,383,072			10,915,310

Other Income (Expense)
Equity in earnings of PAA		15,073			18,807			18,540			—			—
Gains on PAA unit transactions and public offerings (3)		33,237			14,512			170,157			—			9,787
Loss on debt extinguishment		—			(10,319	)		—			(15,148	)		(1,545	)
Gain (loss) on derivatives		(6,728	)		—			—			—			—
Interest expense		(2,222	)		(5,866	)		(8,974	)		(39,943	)		(31,466	)
Interest and other income		97			239			(312	)		7,068			1,150
Minority interest in PAA		—			—			—			(35,565	)		40,911
Income tax expense		(16,464	)		(6,106	)		(67,072	)		(5,628	)		26,104

Income (Loss) From Continuing Operations		20,307			9,732			100,624			12,187			(44,436	)
Income from discontinued operations, net of tax		—			27,800			54,693			28,749			19,105
Cumulative effect of accounting changes, net of tax		933			—			(1,986	)		(121	)		—

Net Income		21,240			37,532			153,331			40,815			(25,331	)
Cumulative preferred dividends (4)		(603	)		(1,400	)		(27,245	)		(14,725	)		(10,026	)

Income Available to Common Stockholders	$	20,637		$	36,132		$	126,086		$	26,090		$	(35,357	)

Income From Continuing Operations Per Share
Basic	$	0.88		$	0.35		$	3.48		$	(0.14	)	$	(3.16	)
Diluted	$	0.86		$	0.34		$	2.81		$	(0.14	)	$	(3.16	)
Balance Sheet Data
Working capital (deficit)	$	(19,455	)	$	(11,971	)	$	(9,969	)	$	20,289		$	115,867
Ownership interest in PAA		100,536			70,042			64,626			—			—
Total assets		176,048			161,412			648,788			1,394,329			1,689,560
Long-term debt		30,000			27,000			282,061			626,376			676,703
Redeemable preferred stock		—			—			—			50,000			138,813
Stockholders’ equity		100,904			105,509			254,852			137,140			40,619
Distributions from PAA		30,930			29,063			31,553			30,134			29,472

(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 2003 relate to public offerings of PAA units and the conversion of certain subordinated units. Amounts in 2002 and 1999 relate to public offerings of PAA units. Amount in 2001 relates to sale of a portion of our interest in PAA and public offering of PAA units.

(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.

Item 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Overview

We are an independent energy company. Our current business operations are focused in two areas of the energy business—“midstream” and “upstream.”

Midstream.

Our midstream activities are carried out through our equity ownership in Plains All American Pipeline, L.P., or PAA, a public master limited partnership. PAA markets, gathers, transports, terminals, and stores oil. As of February 29, 2004 we owned 44% of the general partner of PAA and 12.4 million, or 21%, of the limited partnership units of PAA, which represented approximately 22% aggregate ownership interest in PAA. See “—Plains All American Pipeline, L.P.” The book value of our ownership interest in PAA represents 57% of our total assets as of December 31, 2003.

During 2003, we received $30.9 million in partnership distributions from PAA. PAA partnership distributions generate relatively stable cash flows to the Company with relatively minimal future capital requirements from us. Our equity in the earnings of PAA was $15.1 million and we also recognized $33.2 million in gains on PAA unit transactions and public offerings. These numbers reflect lower PAA earnings and a decrease in our ownership of PAA as a result of 2003 equity offerings. PAA’s financial performance directly impacts our financial performance and the market value performance of PAA’s limited partnership interests directly impacts the value of our assets. Changes to PAA’s income or asset values because of business or market factors affecting PAA will directly affect our reported income and asset values and could affect the amount of distributions we receive. 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, 2003, 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.

Upstream.

We participate in the “upstream” activities of acquiring, exploiting, developing, exploring for and producing oil through our wholly owned subsidiary, Calumet Florida L.L.C., or Calumet, which owns producing properties in the Sunniland Trend in south Florida. The book value of our upstream assets represents 30% of our total assets as of December 31, 2003. The present value of our oil reserves as of December 31, 2003, approximately $77.5 million, was determined in accordance with SEC requirements is based on prices, costs and assumptions in effect on that date. The price in effect at December 31, 2003 was $32.52 per barrel before adjustment for location and quality differential. This present value does not necessarily represent the actual value of such reserves since actual future prices and costs may be significantly higher or lower than the prices and costs on December 31, 2003.

Our revenues from the sale of oil during 2003 were $21.9 million. Our revenues from upstream operations are dependent on the price of oil, which is historically volatile. We manage our exposure to price risk by hedging a substantial portion of our oil production through the use of derivative instruments. We manage our upstream operations to provide a steady cash flow through our hedging and by controlling operating expenses of the properties. We could be adversely affected by a material change in oil prices for which we have not effectively hedged or increases in operating expenses such as electricity or transportation. Our production volumes will decline if we do not invest capital in new wells or reworking of existing wells.

Proposed Merger Transaction

As further described in Items 1 and 2 —“Business and Properties,” the Company has entered into a merger agreement with the Vulcan Group as approved by the Special Committee and our board of directors. In the proposed merger, the Vulcan Group would acquire all of our outstanding stock for $16.75 per share in cash. We have filed a preliminary proxy statement for the special meeting of stockholders to vote on the proposed transaction. If the merger is consummated, Plains Resources will become a privately held company. Accordingly, upon closing, the registration of the Company’s common stock under the Securities Exchange Act of 1934 will terminate and the Company will cease filing reports with the SEC.

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 compensation obligations.

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, foreign imports, the actions of OPEC, political conditions in other oil-producing countries, and governmental regulation, legislation and policies. Under the SEC’s full cost accounting rules, we review the carrying value of our proved oil and gas properties each quarter. These rules generally require that we price our future oil and gas production at the oil and gas prices in effect at the end of each fiscal quarter to determine a ceiling value of our properties. The rules require a write-down if our capitalized costs exceed the allowed “ceiling.” We have had no write-downs due to these ceiling test limitations since 1998. Given the volatility of oil prices, it is likely that our estimate of discounted future net revenues from proved oil and gas reserves will fluctuate in the near term. If oil prices decline in the future, write-downs of our oil and gas properties could occur. Write-downs required by these rules do not directly impact our cash flows from operating activities. Decreases in oil and gas prices have had, and will likely have in the future, an adverse effect on the carrying value of our proved reserves and our revenues, profitability and cash flow.

To manage our exposure to commodity price 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 field personnel, 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 ownership interest 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 (21% at December 31, 2003) 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 are reflected as a reduction in our ownership interest in PAA on the balance sheet.

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 ownership interest. 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

In 2003 our net income was $21.2 million. We had revenues from oil sales of $21.9 million and costs and expenses totaled $24.5 million. Our equity in the earnings of PAA was $15.1 million and we recognized $33.2 million in gains on PAA unit transactions and public offerings. Our derivative transactions resulted in a $4.3 million fair value loss and $2.4 million in settlement losses and we had $2.2 million in interest expense. Income tax expense for the year was $16.5 million. We also recognized a $0.9 million gain on the adoption of a new accounting policy related to our accounting for asset retirement obligations.

The following table reflects the components of our oil and gas revenues from continuing operations and sets forth our revenues and costs and expenses from continuing operations on a BOE basis:


	Year Ended December 31,
	2003			2002			2001
Production (MBbls)		845			970			954
Sales (MBbls)		926			869			1,060
Sales Price per Bbl
Average NYMEX price	$	30.99		$	26.15		$	26.01
Differential		(7.06	)		(3.97	)		(9.77	)

		23.93			22.18			16.24
Hedging		(0.33	)		(0.71	)		(1.11	)

		23.60			21.47			15.13
Derivative cash settlements		(2.57	)		—			—

		21.03			21.47			15.13
Costs and Expenses per Bbl
Production expenses		7.99			6.72			6.63
Production and ad valorem taxes		1.22			0.67			0.35
Oil transportation expenses		4.22			4.34			4.20
DD&A (oil & gas properties)		4.78			3.73			2.74

In the first quarter of 2003, the NYMEX oil price and the price we receive for our Florida oil production did not correlate closely enough for our hedges to qualify for hedge accounting under the applicable accounting rules. As a result, we were required to discontinue hedge accounting effective February 1, 2003 and reflect the mark-to-market value of the derivatives in earnings prospectively from that date. The $2.1 million ($1.0 million, net of tax) net loss in Other Comprehensive Income (“OCI”) at January 31, 2003 ($0.3 million, $0.2 million net of tax at December 31, 2003) related to these hedges will be recognized in earnings as the related production is delivered. In 2003 the hedging amount presented in the above table relates only to oil sold in January 2003. None of our current derivatives qualify for hedge accounting. Derivative instruments that we enter into in the future may or may not qualify for hedge accounting.

Comparison of Year Ended December 31, 2003 to Year Ended December 31, 2002

Net income was $21.2 million for 2003 compared to income from continuing operations of $9.7 million for 2002. Including income from discontinued operations, net income was $37.5 million for 2002.

Oil revenues. Oil revenues, excluding the effect of hedging, increased 15%, or $2.9 million, from $19.3 million for 2002 to $22.2 million for 2003. Our average sales price for oil excluding hedging

increased 8%, or $1.75, to $23.93 per Bbl for 2003 from $22.18 per Bbl for 2002. An increase in the NYMEX price to $30.99 per Bbl was partially offset by an increase in the average differential for location and quality from $3.97 per Bbl in 2002 to $7.06 in 2003. Including the effect of hedging, our average realized price for 2002 was $21.47 per Bbl and our average realized price for 2003 was $23.60 per Bbl. After deducting our $2.57 per Bbl loss on cash settlements of derivatives, our average realized price for 2003 period was $21.03 per Bbl.

Reported sales volumes from our Florida properties were 926 MBbls in 2003 compared to 869 MBbls in 2002. In accordance with SEC Staff Accounting Bulletin 101 we reflect revenue from oil production in the period it is sold as opposed to when it is produced. Oil volumes decreased 13% on an “as produced” basis, with production volumes of 845 MBbls in 2003 compared to 970 MBbls in 2002. The location of our Florida properties and the timing of the barges that transport the oil to market cause reported sales volumes to differ from production volumes. Actual timing of sales volumes is difficult to predict. The Florida oil is typically sold in shipments that range from approximately 110 MBbls to 140 MBbls and typically occurs every 30-50 days. In addition, our Florida properties consist of a relatively low number of higher volume wells and downtime due to equipment failures and other operational issues can cause production from this area to be volatile.

Production expenses. Production expenses increased 27%, or $1.6 million, to $7.4 million ($7.99 per Bbl) for 2003 from $5.8 million ($6.72 per Bbl) for 2002. The increase is primarily attributable to increased fuel and electricity costs and higher costs for maintenance and repairs.

Production and ad valorem taxes. Production and ad valorem taxes increased $0.5 million, to $1.1 million for 2003 from $0.6 million for 2002 primarily due to increased sales volumes and the expiration of severance tax exemptions for several wells in the second quarter of 2002. Unit production and ad valorem taxes were $1.22 per Bbl for 2003 compared to $0.67 per Bbl in 2002.

Oil transportation expenses. Gathering and transportation expenses increased 3%, or $0.1 million, from $3.8 million in 2002 to $3.9 million in 2003. On a per Bbl basis, oil transportation expenses decreased from $4.34 per Bbl in 2002 to $4.22 per Bbl in 2003.

General and administrative expenses. General and administrative expenses, or G&A expense, increased 23%, or $1.3 million, from $5.7 million in the 2002 to $7.0 million in 2003, primarily from costs incurred in connection with a buyout proposal received during 2003 and non-cash compensation expense related to restricted stock awards.

Depreciation, depletion, amortization and accretion, or DD&A. DD&A expense increased 22%, or $0.9 million, to $5.0 million for the year ended December 31, 2003 from $4.1 million for 2002. The increase is primarily due to higher sales volumes in 2003 versus 2002 and an increase in our average DD&A rate from $3.73 per Bbl in 2002 to $4.78 per Bbl in 2003. Accretion expense for 2003 was $0.2 million. Accretion expense represents the adjustment of our asset retirement obligation to its present value at the end of the period.

Other operating expenses. Other operating expenses for 2003 and 2002 include $0.1 million losses on the disposition of materials and supplies inventory.

Equity in earnings of Plains All American Pipeline, L.P. Our equity in earnings of PAA decreased $3.7 million to $15.1 million for 2003 from $18.8 million for 2002 due to lower PAA earnings and a decrease in our ownership in PAA as a result of its 2003 equity offerings. PAA had net income of $59.4 million for 2003 compared to $65.3 million in 2002. Our equity in earnings of PAA was reduced by approximately $7.7 million pre-tax as a result of a $28.8 million compensation accrual by PAA

associated with PAA’s assessment of the probable vesting in 2004 of restricted unit grants pursuant to PAA’s long term incentive plan and a noncash loss on debt refinancing of $3.3 million recognized by PAA in 2003. Our ownership interest in PAA was 22% at December 31, 2003 and 25% at December 31, 2002.

Gain on Plains All American Pipeline, L.P. unit offerings and subordinated unit conversion. In the years ended December 31, 2003 and 2002 we recognized noncash gains totaling $23.5 million and $14.5 million, respectively related to PAA’s public equity offerings in these periods. The gains are recognized to reflect our proportionate share of the increase in the underlying net assets of PAA resulting from the equity offerings. In the fourth quarter of 2003 we recognized a noncash gain of $9.7 million related to the conversion of one fourth of our PAA subordinated units to common units. The gain is recognized to reflect our proportionate share of the increase in the underlying net assets of PAA resulting from the conversion.

Gain (loss) on derivatives. As previously discussed, we were required to discontinue hedge accounting effective February 1, 2003. As a result, in the year ended December 31, 2003 we recorded a $6.7 million loss on derivatives that consisted of a $4.3 million loss in fair value and $2.4 million in settlement losses.

Loss on debt extinguishment. In 2002 we incurred a $10.3 million loss from the early retirement of $267.5 million of outstanding 10.25% notes. The expense included a call premium of 3.4167% on the outstanding principal amount of the 10.25% notes, or $9.1 million, and approximately $1.2 million related to unamortized premiums on the 10.25% notes and unamortized issue costs on the 10.25% notes and our credit facility.

Interest expense. Interest expense decreased $3.7 million, to $2.2 million for 2003 from $5.9 million for 2002, primarily reflecting lower outstanding debt.

Income tax expense. Income tax expense increased $10.4 million to $16.5 million for 2003 from $6.1 million for 2002. The increase was primarily due to higher pre-tax income from continuing operations as well as an increase in our effective tax rate, from 39% in 2002 to 45% in 2003.

Our effective tax rate reflects the Canadian taxes attributable to our share of PAA’s earnings related to their Canadian operations. Since, for U.S. federal income tax purposes, we utilize net operating loss carryforwards, or NOLs, to reduce our currently payable taxes, we receive a deduction rather than a credit for Canadian income taxes. As a result of the double taxation of such Canadian earnings, our effective tax rate is higher than would normally be expected. Current income tax expense for 2003 and 2002 includes benefits of approximately $2.0 million and $2.9 million, respectively, representing tax paid in prior periods that was refunded to us as the result of certain legislation that allowed us to offset 100% of alternative minimum taxable income with NOLs. Previously, we could only offset 90% of AMT income with NOLs. The current income tax benefit is offset by a corresponding charge to deferred income tax expense. This change in the regulations did not change our overall effective tax rate and had no effect on net income.

Cumulative effect of accounting change. In the first quarter of 2003 we recognized a $0.9 million net of tax gain related to the adoption of Statement of Accounting Standards, or SFAS, No. 143, “Accounting for Asset Retirement Obligations”. See “Recent Accounting Pronouncements” for a discussion of the adoption of SFAS No. 143.

Income from discontinued operations. Income from discontinued operations of $27.8 million in 2002 reflects the net after tax earnings of PXP, which was spun off in the fourth quarter of 2002.

Comparison of Year Ended December 31, 2002 to Year Ended December 31, 2001

In 2002, we reported net income of $37.5 million compared to net income of $153.3 million in 2001. Income from continuing operations was $9.7 million in 2002 compared to $100.6 million for 2001. Results for 2001 were affected by special items including $170.2 million of pre-tax gains related to the sale of a portion of our ownership interest in PAA and PAA’s equity offerings.

Oil revenues. Our oil revenues increased 17%, or $2.7 million, to $18.7 million for the year ended December 31, 2002 from $16.0 million for the year ended December 31, 2001. The increase was primarily due to higher realized oil prices that increased revenues by $6.8 million in 2002 versus 2001. This increase was offset by lower sales volumes that decreased revenues by $4.1 million in 2002.

We reported sales volumes from our Florida properties of 869 MBbls in 2002 compared to 1,060 MBbls in 2001. In accordance with SEC Staff Accounting Bulletin 101, or SAB 101, we reflect revenue from oil production in the period it is sold as opposed to when it is produced. Oil volumes increased 2% on an “as produced” basis, with production volumes of 970 MBbls in 2002 compared to 954 MBbls in 2001.

Our average realized price for oil excluding transportation costs increased 42%, or $6.34, to $21.47 per Bbl for the year ended December 31, 2002 from $15.13 per Bbl for the prior year. The increase is primarily attributable to an improvement in the location and quality differential to NYMEX, which was $3.97 per Bbl in 2002 versus $9.77 per Bbl in 2001. The average NYMEX oil price increased slightly to $26.15 per Bbl in 2002 compared to $26.01 per Bbl in 2001. Hedging had the effect of decreasing our average price per Bbl by $0.71 in 2002 and $1.11 in 2001.

Production expenses. Our production expenses decreased 17%, or $1.2 million, to $5.8 million for the year ended December 31, 2002 from $7.0 million for 2001 primarily due to lower reported sales volumes. Unit production expenses for 2002 were $6.72 per Bbl compared to $6.63 in 2001.

Production and ad valorem taxes. Production and ad valorem taxes increased $0.2 million, to $0.6 million for 2002 from $0.4 million for 2001 primarily due to the expiration of severance tax exemptions for several wells. Unit production and ad valorem taxes were $0.67 per Bbl for 2002 compared to $0.35 per Bbl in 2001.

Oil transportation expenses. Our oil transportation costs decreased 14% to $3.8 million in 2002 from $4.4 million in 2001 primarily reflecting lower sales volumes.

General and administrative expense. Our general and administrative, or G&A expense, decreased 49%, or $5.4 million, to $5.7 million for the year ended December 31, 2002 from $11.1 million for the prior year. The decrease primarily reflects the $8.7 million of nonrecurring costs in 2001 related to our June 2001 strategic restructuring, partially offset by a lower amount of G&A expenses being capitalized in 2002.

Depreciation, depletion, amortization and accretion, or DD&A. DD&A expense decreased 15%, or $0.7 million, to $4.1 million for the year ended December 31, 2002 from $4.8 million for 2001. The decrease is primarily due to lower sales volumes in 2002 versus 2001. Our average DD&A rate for 2002 was $3.73 per Bbl compared to $2.74 per Bbl in 2001.

Equity in earnings of Plains All American Pipeline, L.P. Our equity in earnings of PAA increased slightly to $18.8 million for the year ended December 31, 2002 from $18.5 million for the 2001. Although PAA’s net income increased from $44.2 million in 2001 to $65.3 million in 2002, our overall effective ownership was reduced to approximately 25% as of December 31, 2002 from 54% in January 2001. The reduced ownership interest is a result of the sale of a portion of our interest in June 2001 and PAA’s subsequent equity offerings.

Gain on PAA units. In 2002 we recognized a noncash gain of $14.5 million due to the increase in the book value of our equity in PAA to reflect our proportionate share of the increase in the underlying net assets of PAA resulting from PAA’s public equity offering.

The 2001 gain on PAA units reflects: (i) $129.4 million in gains related to the sale of a portion of our ownership interest in PAA in connection with our June 2001 strategic restructuring; (ii) $38.8 million of gains resulting from the increase in the book value of our equity in PAA to reflect our proportionate share of the increase in the underlying net assets of PAA resulting from PAA’s 2001 public equity offerings, in which we did not participate; and (iii) a $2.0 million gain related to the vesting of certain unit grants.

Loss on debt extinguishment. We incurred a $10.3 million loss on debt extinguishment in 2002 primarily from the early retirement of $267.5 million of outstanding 10.25% senior subordinated notes. The loss consisted of a call premium of 3.4167% on the outstanding principal amount of the 10.25% notes, or $9.1 million, and $3.1 million of unamortized issue costs on the 10.25% notes and our revolving credit facility, net of $1.9 million of unamortized issue premium on the 10.25% notes.

Interest expense. Our interest expense decreased $3.1 million, to $5.9 million for the year ended December 31, 2002 from $9.0 million for 2001. The decrease is due to the redemption of the 10.25% notes and the repayment of amounts outstanding under our revolving credit facility on July 3, 2002. From this date through early December 2002, when we borrowed $45 million under our tem loan facility, we had no outstanding debt. Outstanding debt during this period was debt of PXP and accordingly, interest expense for this period is reflected in discontinued operations.

Income tax expense. Our income tax expense decreased $61.0 million to $6.1 million for the year ended December 31, 2002. The decrease was primarily due to lower pre-tax income from continuing operations. Pre-tax income from continuing operations was significantly higher in 2002 as a result of the gains related to the sale of the PAA interest.

Income from discontinued operations. Income from discontinued operations decreased from $54.7 million in 2001 to $27.8 million in 2002, primarily reflecting lower revenues due to lower realized prices partially offset by higher sales volumes, higher costs and expenses, and expenses related to a terminated public equity offering.

Liquidity and Capital Resources

General

At December 31, 2003 we had negative working capital of $19.5 million. Cash generated from our upstream operations and PAA distributions are our primary sources of liquidity. We believe that we have sufficient liquid assets and cash from operations and PAA distributions to meet our short term and long-term normal recurring operating needs, debt service obligations, contingencies and anticipated capital expenditures.

If PAA could not, for any reason, make its minimum quarterly distribution payments on its limited partnership interests, this would impair our cash flows and our ability to meet our short and long-term cash needs. Thus, PAA’s financial and operational performance directly affects our financial and operational performance. We encourage you to review PAA’s SEC filings, including its Annual Report on Form 10-K for the year ended December 31, 2003.

PAA Cash Distributions

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.

We own 1.3 million Class B common units. 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 (the “MQD”). Generally the general partner is entitled, 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.

Cash distributions on PAA’s outstanding common units and Class B common units and the portion of the distributions representing an excess over the MQD for 2003, 2002 and 2001 were as follows:


	Year Ended December 31,
	2003				2002				2001
	Distribution		Excess over MQD		Distribution		Excess over MQD		Distribution		Excess over MQD
First Quarter	$	0.5375	$	0.0875	$	0.5250	$	0.0750	$	0.4750	$	0.0250
Second Quarter	$	0.5500	$	0.1000	$	0.5375	$	0.0875	$	0.5000	$	0.0500
Third Quarter	$	0.5500	$	0.1000	$	0.5375	$	0.0875	$	0.5125	$	0.0625
Fourth Quarter	$	0.5500	$	0.1000	$	0.5375	$	0.0875	$	0.5125	$	0.0625

Financing Activities

At December 31, 2003, $50.0 million was outstanding under the secured term loan facility. The term loan is repayable in twelve quarterly installments of $5.0 million each, that commenced on August 31, 2003 with a final maturity of May 31, 2006. Amounts outstanding under the term loan bear an annual interest rate, at our election, equal to either the Base Rate (as defined in the agreement) plus 1.5%, or LIBOR plus 3%. The term loan requires that we maintain $5.0 million on deposit in a debt service reserve account with one of the lending banks. Our average borrowing rate for 2003 was 4.3% (4.2% at December 31, 2003).

To secure the term loan, we pledged 100% of the shares of stock of our subsidiaries, pledged 5.2 million of our PAA common units and delivered mortgages on Calumet’s oil and gas properties. To the extent the outstanding principal under the term loan exceeds the balance in the debt service reserve account plus 50% of the fair market value of the pledged common units, we are required to repay the excess. The fair market value of the pledged units is determined based on the closing price of PAA common units as reported on the New York Stock Exchange.

The term loan contains covenants that limit our ability, as well as the ability of our subsidiaries, to incur additional debt, make investments, create liens, enter into leases, sell assets, 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 capital stock. The term loan requires us to maintain a minimum consolidated tangible net worth (as defined) and a consolidated debt service coverage ratio (as defined in the agreement) of 1.0 to 1.0. At December 31, 2003, we were in compliance with the covenants contained in the term loan facility.

Cash Flows from Continuing Operations


	Year Ended December 31,
	2003			2002			2001
	(in millions)
Cash provided by (used in):
Operating activities	$	27.0		$	7.6		$	3.3
Investing activities		(5.4	)		(7.3	)		96.5
Financing activities		(25.9	)		(235.4	)		(90.7	)

Operating Activities. Net cash provided by operating activities in 2003 totaled $27.0 million compared to $7.6 million in 2002. The increase primarily reflects the absence of debt extinguishment costs in 2003 and the negative effect in 2002 of the decrease in current liabilities reflecting the payment of costs incurred in prior periods. Net cash provided by operating activities in 2002 totaled $7.6 million compared to $3.3 million in 2001. The net increase is primarily attributable to higher realized oil prices and increased sales volumes.

Investing Activities. In 2003 net cash used in investing activities totaled $5.4 million. Additions to oil and gas properties and equipment used $3.1 million in cash, and we made capital contributions to PAA of $2.3 million to maintain our proportionate general partner share interest as a result of equity offerings by PAA. In 2002 net cash used in investing activities totaled $7.3 million. Additions to oil and gas properties and equipment used $5.9 million in cash, and we made capital contributions to PAA of $1.3 million to maintain our proportionate general partner share interest as a result of equity offerings by PAA. In 2001 net cash provided by investing activities was $96.5 million. Additions to oil and gas properties and equipment used $6.0 million in cash, and we made capital contributions to PAA of $4.0 million to maintain our proportionate general partner share of equity offerings by PAA. These uses of cash were offset by $106.9 million in cash proceeds received as a result of our June 2001 strategic restructuring.

Financing activities. Cash used in financing activities in 2003 included a net increase in long-term debt of $5.0 million, $2.8 million in proceeds from issuances of our common stock, $23.3 million to retire our outstanding Series D preferred stock, $9.0 million in treasury stock purchases and $0.6 million in preferred stock dividends. Cash used in financing activities in 2002 included a net reduction in long-term debt of $234.0 million, $5.2 million in proceeds from issuances of our common stock, and $1.4 million in preferred stock dividends. Cash used in financing activities in 2001 included a net

reduction in long-term debt of $23.4 million, expenditures of $67.7 million for our repurchase of 2.8 million shares of our common stock, $9.2 million in proceeds from issuances of our common stock, and $8.7 million in preferred stock dividends.

Capital Expenditures

We have made and will continue to make capital expenditures with respect to our oil properties. We intend to make aggregate capital expenditures of approximately $3.5 million in 2004 for exploitation of our existing properties. These expenditures will be funded with cash from operations and PAA distributions.

When PAA issues equity, the general partner is required to contribute cash to maintain its 2% general partner interest. In 2003 PAA issued units in public equity offerings and we were required to make cash capital contributions to the general partner of PAA totaling $2.3 million for our 44% interest in the general partner. If PAA issues equity in the future, we will be required to make additional cash capital contributions.

Contractual Obligations

At December 31, 2003, the aggregate amounts of contractually obligated payment commitments for the next five years are as follows (in thousands):


	2004		2005		2006		2007		2008		Total
Long-term debt	$	20,000	$	20,000	$	10,000	$	—	$	—	$	50,000
Operating leases		23		23		6		—		—		52

	$	20,023	$	20,023	$	10,006	$	—	$	—	$	50,052

Of such amounts, $20.0 million is due in less than one year and the total amount is due in one to three years.

Commitments and Contingencies

Environmental Matters. As discussed under “Business & Properties—Regulation—Environmental.” as an owner or lessee and operator of oil and gas properties, we are subject to various federal, state, and local laws and regulations relating to discharge of materials into, and protection of, the environment. Typically when producing oil and gas assets are purchased, one assumes the obligation to plug and abandon wells that are part of such assets. We have established policies for continuing compliance with environmental laws and regulations. Also, we maintain insurance coverage for environmental matters, which we believe is customary in the industry, but we are not fully insured against all environmental risks. There can be no assurance that current or future local, state or federal rules and regulations will not require us to spend material amounts to comply with such rules and regulations.

Plugging, Abandonment and Remediation Obligations. Consistent with normal industry practices, our oil and gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. Typically when producing oil and gas assets are purchased, one assumes the obligation to plug and abandon wells that are part of such assets. We have estimated that at December 31, 2003 the costs to perform these tasks will be approximately $8.1 million, net of salvage value.

Operating risks and insurance coverage. Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and gas, including well blowouts, cratering, explosions, spills of oil, gas or well fluids, fires, pollution and releases of toxic gas, each of which could result in damage to or destruction of oil and gas wells, production facilities or other property, or injury to persons. Although we maintain insurance coverage considered to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of high premium costs. The occurrence of a significant event that is not fully insured against could have a material adverse effect on our financial position. Our insurance does not cover every potential risk associated with operating our pipelines, including the potential loss of significant revenues. Consistent 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.

Other commitments and contingencies. As is common within the industry, we have entered into various commitments and operating agreements related to the exploration and development of and production from proved oil and gas properties and the marketing, transportation, terminalling and storage of oil. It is management’s belief that such commitments will be met without a material adverse effect on our financial position, results of operations or cash flows.

As discussed under “Legal Proceedings”, in the ordinary course of business, we are a claimant or defendant in various legal proceedings. In particular, we are a defendant in a number of lawsuits related to the sale of the Company. See Item 3.—Legal Proceedings.

PAA’s Commitments and Contingencies

For a discussion of PAA’s commitments and contingencies, we recommend you review PAA’s Annual Report on Form 10-K for the year ended December 31, 2003, and other applicable SEC filings by PAA.

Material Related Party Transactions

Governance of PAA

We, along with Sable Investments, L.P. (which is owned by Mr. Flores, our Executive Chairman, and Mr. Raymond, our Chief Executive Officer), Kafu Holdings, L.P. (which is controlled by Kayne Anderson Capital Advisors, L.P. and Kayne Anderson Investment Management, Inc., of which Mr. Sinnott is Senior Vice President), and E-Holdings III, L.P. (which is controlled by EnCap Investments L.L.C. and of which Mr. Phillips is a managing director and principal) are parties to agreements governing Plains All American GP LLC, which is the general partner of Plains AAP, L.P., and Plains AAP, L.P., which is the general partner of PAA. These agreements govern the ongoing management of PAA.

In addition, the general partner of PAA is owned as follows:


Plains Resources	44.00	%
Sable Investments, L.P.	20.00	%
Kafu Holdings, L.P.	16.42	%
E-Holdings, L.P.	9.00	%
Others	10.58	%

	100.00	%

Also, each of we, Sable Investments, Kafu Holdings, and E-Holdings may appoint one member of the Plains All American GP LLC board of directors. Under a Voting and Designation Agreement dated December 18, 2003, we have the right to direct Sable Investments to appoint the person we designate as director of Plains All American GP LLC.

Our Relationship with PAA

We have ongoing relationships with PAA, including:

•

a marketing agreement that provides that PAA will purchase all of our equity oil production at market prices for a fee of $.20 per barrel. In 2003, PAA paid us $26.2 million for such equity production, including the royalty share of production, and we paid PAA $0.2 million in marketing fees;

•

a separation agreement 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.

Our Relationship with PXP

In connection with the spin-off we entered into certain agreements with PXP, including a master separation agreement; an intellectual property agreement; the Plains Exploration & Production transition services agreement that expires June 16, 2004; the Plains Resources transition services agreement that expires June 8, 2004; and a technical services agreement that expires July 2005. For the year ended December 31, 2003, PXP billed us $0.5 million for services provided to us under these agreements and we billed PXP $0.1 million for services we provided under these agreements.

Industry Concentration

Financial instruments which potentially subject us to concentrations of credit risk consist principally of accounts receivable with respect to our oil operations and derivative instruments related to our hedging activities. PAA is the exclusive marketer/purchaser for all of our equity oil production. This concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that PAA may be affected by changes in economic, industry or other conditions. We do not believe the loss of PAA as the exclusive purchaser of our equity production would have a material adverse affect on our results of operations. We believe PAA could be replaced by other purchasers under contracts with similar terms and conditions.

There are a limited number of alternative methods of transportation for our production. 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 result in our having to find transportation alternatives, increased transportation costs or involuntary curtailment of a significant portion of our oil production which could have a negative impact on future results of operations or cash flows.

The contract counterparties for our derivative commodity contracts are all major financial institutions with Standard & Poor’s ratings of A or better.

Critical Accounting Policies and Factors That May Affect Future Results

Based on the accounting policies which we have in place, certain factors may impact our future financial results. The most significant of these factors and their effect on certain of our accounting policies are discussed below.

Commodity pricing and risk management activities. Prices for oil have historically been volatile. Decreases in oil prices from current levels will adversely affect our revenues, results of operations, cash flows and proved reserves. If the industry experiences significant prolonged future price decreases, this could be materially adverse to our operations and our ability to fund planned capital expenditures.

Periodically, we enter into hedging arrangements relating to a portion of our oil production to achieve a more predictable cash flow, as well as to reduce our exposure to adverse price fluctuations. Hedging instruments used are typically fixed price swaps and collars and purchased puts and calls. While the use of these types of hedging instruments limits our downside risk to adverse price movements, we are subject to a number of risks, including instances in which the benefit to revenues is limited when commodity prices increase. For a further discussion concerning our risks related to oil prices and our hedging programs, see “Item 7A—Quantitative and Qualitative Disclosures about Market Risks”.

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

•

the standardized measure (including, for this test only, the effect of any related hedging activities); plus

•

the lower of cost or fair value of unproved properties not included in the costs being amortized (net of related tax effects).

These rules generally require that we price our future oil production at the prices in effect at the end of each fiscal quarter and require a write-down if our capitalized costs exceed this “ceiling,” even if prices declined for only a short period of time. We have had no write-downs due to these ceiling test limitations since 1998. Given the volatility of oil prices, it is likely that our estimate of discounted future net revenues from proved oil reserves will change in the near term. If oil prices decline in the future, even if only for a short period of time, write-downs of our oil and gas properties could occur. Write-downs required by these rules do not directly impact our cash flows from operating activities.

Based on the book value of our proved oil and gas properties (including related deferred income taxes) and our proved reserve reports as of December 31, 2003, we believe that we would have a write-down under the full cost ceiling test rules at a net realized price for our oil production of approximately $17.00 to $19.00 per barrel. Based on an estimated oil differential at December 31, 2003 of $11.75 per barrel, we would have a write-down at a NYMEX oil index price of $28.75 to $30.75 per barrel.

Oil and gas reserves. The proved reserve information included herein was based on estimates prepared by an outside engineering firm. Estimates prepared by others may be higher or lower than these estimates.

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

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

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

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

PAA’s Critical Accounting Policies. For a discussion of PAA’s critical accounting policies, we recommend you review PAA’s Annual Report on Form 10-K for the year ended December 31, 2003, and other applicable SEC filings by PAA.

Recent Accounting Pronouncements

The Financial Accounting Standards Board (FASB) issued Financial Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities” in January 2003. FIN 46 addresses the consolidation of variable interest entities (VIEs) by business enterprises that are the primary beneficiaries. A VIE is an entity that does not have sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or whose equity investors lack the characteristics of a controlling financial interest. The primary beneficiary of a VIE is the enterprise that has the majority of the risks or rewards associated with the VIE. In December 2003, the FASB issued a revision to FIN 46, Interpretation No. 46R (FIN 46R), to clarify some of the provisions of FIN 46, and to exempt certain entities from its requirements. Application of FIN 46R is required in financial statements of public entities that have interests in structures that are commonly referred to as special-purpose entities for periods ending after December 15, 2003. Application for all other types of VIEs is required in financial statements for periods ending after March 15, 2004. We do not believe we participate in any arrangement that would be subject to the provisions of FIN 46R.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

We are exposed to various market risks, including volatility in oil commodity prices and interest rates. To manage our exposure, we monitor current economic conditions and our expectations of future commodity prices and interest rates when making decisions with respect to risk management. We do not enter into derivative transactions for speculative trading purposes.

We have entered into various derivative instruments to reduce our exposure to fluctuations in the market price of oil. The derivative instruments consist of oil swaps entered into with financial institutions. Derivative instruments are accounted for in accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” as amended, or SFAS 133. All derivative instruments are recorded on the balance sheet at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. If the derivative qualifies for hedge accounting, the gain or loss on the derivative is deferred in Accumulated Other Comprehensive Income (“OCI”), a component of our stockholders’ equity, to the extent the hedge is effective. Gains and losses on oil hedging instruments related to OCI and adjustments to carrying amounts on hedged volumes are included in oil revenues in the period that the related volumes are delivered.

The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. Hedge accounting is discontinued prospectively when a hedge instrument becomes ineffective. Gains and losses deferred in OCI related to cash flow hedges that become ineffective remain unchanged until the related product is delivered. If it is determined that it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are recognized in earnings immediately.

We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. Hedge effectiveness is measured at least on a quarterly basis. This process includes specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.

In the first quarter of 2003, the NYMEX oil price and the price we received for our Florida oil production did not correlate closely enough for the hedges to qualify for hedge accounting. As a result, we were required to discontinue hedge accounting effective February 1, 2003 and reflect the mark-to-market value of the hedges in earnings prospectively from that date. In 2003, we recorded a $6.7 million loss on derivatives that consisted of a $4.3 million loss for the decrease in the fair value of our derivatives and a $2.4 million loss on cash settlements of such derivatives. In addition a $0.3 million loss on cash settlements for January 2003 is reflected as a reduction of revenues. None of our current hedges qualify for hedge accounting.

At December 31, 2003, Accumulated OCI consisted of unrealized losses of $0.3 million ($0.2 million, net of tax) on our oil hedging instruments generated prior to the discontinuation of hedge accounting, unrealized losses of $0.5 million ($0.3 million, net of tax) related to pension liabilities and an unrealized gain of $7.0 million ($3.9 million, net of tax) related to our equity in the OCI gains of PAA. At December 31, 2003, the liability related to our open oil derivative instruments was included in current liabilities ($2.8 million), other long-term liabilities ($1.8 million), and deferred income taxes (a tax benefit of $0.1 million).

As of December 31, 2003, $0.3 million ($0.2 million, net of tax) of deferred net losses on our oil derivative instruments recorded in OCI are expected to be reclassified to earnings during the following twelve month period as the hedged volumes are produced and sold.

Commodity Price Risk. At February 29, 2004, we had the following open oil derivative positions:


	2004	2005	2006
Swaps
Average price $25.01/bbl	1,500	—	—
Average price $24.70/bbl	—	1,000	—
Average price $24.43/bbl	—	—	1,000

Assuming our fourth quarter 2003 production volumes are held constant in subsequent periods, these positions result in our hedging approximately 66%, 44% and 44% of oil production in 2004, 2005 and 2006, respectively. Location and quality differentials attributable to our properties are not included in the foregoing prices. Because of the quality and location of our oil production, these adjustments will reduce our net price per barrel.

The fair value of outstanding oil derivative commodity instruments and the change in fair value that would be expected from a 10 percent price decrease are shown in the table below (in millions):


	December 31,
	2003					2002
	Fair Value			Effect of 10% Price Decrease		Fair Value			Effect of 10% Price Decrease
Swaps and options contracts	$	(1.0	)	$	3.6	$	(0.4	)	$	1.9

The fair value of the swaps is estimated based on quoted prices from independent reporting services compared to the contract price of the swap and approximate the gain or loss that would have been realized if the contracts had been closed out at year end. All hedge positions offset physical positions exposed to the cash market. None of these offsetting physical positions are included in the above table. Price-risk sensitivities were calculated by assuming an across-the-board 10 percent decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10 percent change in prompt month oil prices, the fair value of our derivative portfolio would typically change less than that shown in the table due to lower volatility in out-month prices.

Our management intends to continue to maintain hedging arrangements for a significant portion of our production. These contracts may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if oil prices decline below the prices at which these hedges are set, but ceiling prices in our hedges may cause us to receive less revenue on the hedged volumes than we would receive in the absence of hedges. The contract counterparties for our current derivative commodity contracts are all major financial institutions with Standard & Poor’s ratings of A or better.

Interest Rate Risk. Our debt instruments are sensitive to market fluctuations in interest rates. At December 31, 2003 we had $50.0 million outstanding under our credit facility, repayable $20.0 million in 2004, $20.0 million in 2005 and $10.0 million in 2006. Our credit facility bears interest at a base rate (as defined) or LIBOR plus the applicable margin (4.2% at December 31, 2003). The carrying value of our credit facility debt approximates fair value because interest rates are variable, based on prevailing market rates.

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required here is included in this report as set forth in the “Index to Financial Statements” on page F-1.

The financial statements, including the notes thereto, of PAA are incorporated herein by reference to pages F-1 through F-36 of PAA’s Annual Report on Form 10-K for the year ended December 31, 2003 (as may be amended from time to time). The PAA financial statements were prepared by PAA.

Item 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Item 9A. CONTROLS AND PROCEDURES

Under the supervision and with the participation of our management, including our Chief Executive Officer (our principal executive officer) and our Chief Financial Officer (our principal financial officer), we evaluated the effectiveness of our disclosure controls and procedures (as defined under Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on this evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures as of December 31, 2003 are effective to ensure that information we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

During our fourth fiscal quarter ended December 31, 2003, there was no change in our internal control over financial reporting that has materially affected or is reasonably likely to materially affect our internal control over financial reporting.

PART III

Item 10. EXECUTIVE OFFICERS OF THE REGISTRANT

Identification

Our directors and executive officers are identified and the business experience of each is given in Item 4—“Submission of Matters to a Vote of Security Holders” above.

Board of Directors and Committees

Plains’ board has established a Policy Concerning Corporate Ethics and Conflicts of Interest. This policy applies to all our employees, including our chief executive officer, chief financial officer and principal accounting officer. Any shareholder may request a copy of Plains’ Corporate Governance Guidelines and/or Policy Concerning Corporate Ethics and Conflicts of Interest, free of charge, by sending a request to Corporate Secretary, Plains Resources Inc., 700 Milam, Suite 3100, Houston, Texas 77002.

Plains’ non-management directors intend to meet periodically in executive session. There is not one single non-management director who has been chosen to preside over executive sessions of Plains’ board of directors.

Plains’ board has established an audit committee, an organization and compensation committee and a nominating and corporate governance committee. Plains’ board may establish other committees

from time to time to facilitate Plains’ management. During 2003 Plains’ board held five meetings. No director attended fewer than 75% of the total number of meetings of the meetings of Plains’ board and committees on which he served.

Plains’ audit committee currently consists of Messrs. O’Malley, Hitchcock, Phillips, Sinnott and Symonds, with Mr. O’Malley acting as chairman. Plains’ audit committee selects Plains’ independent auditors to be engaged by Plains, reviews the plan, scope and results of Plains’ annual audit and discusses with the independent auditor any significant matters regarding internal controls over financial reporting that have come to their attention during the audit. Plains’ audit committee has adopted a written audit committee charter. The Audit Committee’s charter, as amended, was attached to the Company’s 2003 proxy statement. During 2003, Plains’ audit committee held six meetings. All of the members of Plains’ audit committee are non-employee directors. Plains’ board of directors, in its business judgment, has determined that all current members of Plains’ audit committee are “independent” as defined in the NYSE governance rules (and Item 7(d)(3)(iv) of Schedule 14A under the Exchange Act) and are “financially literate” in compliance with the NYSE listing standards as the Plains’ board of directors interprets that designation. In addition, the Plains’ board of directors has determined that Mr. O’Malley is an “audit committee financial expert” as defined in Item 401(h)(2) of Regulation S-K. In making its determination, the board recognized Mr. O’Malley’s experience in public accounting and as a chief executive officer directly supervising the principal financial officer.

Plains’ organization and compensation committee currently consists of Messrs. Hitchcock, O’Malley and Symonds, with Mr. Hitchcock acting as chairman. Plains’ organization and compensation committee reviews and sets the chief executive officer’s compensation, establishes guidelines and standards relating to the determination of executive compensation, reviews executive compensation policies and recommends to Plains’ entire board compensation for Plains’ executive officers other than the chief executive officer and key employees. Plains’ organization and compensation committee also administers Plains’ equity compensation plan and determines the number of shares covered by, and terms of, grants to executive officers and key employees. All of the members of Plains’ compensation committee are non-employee directors. During 2003, Plains’ organizational and compensation committee held two meetings.

Plains’ nominating and corporate governance committee currently consists of Messrs. Sinnott, O’Malley, Hitchcock, Phillips, and Symonds, with Mr. Sinnott acting as chairman. Plains’ nominating and corporate governance committee identifies and evaluates candidates for election as directors, nominates the slate of directors for election by Plains’ stockholders, and develops and recommends to Plains’ board Plains’ corporate governance principles. During 2003, Plains’ nominating and corporate governance committee held no meetings.

Section 16(A) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934, as amended, requires the Company’s’ directors and executive officers, and persons who own more than ten percent of a registered class of Plains’ equity securities, to file with the SEC and any exchange or other system on which such securities are traded or quoted, initial reports of ownership and reports of changes in ownership of Plains common stock and other equity securities. Officers, directors and greater than ten percent stockholders are required by the SEC’s regulations to furnish Plains with copies of all Section 16(a) forms they filed with the SEC.

To the Company’s’ knowledge, based solely on a review of the copies of such reports furnished to Plains and written representations that no other reports were required, the Company believes that all reporting obligations of the Company’s officers, directors and greater than ten percent stockholders under Section 16(a) were satisfied during the first six months of the year ended December 31, 2003,

except that (i) a Form 4 covering one transaction for the grant of restricted stock units related to 15,000 shares of the Company’s common stock to Franklin R. Bay was filed late, (ii) two Forms 4 covering one transaction each for the grant of common stock in accordance with a 2001 agreement and for the grant of restricted stock units related to 20,000 shares of the Company’s common stock to James C. Flores were filed late, (iii) a Form 4 covering one transaction for the exercise of a stock option by William M. Hitchcock was filed late, (iv) two Forms 4 covering one transaction each for the acquisition of 163 and 155 shares, respectively, of the Company’s common stock in lieu of director’s fees by William C. O’Malley were filed late; (v) a Form 4 covering one transaction for the grant of restricted stock units related to 10,000 shares of the Company’s common stock to D. Martin Phillips was filed late; (vi) a Form 4 covering one transaction for the grant of restricted stock units related to 40,000 shares of the Company’s common stock to John T. Raymond was filed late, (vi) three Forms 4 covering one transaction each for the acquisition of 375, 172 and 338 shares, respectively, of the Company’s common stock in lieu of director’s fees by Robert V. Sinnott were filed late, and (vii) a Form 4 covering one transaction for the grant of restricted stock units related to 20,000 shares of the Company’s common stock to Stephen A. Thorington was filed late. No forms were filed late after June 12, 2003.

Item 11. EXECUTIVE COMPENSATION

Summary Compensation Table

The following table shows certain compensation information for our chief executive officer and the two highly compensated executive officers whose 2003 salary and bonus exceeded $100,000, or named executive officers, for services rendered in all capacities during the fiscal years ended December 31, 2003, 2002 and 2001.


					Long Term Compensation
					Awards				Payouts
Name and Principal Position	Year	Annual Compensation			Restricted Stock Award(s) ($)(2)		Securities Underlying Options/ SARs (#)		LTIP Payouts ($)	All Other Compensation ($)(3)
Name and Principal Position	Year	Salary ($)	Bonus ($)		Restricted Stock Award(s) ($)(2)		Securities Underlying Options/ SARs (#)		LTIP Payouts ($)	All Other Compensation ($)(3)
James C. Flores	2003	100,000	50,000	(4)	210,000	(5)	–0–		–0–	–0–
Chairman of the Board(1)	2002	4,167	100,000		750,600	(6)	475,000		–0–	11,000
	2001	–0–	325,000				1,000,000	(7)	–0–	–0–

John T. Raymond	2003	150,000	75,000	(4)	420,000	(5)	–0–		–0–	–0–
President and Chief	2002	389,584	150,000		938,250	(9)	425,000		–0–	11,000
Executive Officer(8)	2001	187,500	788,000		–0–		300,000		–0–	–0–

Stephen A. Thorington	2003	100,000	50,000	(4)	210,000	(5)	–0–			–0–
Executive Vice President and	2002	91,667	33,333		1,059,750	(11)	–0–		–0–	–0–
Chief Financial Officer(10)

(1)	Mr. Flores joined us as Chairman of the Board and Chief Executive Officer in May 2001 and became Executive Chairman of the Board in December 2002.

(2)	These dollar amounts represent the closing price of a share of our common stock on the restricted stock or restricted stock unit grant date as reported on the New York Stock Exchange multiplied by the number of restricted shares or units granted on such date.

(3)

We match 100% of an employee’s contribution to our 401(k) plan, subject to certain limitations in the plan, with matching contributions being made (i) before October 1, 2002, 50% in cash and 50% in our common stock (the number of shares for the stock match being based on the market value of our common stock at the time the shares are issued), and (ii) starting on October 1, 2002, 100% in cash.

(4)	An additional bonus equal to this amount was awarded and was deferred until after the resolution of any open issues relating to the sale of the Company.

(5)

These amounts represent an award of restricted stock units on March 12, 2003 under our 2001 Stock Incentive Plan (calculated as described in footnote 2 above). The award vests on the third anniversary of the grant date, provided that if the closing price of shares of our common stocks equals or exceeds 150% of the of the shares on the grant date ($12.50), then the award will vest 18 months after the grant date.

(6)

This was a restricted stock award under our 2001 Stock Incentive Plan. The fair market value at the time of the award was $750,600 (calculated as described in footnote 2 above). The fair market value of this award as of December 31, 2002 (calculated by multiplying the closing price per share of our common stock on December 31, 2002 as reported on the NYSE by the number of restricted shares) was $711,000. The award vests in three equal, annual installments beginning on December 19, 2003. Dividends will be paid on the shares covered by the award and will be held in custody by us until the restricted shares vest.

(7)

Pursuant to Mr. Flores’ original employment agreement with us, we granted Mr. Flores a number of shares of our common stock with a value equal to $1 million. This grant is payable in five equal installments as of each anniversary of May 8, 2001, which is the date of his original employment agreement, in the form of a direct grant of shares of our common stock, the number of which will equal the annual dollar payment amount ($200,000) divided by the fair market value of a share on the applicable anniversary date. The first two installments of this grant were paid on May 8, 2002 and 2003 in the amount of 7,407 shares and 16,625 shares, respectively, of our common stock.

(8)	Mr. Raymond joined us in May 2001 and became Chief Executive Officer in December 2002.

(9)

This was a restricted stock award under our 2001 Stock Incentive Plan. The fair market value at the time of the award was $938,250 (calculated as described in footnote 2 above). The fair market value of this award as of December 31, 2002 (calculated by multiplying the closing price per share of our common stock on December 31, 2002 as reported on the NYSE by the number of restricted shares) was $888,750. The award vests in three equal, annual installments beginning on December 19, 2003. Dividends will be paid on the shares covered by the award and will be held in custody by us until the restricted shares vest.

(10)	Mr. Thorington joined us in December 2002.

(11)

This was a restricted stock award under our 2001 Stock Incentive Plan. The fair market value at the time of the award was $1,059,750 (calculated as described in footnote 2 above). The fair market value of this award as of December 31, 2002 (calculated by multiplying the closing price per share of our common stock on December 31, 2002 as reported on the NYSE by the number of restricted shares) was $533,250. The award vests in three equal, annual installments beginning on September 3, 2003. Dividends will be paid on the shares covered by the award and will be held in custody by us until the restricted shares vest.

Option Grants in 2003

There were no stock options or stock appreciation rights granted to any named executive officer.

Aggregated Option Exercises in 2003 and Year-End Option Values

The following table sets forth certain information for each named executive officer concerning option exercises during 2003 and all unexercised options held at December 31, 2003.

Name

Shares
Acquired on
Exercise (#)

Value
Realized
($)

Number of Securities
Underlying Unexercised
Options/SARs

at Fiscal Year-End(#)

Value of Unexercised

In-the-Money Options

at Year-End($)(1)

Exercisable

Unexercisable

Exercisable

Unexercisable

James C. Flores

–0–

99,652

1,375,348

459,694

5,555,556

John T. Raymond

–0–

225,486

499,514

719,104

1,887,646

Stephen A. Thorington

–0–

(1)

Year-end values are determined by aggregating for each option outstanding as of December 31, 2003 the amount calculated by multiplying the number of shares underlying such option by an amount equal to the closing price of our common stock on December 31, 2003, which was $17.70, less the exercise price of such option.

2001 Stock Incentive Plan

We adopted our 2001 stock incentive plan on May 7, 2001. The 2001 plan was amended effective September 10, 2002 and January 1, 2003. The 2001 plan provides for the grant of stock options (including incentive stock options, as defined in Section 422 of the Internal Revenue Code of 1986, as amended, or the Code, and non-qualified stock options) and other awards (including performance units, performance shares, share awards, restricted stock and restricted stock units) to our directors, officers and employees, individuals to whom we have extended written offers of employment, and our consultants and advisors. The Organization and Compensation Committee, which is currently comprised of three directors, each of whom are “non-employee directors” within the meaning of Rule 16b-3 of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and two of whom are “outside directors” under Section 162(m) of the Code, administers the 2001 plan. Four million shares of our common stock are subject to issuance under the 2001 plan, although no more than 1,000,000 of the allotted shares may be the subject of restricted stock awards. The Organization and Compensation Committee may grant stock options on such terms, including vesting and payment forms, as it deems appropriate. However, no option may be exercised more than 10 years after its grant, and the purchase price for incentive stock options and non-qualified stock options may be not less than 100% of the fair market value of our common stock at the time of grant. The Organization and Compensation Committee may grant restricted stock awards, restricted stock unit awards, share awards, performance units and performance shares on such terms and conditions as it may in its discretion decide. Unless terminated earlier by our board of directors, the 2001 plan will terminate on May 6, 2011.

Upon a “change in control” (as defined in the 2001 plan), all options and awards will become immediately exercisable in full for the remainder of their terms. In addition, in such an event, unless otherwise determined by the Organization and Compensation Committee and set forth in the agreement governing the award, performance units and restricted stock units will become immediately vested and restrictions on stock granted pursuant to restricted stock awards will lapse.

At December 31, 2003, we had outstanding options to purchase 3,475,570 shares of our common stock under the 2001 plan.

Employment Contracts and Termination of Employment and Change-in-Control Arrangements

James C. Flores. On September 19, 2002, we entered into a new employment agreement with Mr. Flores that became effective the date after the spin-off of PXP, December 19, 2002, and replaced his

prior employment agreement dated May 8, 2001, which we refer to as Mr. Flores’ Original Agreement. The new agreement has an initial term of five years, although it may be terminated earlier under certain circumstances. At the end of that term and, if that term is extended, each subsequent term, the agreement is subject to a one-year extension if we and Mr. Flores agree to new compensation terms ninety days before the end of the applicable term. The new agreement also acknowledges that Mr. Flores is an officer and director of PXP and therefore will not devote all of his time and attention to us. As Chairman of the Board and Chief Executive Officer of PXP, Mr. Flores will also devote time and attention to, and be compensated by, PXP.

Mr. Flores’ employment agreement provides for an annual salary of $100,000 and a target annual bonus of $100,000, subject to the attainment of performance goals. The agreement provides that the stock options and share grant pursuant to Mr. Flores’ Original Agreement will remain in full force and effect. Pursuant to his Original Agreement, Mr. Flores received a performance option under our 2001 plan to purchase 1,000,000 shares of our common stock at an exercise price of $13.92 per share (as adjusted for the spin off of PXP). The performance option becomes vested and exercisable on the first to occur of:

•

May 7, 2006;

•

with respect to one-half of the shares subject to the performance option, a period of 10 trading days out of 20 consecutive trading days upon which the closing price of our common stock equals or exceeds $20.88 (as adjusted for the spin off);

•

with respect to all shares, a period of 10 trading days out of 20 consecutive trading days upon which the closing price of our common stock equals or exceeds $27.84 (as adjusted for the spin off);

•

termination of Mr. Flores’ employment by us for any reason other than Cause (as defined in his new agreement) or because of Mr. Flores’ death or resignation or by Mr. Flores for Good Reason (as defined in his new agreement);

•

a Change in Control (as defined in his new agreement) of us; or

•

any such time that Mr. Flores is not a member of our board of directors.

In connection with his new employment agreement, in addition to his annual salary and existing stock-based awards, Mr. Flores received a grant of 60,000 restricted shares of our common stock as well as options to purchase 350,000 shares of our common stock under the 2001 plan. The restricted shares vest in three equal, annual installments beginning on December 19, 2003. The options have a grant date of December 19, 2002 and a per share exercise price of $12.51, the closing sales price of our common stock on December 19, 2002. The options have a ten-year term and vest in five equal, annual installments beginning on December 19, 2003. Under his employment agreement, Mr. Flores is entitled to all of the employee benefits, fringe benefits and perquisites we provide to other senior executives.

On March 12, 2003, Mr. Flores was granted 20,000 restricted stock units that vest on the third anniversary of the grant date, provided that if the closing price of shares of our common stocks equals or exceeds 150% of the of the shares on the grant date ($12.50), then the award will vest 18 months after the grant date.

Mr. Flores’ employment agreement provides that if his employment is terminated by us without Cause (as defined in his new agreement), by Mr. Flores’ death or disability, or by Mr. Flores for Good Reason (as defined in his new agreement), we will also pay Mr. Flores $2.5 million. Upon such termination, all then-outstanding stock-based awards Mr. Flores holds will become immediately exercisable and payable in full, with any performance goals associated with the employment

agreement being deemed to have been achieved at the maximum levels. Mr. Flores’ share award under his Original Agreement would become immediately vested and he would be granted a number of shares to be determined by dividing the amount equal to the aggregate unpaid annual installments divided by the fair market value of a share on the date of termination. However, if the share price is less than $13.31 (as adjusted for the spin off) on the termination date, payment will be made in cash. Mr. Flores and his dependents will be entitled to continued health insurance benefits for three years made “whole” on a net after-tax basis.

Under Mr. Flores’ employment agreement, if benefits to which Mr. Flores becomes entitled in connection with a change in control are considered “excess parachute payments” under Section 280G of the Code, then we will pay Mr. Flores an amount equal to the excise tax imposed by Section 4999 of the Code or any interest or penalties with respect to such excise tax (excluding any income tax or employment tax imposed upon the additional payment).

John T. Raymond. On September 19, 2002, we entered into a new employment agreement with Mr. Raymond that became effective the date after the spin-off of PXP, December 19, 2002, and replaced his prior employment agreement dated June 7, 2001, which we refer to as Mr. Raymond’s Original Agreement. Under the new agreement Mr. Raymond will serve for an initial term of five years, although it may be terminated earlier under certain circumstances. At the end of that term and, if that term is extended, each subsequent term, the agreement is subject to a one-year extension if we and Mr. Raymond agree to new compensation terms ninety days before the end of the applicable term. The new agreement also acknowledged that Mr. Raymond was an officer of PXP and therefore did not devote all of his time and attention to us. As President and Chief Operating Officer of PXP, Mr. Raymond devoted time and attention to, and was compensated by, PXP. Mr. Raymond resigned from PXP on March 3, 2004 and became a full time employee of the Company.

The new agreement provides for an annual salary of $150,000 and a target annual bonus of $150,000, subject to the attainment of performance goals. The agreement also provides that the stock options granted under Mr. Raymond’s Original Agreement will remain in full force and effect. Pursuant to his Original Agreement, Mr. Raymond received (1) a stock option to purchase 200,000 shares of our common stock at an exercise price of $15.29 per share (as adjusted for the spin off), which option vests in three equal, annual installments beginning in May 2002, and (2) a performance option under our 2001 plan to purchase 100,000 shares of our common stock at an exercise price of $15.29 per share (as adjusted for the spin off of PXP). The vesting terms of this performance option are substantially similar to the terms of Mr. Flores’ performance option.

In connection with his new employment agreement, in addition to his annual salary and stock-based awards, Mr. Raymond received a grant of 75,000 restricted shares of our common stock as well as options to purchase 250,000 shares of our common stock under the 2001 plan. The restricted shares vest in three equal, annual installments beginning on December 19, 2003. The options have a grant date of December 19, 2002 and a per share exercise price of $12.51, the closing sales price of our common stock on December 19, 2002. The options have a ten-year term and vest in five equal, annual installments beginning on December 19, 2003. Mr. Raymond is entitled to all of the employee benefits, fringe benefits and perquisites provided by us to other senior executives.

On March 12, 2003, Mr. Raymond was granted 40,000 restricted stock units that vest on the third anniversary of the grant date, provided that if the closing price of shares of our common stocks equals or exceeds 150% of the of the shares on the grant date ($12.50), then the award will vest 18 months after the grant date.

Mr. Raymond’s employment agreement provides that if his employment is terminated by us without Cause (as defined in his new agreement), by Mr. Raymond’s death or disability, or by Mr. Raymond for Good Reason (as defined in his new agreement), we will also pay Mr. Raymond $2.5

million. Upon such termination, all then-outstanding stock-based awards Mr. Raymond holds will become immediately exercisable and payable in full, with any performance goals associated with the employment agreement being deemed to have been achieved at the maximum levels. Mr. Raymond and his dependents will be entitled to continued health insurance benefits for three years made “whole” on a net after-tax basis.

Under Mr. Raymond’s employment agreement, if benefits to which Mr. Raymond becomes entitled in connection with a change in control are considered “excess parachute payments” under Section 280G of the Code, then we will pay Mr. Raymond an amount equal to the excise tax imposed by Section 4999 of the Code or any interest or penalties with respect to such excise tax (excluding any income tax or employment tax imposed upon the additional payment).

Stephen A. Thorington. We entered into an employment agreement with Mr. Thorington on September 8, 2003, that is effective December 18, 2002. Pursuant to this agreement, Mr. Thorington will serve for an initial term of five years beginning on December 18, 2002. At the end of the initial five-year term and, if such term is extended, each subsequent term, the agreement is subject to a one-year extension if Plains and Mr. Thorington agree to new compensation terms before the end of the applicable term. Mr. Thorington’s employment agreement provides for a base salary of $100,000 per year and a target annual bonus of $100,000, subject to the attainment of performance goals.

In September 2002, Mr. Thorington was granted an award of 45,000 shares of restricted stock units which vest over three equal annual installments beginning September 9, 2003. On March 12, 2003, Mr. Thorington was granted 20,000 restricted stock units that vest on the third anniversary of the grant date, provided that if the closing price of shares of our common stocks equals or exceeds 150% of the of the shares on the grant date ($12.50), then the award will vest 18 months after the grant date.

If Mr. Thorington’s employment is terminated by Plains without cause, by Mr. Thorington’s death, or if a change of control (as defined in the 2001 plan) occurs, Plains will pay him a lump sum amount equal to two times the sum of his base salary and last earned annual bonus. Also, Mr. Thorington will be entitled to health insurance benefits for up to two years after termination, subject to mitigation if he becomes entitled to health benefits under another plan, and his restricted stock and restricted stock units will automatically vest.

Under Mr. Thorington’s employment agreement, if benefits to which Mr. Thorington becomes entitled in connection with a change in control are considered “excess parachute payments” under Section 280G of the Code, then we will pay Mr. Thorington an amount equal to the excise tax imposed by Section 4999 of the Code or any interest or penalties with respect to such excise tax (excluding any income tax or employment tax imposed upon the additional payment).

Other. In the event of certain corporate transactions, changes in control of us, or changes in the composition of our board of directors under certain circumstances, all options granted to the named executive officers will be exercisable on an accelerated schedule pursuant to the plans under which the options were granted. To the extent not already exercisable, these options generally become exercisable upon a change of control of us resulting from:

•

a change in the composition of our board of directors pursuant to which incumbent directors or their designated successors cease to constitute at least two-thirds of our board;

•

subject to certain exceptions, the acquisition of securities by a person after which that person beneficially owns 50% or more of the voting power of our securities; or

•

subject to certain exceptions, approval by our stockholders of a merger, consolidation or reorganization involving us, a complete liquidation or dissolution of us, or an agreement for the sale of all or substantially all of our assets.

In addition, in the event of such a change in control, certain holders of options may elect to surrender their options for a cash payment equal to the difference between the exercise price and the market price of the common stock on the date of the event.

Organization and Compensation Committee Report on Executive Compensation

The Organization and Compensation Committee is currently composed of three directors, each of whom is “independent” under the rules of the NYSE and is a “non-employee director” under Rule 16b-3 under the Securities Exchange Act of 1934, and two of whom are “outside directors” under Section 162(m) of the Internal Revenue Code of 1986. The Committee has the responsibility of determining the compensation level of the Chief Executive Officer and compensation and awards under the Company’s stock incentive plans. The Committee also makes determinations and recommendations to the Board of Directors concerning the compensation of the Company’s other executive officers. To make such determinations and recommendations, at the end of each year the Organization and Compensation Committee evaluates (i) the Company’s performance relative to its annual objectives, (ii) the Company’s performance relative to changes in the industry (i.e., performance relative to the opportunities available), and (iii) each executive officer’s contribution to the Company’s achievements during the year. The basic objectives of the executive compensation program are to:

•

enable the Company to attract, retain, motivate and reward high caliber executive officers who are among the most skilled, talented and persistent individuals available in a very competitive marketplace;

•

inspire executive officers to work as a team to innovatively and aggressively pursue Company goals;

•

foster a general corporate atmosphere that promotes an entrepreneurial style of leadership to enable the Company to act quickly and flexibly to implement its plans and pursue opportunities as they arise;

•

emphasize “pay for performance” by having a significant portion of the executive officers’ total compensation “at risk” in the form of incentive compensation; and

•

align the long term interests of the executive officers with those of the Company’s stockholders through the use of stock options and restricted stock as a portion of compensation and thereby encourage the achievement of performance objectives that enhance stockholder value on a continuing basis.

The Committee monitors general industry conditions, changes in regulations and tax laws, and other developments that may, from time to time, require modifications of the executive compensation program to ensure the program is properly structured to achieve its objectives. The Company’s executive compensation program currently includes three major components: base salary, annual incentive compensation and longer-term incentives through stock options and restricted stock awards.

Base Salaries

Base salaries for each of the Company’s executive officers are determined on an individual basis, taking into consideration the performance of the individual and his or her contributions to the Company’s performance, the length of service of the individual with the Company, compensation by industry competitors for comparable positions, internal equities among positions, and general economic conditions. The Committee believes that maintaining a competitive base salary structure is vital to attract and retain talented executives and that optimal performance is encouraged through the use of incentive programs, such as annual incentive compensation and stock option plans, furthering the goal of having “at risk” compensation as an important component of the executive compensation program.

Annual Incentive Compensation

In addition to their base salaries, the Company’s executive officers may earn an annual incentive payment, depending on Company performance relative to objectives set forth in an annual business plan. Such annual objectives are a combination of operating, financial and strategic goals that are considered to be critical to the Company’s success. These objectives are not specifically weighted in determining whether to award annual incentive payments to executive officers because the relative importance of such objectives may change from year to year and the relative responsibilities of each executive officer in the achievement of each of the objectives may differ. After a year-end review of the Company’s performance relative to the annual business plan, the Committee determines the amount of the annual incentive payment, if any, that will be awarded to an executive officer based on the Committee’s subjective evaluation of factors that include the extent to which the objectives of the annual business plan were achieved, his or her contribution to the achievement of those objectives, and general economic and industry conditions.

Stock Options and Restricted Stock Awards

The Company has used stock options and restricted stock awards (including restricted stock units) as its long-term incentive program for executive officers and may in the future continue to use options and restricted stock awards in its long-term incentive program. Stock options and restricted stock awards are used to relate the benefits received by the executive officers to the amount of appreciation realized by the stockholders over comparable periods. The Committee anticipates that stock options and/or restricted stock awards will generally be granted annually to executive officers. The size of the option grant and restricted stock award will generally be determined at the discretion of the Committee. Stock options will be granted at exercise prices not less than the market value of the stock on the date of the grant and are not transferable (other than to the holder’s heirs or entities for the benefit of his heirs). Therefore, such options will have no realizable value unless the Company’s stock appreciates in value. Stock options and restricted stock awards typically include provisions for the vesting of those awards over time. Stock options and restricted stock awards provide the executive officers the opportunity to acquire and build a meaningful ownership interest in the Company and, therefore, closely align the executive officers’ interests with those of the stockholders.

Compensation of the Chief Executive Officer

In connection with the PXP spin off, the Company entered into a new employment agreement with Mr. Raymond. Because Mr. Raymond did not devote all of his time and efforts to the Company (a portion of his time and efforts were devoted to PXP in his position as President and Chief Operating Officer), effective December 2002, and for the fiscal year 2003, the Company paid Mr. Raymond an annual salary of $150,000. He was awarded a bonus of $150,000 for the fiscal year 2003 based upon the attainment of performance goals; half of which was paid on March 5, 2004 and half of which was deferred until after the resolution of any open issues relating to the sale of the Company. The Committee considered the attainment of the Company’s financial goals in assessing Mr. Raymond’s performance. In addition, on March 12, 2003, Mr. Raymond was granted an award of 40,000 restricted stock units. The restricted stock units vest on the third anniversary of the grant date, or March 12, 2006, provided that Mr. Raymond is still employed by the Company. The restricted stock units will vest earlier if, after 18 month after the grant date, for a period of 30 consecutive trading days, the closing price of the Company’s common stock equals or exceeds 150% of the closing price on the grant date. When the restricted stock units vest, the Company will issue to Mr. Raymond shares of the Company’s common stock. The Committee approved Mr. Raymond’s compensation package to directly align Mr. Raymond’s interests with those of the Company’s stockholders. Due to the pending merger of the Company, the Committee has not determined to make any 2004 stock option or restricted stock awards to any of the executive officers.

Deductibility of Compensation Expenses

Section 162(m) of the Internal Revenue Code generally precludes the Company from taking federal income tax deductions for compensation paid to certain executive officers in excess of $1 million per year, unless such excess constitutes performance-based compensation under such section. The Company’s policy is, primarily, to design and administer compensation plans that support the achievement of long-term strategic objectives and enhance stockholder value. Where it is consistent with this compensation philosophy, the Committee will also attempt to structure compensation programs that are tax-deductible by the Company.

March 2, 2004

Organization and Compensation Committee

William M. Hitchcock, Chairman

William C. O’Malley

J. Taft Symonds

Performance Graph

The following graph compares the cumulative total stockholder return on our common stock with the cumulative total return of the Media General Industry Group Index No. 121, “Independent — Oil & Gas”, and the NYSE Market Index for five years ended December 31, 2003. Our common stock became listed on the New York Stock Exchange in December 2001. The graph assumes that the value of an investment in our common stock and each index was $100 at December 31, 1998 and that any dividends were reinvested. Numerical values used for the year-end and other plot points in the graph are set forth in the table under the graph.

At the close of business on December 18, 2002, we spun off PXP. As a result of the spin off, the price of our common stock on December 19, 2002 closed at $12.51 as compared to the closing price of our common stock on December 18, 2002 of $23.05, both as reported on the NYSE. We have included on the graph below numerical values for December 18 and 19, 2002 to help show the impact of the spin off on the investment values noted.

LOGO


	12/31/98	12/31/99	12/31/00	12/31/01	12/18/02	12/19/02	12/31/02	12/31/03
Plains Resources Inc.	100.00	88.89	150.22	175.00	163.91	88.96	84.27	114.13
MG Group Index	100.00	140.10	203.31	166.14	173.97	173.97	173.97	271.35
NYSE Market Index	100.00	109.50	112.11	102.12	83.42	83.42	83.42	108.07

Item 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table sets forth, as of April 19, 2004, the beneficial ownership of our outstanding common stock by:

•

each of our directors;

•

each named executive officer; and

•

all of our executive officers and directors as a group.

Unless otherwise indicated, the persons listed in the table below have sole voting and investment powers with respect to the shares of our common stock indicated, and each person’s address is 700 Milam, Suite 3100, Houston, Texas 77002.


Name of Beneficial Owner	Amount and Nature of Beneficial Ownership(1)		Percent of Class(2)
James C. Flores	1,215,355	(4)	4.85	%
William M. Hitchcock	482,023	(5)	1.92	%
William C. O’Malley	10,946	(5)	(3	)
D. Martin Phillips(6)	25,833	(5)	(3	)
John T. Raymond	421,223	(7)	1.68	%
Robert V. Sinnott(8)	51,185	(5)	(3	)
J. Taft Symonds	79,662	(5)(9)	(3	)
Stephen A. Thorington	41,033	(10)	(3	)
Directors and Executive Officers as a group (9 persons)	2,337,060		9.33	%

(1)	Includes both outstanding shares of our common stock and shares of our common stock such person has the right to acquire within 60 days after April 19, 2004 by exercise of outstanding stock options or by vesting of restricted stock units.

(2)	Based on 24,409,631 shares of our common stock outstanding as of April 19, 2004.

(3)	Less than 1%.

(4)

1,000,000 of these shares are held directly by Sable Management, L.P., the general partner of which is Sable Management, LLC, of which Mr. Flores is the sole member. Includes 40,000 shares of unvested restricted stock over which Mr. Flores exercises voting power and 221 shares held by the Company’s 401(k) plan. Mr. Flores also owns 20,000 unvested restricted stock units.

(5)	Also owns 5,000 unvested restricted stock units.

(6)

Mr. Phillips is a Managing Director of EnCap, which is the general partner of EnCap Energy Capital Fund III, L.P. and EnCap Energy Capital Fund III-B, L.P., the investment manager of Energy Capital Investment Company PLC, and the manager of BOCP Energy Partners, L.P. Mr. Phillips disclaims beneficial ownership of the 1,174,219 shares beneficially owned by EnCap.

(7)	Includes 50,000 shares of unvested restricted stock over which Mr. Raymond exercises voting power and 221 shares held by the Company’s 401(k) plan. Mr. Raymond also owns 40,000 unvested restricted stock units.

(8)	Mr. Sinnott is Senior Vice President of Kayne Anderson Investment Management, Inc., the general partner of Kayne Anderson Capital Advisors, L.P., or Kayne Anderson. Mr. Sinnott disclaims beneficial ownership of the 1,755,916 shares beneficially owned by Kayne Anderson.

(9)	These shares include 32,662 shares that are held by Symonds Trust Co. Ltd.

(10)	Includes 30,000 shares of unvested restricted stock over which Mr. Thorington exercises voting power. Mr. Thorington also owns 20,000 unvested restricted stock units.

The following table lists the persons who, to our knowledge, may be deemed to be beneficial owners, as of April 19, 2004, of more than 5% of our common stock.


Name of Beneficial Owner	Amount and Nature of Beneficial Ownership		Percent of Class(1)
Barclays Global Investors, N.A. 45 Fremont Street San Francisco, CA 94105	1,294,411	(2)	5.17	%

Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne 1800 Avenue of the Stars, Second Floor Los Angeles, CA 90067	1,755,916	(3)	7.01	%

Merrill Lynch & Co. World Financial Center, North Tower 250 Vesey Street New York, NY 10381	1,338,969	(4)	5.35	%

Pershing Square, L.P. 110 East 42nd Street New York, NY 10017	1,258,500	(5)	5.03	%

(1)	Based on 24,409,631 shares of our common stock outstanding as of April 19, 2004.

(2)	Based on the Schedule 13G filed by Barclays Global Investors, N.A. with the SEC on February 17, 2004, Barclays has sole voting and investment power over 1,216,029 shares.

(3)

Based on Amendment No. 14 to Schedule 13D filed by Kayne Anderson and Richard A. Kayne with the SEC on February 27, 2004, Kayne Anderson and Mr. Kayne have shared voting and investment power over 1,665,300 shares held by investment partnerships and managed accounts and Mr. Kayne has sole voting and investment power over 90,616 shares.

(4)	Based on the Schedule 13G filed by Merrill Lynch & Co. with the SEC on January 27, 2004, Merrill Lynch has shared voting and investment power over 1,338,969 shares. Merrill Lynch advised that all such shares are owned by various clients of Merrill Lynch.

(5)	Based on Amendment No. 4 to Schedule 13D filed by Leucadia National Corporation, Pershing Square, L.P., Pershing Square GP, LLC and William Ackman on April 19, 2004, Pershing Square, L.P. shares voting and dispositive power over the shares with Pershing Square GP, LLC and William Ackman.

The following table sets forth certain information, as of December 31, 2003, with respect to all compensation plans that our security holders previously approved, as well as compensation plans not previously approved by our security holders.

Equity Compensation Plan Information


Plan category	Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights	Weighted Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column(a))
	(a)	(b)		(c)
Equity compensation plans approved by security holders	3,846,760	$	13.49	165,807
Equity compensation plans not approved by security holders	—		—	—
Total	3,846,760	$	13.49	165,807

In addition to the above plans, under Mr. Flores’ original employment agreement with us, we granted Mr. Flores a number of shares of our common stock with a value equal to $1 million, which grant was not approved by our stockholders. This grant is payable in five equal installments as of each anniversary of May 8, 2001, which is the date of his original employment agreement, in the form of a direct grant of shares of our common stock, the number of which will equal the annual dollar payment amount ($200,000) divided by the fair market value of a share on the applicable anniversary date. Two installments of this grant were paid on May 8, 2002 and 2003 in the amounts of 7,407 shares and 16,625 shares, respectively, of our common stock.

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Governance of PAA

In addition, the general partner of PAA is owned as follows:


Plains Resources	44.00	%
Sable Investments, L.P.	20.00	%
Kafu Holdings, L.P.	16.42	%
E-Holdings, L.P.	9.00	%
Others	10.58	%

	100.00	%

Our Relationship with PAA

We have ongoing relationships with PAA, including:

•

Our Relationship with PXP

In connection with the spin-off we entered into certain agreements with PXP, including a master separation agreement; an intellectual property agreement; the Plains Exploration & Production transition services agreement that expires June 16, 2004; the Plains Resources transition services agreement that expires June 8, 2004; and a technical services agreement that expires July 2005. For the year ended December 31, 2003, PXP billed us $0.5 million for services provided to us under these agreements and we billed PXP $0.1 million for services we provided under these agreements.

Other

From time to time we charter private aircraft from Gulf Coast Aviation Inc. (“Gulf Coast”), which is not affiliated with us or our employees. On certain occasions, the aircraft that Gulf Coast charters is owned by our Executive Chairman. In 2003, we paid Gulf Coast $0.1 million for aircraft chartering services provided by Gulf Coast using an aircraft owned by our Executive Chairman. The charters were arranged through arms-length dealings with Gulf Coast and the rates were market based.

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees. The fees billed for professional services rendered by PricewaterhouseCoopers LLP in connection with the audit of Plains’ annual financial statements for the year ended December 31, 2002 included in Plains’ annual report on Form 10-K and the review of Plains’ quarterly financial statements during 2002 totaled $320,000, $245,000 of which was paid by Plains Exploration & Production Company when it was wholly-owned by the Company related to the 2002 annual audit and quarterly reviews of the Plains Exploration & Production Company financial statements ($205,000) and for the audit of a partnership ($40,000). The fees billed for professional services rendered by PricewaterhouseCoopers LLP in connection with the audit of Plains’ annual financial statements for the year ended December 31, 2003 included in Plains’ annual report on Form 10-K and the review of Plains’ quarterly financial statements during 2003 totaled $95,000.

Audit-Related Fees. The fees billed for assurance and related services rendered by PricewaterhouseCoopers LLP totaled $819,000 in 2002, $776,000 of which was paid by Plains Exploration & Production Company when it was wholly-owned by the Company related to securities and debt offerings ($756,000) and to the audit of benefit plans ($20,000). No such services were provided in 2003. The percentage of fees related to assurance and related services approved by the audit committee in 2002 was 100% percent.

Tax Fees. PricewaterhouseCoopers LLP did not render any services related to tax compliance, tax advice or tax planning during 2002 or 2003.

All Other Fees. PricewaterhouseCoopers LLP did not render any other services during 2002 or 2003.

Pre-Approval Procedures. Plains’ audit committee is responsible for the engagement of the independent auditors and for approving, in advance, all auditing services and permitted non-audit services to be provided by the independent auditors. The audit committee maintains a policy for the engagement of independent auditors that is intended to maintain the independence from Plains of the independent auditors. In adopting this policy, Plains’ audit committee considered the various services that independent auditors have historically performed or may be needed to perform in the future for Plains. Under this policy, which is subject to review and re-adoption at least annually by the audit committee:

•

The audit committee approves the performance by the independent auditors of audit-related services, subject to restrictions in certain cases, based on the audit committee’s determination that this would not be likely to impair the independence of the independent auditors from Plains;

•

Plains’ management must obtain the specific prior approval of Plains’ audit committee for each engagement of the independent auditors to perform types of permitted services other than audit-related; and

•

The performance by the independent auditors of certain types of services (bookkeeping or other services related to the accounting records or financial statements of the Company; financial information systems design and implementation; appraisal or valuation services, fairness opinions or contribution-in-kind reports; actuarial services; internal audit outsourcing services; management functions or human resources; broker or dealer, or investment adviser or investment banking services; legal services and expert services unrelated to the audit; and any other service that the applicable federal oversight regulatory authority determines, by regulation, is impermissible) is prohibited due to the likelihood that their independence would be impaired.

Any approval required under this policy must be given by Plains’ audit committee, by the chairman of the audit committee in office at the time, or by any other audit committee member to whom the audit committee has delegated that authority. Plain’s audit committee will not delegate its responsibilities to approve services performed by the independent auditors to any member of management.

The standard applied by Plains’ audit committee in determining whether to grant approval of an engagement of the independent auditors is whether the services to be performed, the compensation to be paid therefor and other related factors are consistent with the independent auditor’s independence under guidelines of the Securities and Exchange Commission and applicable professional standards. Relevant considerations include, but are not limited to, whether the work product is likely to be subject to, or implicated in, audit procedures during the audit of Plains’ financial statements; whether the independent auditors would be functioning in the role of management or in an advocacy role; whether performance of the service by the independent auditors would enhance Plains’ ability to manage or control risk or improve audit quality; whether performance of the service by the independent auditors would increase efficiency because of their familiarity with Plains’ business, personnel, culture, systems, risk profile and other factors; and whether the amount of fees involved, or the proportion of the total fees payable to the independent auditors in the period that is for tax and other non-audit services, would tend to reduce the ability of the independent auditors to exercise independent judgment in performing the audit.

PART IV

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) (1) and (2) Financial Statements and Financial Statement Schedules

See “Index to Consolidated Financial Statements” set forth on Page F-1.

(a) (3) Exhibits



2.1		Stock Purchase Agreement dated as of March 15, 1998, among Plains Resources Inc., Plains All American Inc. and Wingfoot Ventures Seven Inc. (incorporated by reference to Exhibit 2(b) to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997).

2.2		Agreement and Plan of Merger, dated as of February 19, 2004, by and among Vulcan Energy Corporation, Prime Time Acquisition Corporation and Plains Resources Inc. (incorporated by reference to Appendix A to Plains’ Proxy Statement on Schedule 14A filed on March 1, 2004).

3.1		Second Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3(a) to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995).

3.2		Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2001).

3.3		First Amendment to the Plains Resources Inc. Bylaws (incorporated by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the three months ended June 30, 2001).

4.1		Specimen Common Stock Certificate (incorporated by reference to Exhibit 4 to the Company’s Form S-1 Registration Statement (Reg. No. 33-33986)).

10.1		The Company’s 1992 Stock Incentive Plan (incorporated by reference to Exhibit 4.3 to the Company’s Form S-8 Registration Statement (Reg. No. 33-48610)).

10.2		First Amendment to the Company’s 1992 Stock Incentive Plan (incorporated by reference to Exhibit 10(n) to the Company’s Annual Report on Form 10-K for the year ended December 31, 1996).

10.3		Second Amendment to the Company’s 1992 Stock Incentive Plan (incorporated by reference to Exhibit 10(b) to the Company’s Quarterly Report on Form 10-Q for the three months ended June 30, 1997).

10.4		Third Amendment to Plains Resources Inc. 1992 Stock Incentive Plan dated May 21, 1998 (incorporated by reference to Exhibit 10(aa) to the Company’s Quarterly Report on Form 10-Q for the three months ended September 30, 1998).

10.5		The Company’s 1996 Stock Incentive Plan (incorporated by reference to Exhibit 4 to the Company’s Form S-8 Registration Statement (Reg. No. 333-06191)).

10.6		First Amendment to Plains Resources Inc. 1996 Stock Incentive Plan dated May 21, 1998 (incorporated by reference to Exhibit 10(z) to the Company’s Quarterly Report on Form 10-Q for the three months ended September 30, 1998).


10.7		Second Amendment to Plains Resources 1996 Stock Incentive Plan dated May 20, 1999 (incorporated by reference to Exhibit 10(q) to the Company’s Quarterly Report on Form 10-Q for the three months ended June 30, 1999).

10.8		Third Amendment to Plains Resources 1996 Stock Incentive Plan dated June 7, 2000 (incorporated by reference to Exhibit 10.23 to the Company’s Annual Report on Form 10-K for the Year Ended December 31, 2000).

10.9		Forms of Officer Stock Option Agreement (incorporated by reference to Exhibits 4.1 and 4.2 to the Company’s Form S-8 Registration Statement (Registration No. 333-45562)).

10.10		Contribution, Conveyance and Assumption Agreement among Plains All American Pipeline, L.P. and certain other parties dated as of November 23, 1998 (incorporated by reference to Exhibit 10.03 to Annual Report on Form 10-K for the Year Ended December 31, 1998 for Plains All American Pipeline, L.P.).

10.11		First Amendment to Contribution, Conveyance and Assumption Agreement dated as of December 15, 1998 (incorporated by reference to Exhibit 10.13 to Annual Report on Form 10-K for the Year Ended December 31, 1998 for Plains All American Pipeline, L.P.).

10.12		Crude Oil Marketing Agreement among Plains Resources Inc., Plains Illinois Inc., Stocker Resources, L.P., Calumet Florida, Inc. and Plains Marketing, L.P. dated as of November 23, 1998 (incorporated by reference to Exhibit 10.07 to Annual Report on Form 10-K for the Year Ended December 31, 1998 for Plains All American Pipeline, L.P.).

10.13		Performance Stock Option Agreement dated as of May 8, 2001 between Plains Resources Inc. and James C. Flores (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the three months ended June 30, 2001).

10.14		Separation Agreement dated as of June 8, 2001 by and among Plains Resources Inc., Plains Holdings Inc. (formerly known as Plains All American Inc.), Plains All American GP LLC, Plains AAP, LP and Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the three months ended June 30, 2001).

10.15		Pension and Employee Benefits Assumption and Transition Agreement, dated as of June 8, 2001, by and between Plains Resources Inc., Plains Holdings Inc. (formerly known as Plains All American Inc.) and Plains All American GP LLC (incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the three months ended June 30, 2001).

10.16		Contribution, Assignment and Amendment Agreement dated as of June 8, 2001, between Plains Holdings Inc. (formerly known as Plains All American Inc.), Plains AAP, LP and Plains All American GP LLC (incorporated by reference to Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q for the three months ended June 30, 2001).

10.17		Registration Rights Agreement dated as of May 8, 2001, among Plains Resources Inc. and James C. Flores (incorporated by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q for the three months ended June 30, 2001).

10.18		Registration Rights Agreement dated as of June 8, 2001, among Plains Resources Inc., Strome Hedgecap Fund L.P., Strome Series Fund 1, Strome Series Fund 2 and Mark E. Strome. (incorporated by reference to Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q for the three months ended June 30, 2001).

10.19		Registration Rights Agreement dated as of June 8, 2001, among Plains All American Pipeline, L.P., Sable Holdings, L.P., E-Holdings III, L.P., KAFU Holdings, LP, PAA Management, L.P., Mark E. Strome, Strome Hedgecap Fund, L.P., John T. Raymond, and Plains Holdings Inc. (formerly known as Plains All American Inc.) (incorporated by reference to Exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q for the three months ended June 30, 2001).



10.20		Registration Rights Agreement dated as of June 8, 2001, among Plains Resources Inc. and EnCap Energy Capital Fund III, L.P., EnCap Energy Capital Fund III-B, L.P., BOCP Energy Partners, L.P. and Energy Capital Investment Company PLC. (incorporated by reference to Exhibit 10.10 to the Company’s Quarterly Report on Form 10-Q for the three months ended June 30, 2001).

10.21		Registration Rights Agreement dated as of June 8, 2001, among Plains Resources Inc. and Kayne Anderson Capital Advisors, L.P. (incorporated by reference to Exhibit 10.11 to the Company’s Quarterly Report on Form 10-Q for the three months ended June 30, 2001).

10.22		Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC, dated as of June 8, 2001, and amended as of September 16, 2003 (incorporated by reference to Exhibit 3.1 to the Plains All American Pipeline, L.P.’s Quarterly Report on Form 10-Q for the three months ended September 30, 2003).

10.23		Amended and Restated Limited Partnership Agreement of Plains AAP, L.P, dated June 8, 2001 (incorporated by reference to Exhibit 10.13 to the Company’s Quarterly Report on Form 10-Q for the three months ended June 30, 2001).

10.24		Plains Resources Inc. 2001 Stock Incentive Plan (incorporated by reference to Exhibit 10.15 to the Company’s Quarterly Report on Form 10-Q for the three months ended June 30, 2001).

10.25		Combination Incentive Stock Option and Nonqualified Stock Option Agreement, dated as of June 7, 2001, between John T. Raymond and Plains Resources Inc. (incorporated by reference to Exhibit 10.36 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2001).

10.26		Performance Stock Option Agreement, dated as of June 7, 2001, between John T. Raymond and Plains Resources Inc. (incorporated by reference to Exhibit 10.37 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2001).

10.27		Secured Term Loan Agreement dated as of December 6, 2002, by and among the Company, Bank of Montreal as Administrative Agent, Bank One, NA, as Syndication Agent, Wells Fargo Bank Texas, NA, as Collateral Agent and Documentation Agent, and the Lenders named therein (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on January 2, 2003).

10.28		First Amendment to Secured Term Loan Agreement dated as of May 9, 2003, by and among Plains Resources Inc., Bank of Montreal, as Administrative Agent, Bank One, NA, as Syndication Agent, Wells Fargo Bank Texas, NA, as Collateral Agent and Documentation Agent, and the Lenders named therein (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the three months ended June 30, 2003).

10.29		Second Amendment to Secured Term Loan Agreement dated as of June 6, 2003, by and among Plains Resources Inc., Bank of Montreal as Administrative Agent, Bank One, NA, as Syndication Agent, Wells Fargo Bank Texas, NA, as Collateral Agent and Documentation Agent, and the Lenders named therein (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the three months ended June 30, 2003).

10.30		Amended and Restated Employment Agreement, dated as of September 19, 2002, by and between James C. Flores and the Company (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the three months ended September 30, 2002).

10.31		Amended and Restated Employment Agreement, dated as of September 19, 2002, by and between John T. Raymond and the Company (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the three months ended September 30, 2002).



10.32		Employment Agreement dated as of September 8, 2003 by and between Stephen A. Thorington and the Company (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the three months ended September 30, 2003).

10.33		Form of Officer Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.32 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002).

10.34		Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.33 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002).

10.35		Form of Incentive Stock Option Agreement (incorporated by reference to Exhibit 10.34 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002)

10.36		Form of Non-Qualified Stock Option Agreement (incorporated by reference to Exhibit 10.35 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002).

10.37		Master Separation Agreement dated July 3, 2002 between PXP and the Company (incorporated by reference to Exhibit 10.1 to PXP’s Amendment No. 1 to Form S-1 filed on August 28, 2002).

10.38		Plains Exploration & Production Company Transition Services Agreement dated July 3, 2002 between PXP and the Company (incorporated by reference to Exhibit 10.2 to PXP’s Amendment No. 1 to Form S-1 filed on August 28, 2002).

10.39		Extension of Term of Plains Exploration & Production Company Transition Services Agreement, dated as of December 18, 2002, between PXP and the Company (incorporated by reference to Exhibit 10.3 to PXP’s Registration Statement on Form S-4 filed on February 12, 2003).

10.40		Plains Resources Inc. Transition Services Agreement dated July 3, 2002 between the Company and PXP (incorporated by reference to Exhibit 10.3 to PXP’s Amendment No. 1 to Form S-1 filed on August 28, 2002).

10.41		Second Amended and Restated Tax Allocation Agreement dated November 20, 2002 between PXP and the Company (incorporated by reference to Exhibit 10.4 to PXP’s Amendment No. 1 to Form 10 filed on November 21, 2002).

10.42		Technical Services Agreement dated July 3, 2002 between PXP and the Company (incorporated by reference to Exhibit 10.5 to PXP’s Amendment No. 1 to Form S-1 filed on August 28, 2002).

10.43		Intellectual Property Agreement dated July 3, 2002 between PXP and the Company (incorporated by reference to Exhibit 10.6 to PXP’s Amendment No. 1 to Form S-1 filed on August 28, 2002).

10.44		Employee Matters Agreement dated July 3, 2002 between PXP and the Company (incorporated by reference to Exhibit 10.7 to PXP’s Amendment No. 1 to Form S-1 filed on August 28, 2002).

10.45		Amendment No. 1 to Employee Matters Agreement, dated as of September 18, 2002, between the Company and PXP (incorporated by reference to Exhibit 10.22 to PXP’s Amendment No. 2 to Form S-1 filed on October 4, 2002).

10.46		Amendment No. 1 to Master Separation Agreement, dated as of November 20, 2002, between the Company and PXP (incorporated by reference to Exhibit 10.24 to PXP’s Amendment No. 1 to Form 10 filed on November 21, 2002).



10.47		Amendment No. 2 to Employee Matters Agreement, dated as of November 20, 2002, between the Company and PXP (incorporated by reference to Exhibit 10.25 to PXP’s Amendment No. 1 to Form 10 filed on November 21, 2002).

10.48		Amendment No. 3 to Employee Matters Agreement, dated as of December 2, 2002, between PXP and the Company (incorporated by reference to Exhibit 10.23 to PXP’s Registration Statement on Form S-4 filed on February 12, 2003).

10.49		First Amendment to Plains Resources Inc. 2001 Stock Incentive Plan (incorporated by reference to Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q for the three months ended September 30, 2002).

10.50		Second Amendment to Plains Resources Inc. 2001 Stock Incentive Plan (incorporated by reference to Exhibit 10.49 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002).

10.51	*	Designation and Voting Agreement dated as of December 18, 2003, between Sable Investments, L.P. and Plains Holdings Inc.

21.1*		Subsidiaries of the Company

23.1*		Consent of PricewaterhouseCoopers LLP.

23.2*		Consent of PricewaterhouseCoopers LLP.

23.3*		Consent of Netherland, Sewell and Associates, Inc.

31.1*		Certification of Chief Executive Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*		Chief Executive Officer Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2*		Chief Financial Officer Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.1		The financial statements of Plains All American Pipeline, L.P. included on pages F-1 through F-36 of PAA’s Annual Report on Form 10-K for the year ended December 31, 2003.

*	Filed herewith

(b) Reports on Form 8-K

A Current Report on Form 8-K was filed on January 23, 2004 with respect to the Company’s press release of January 22, 2004 announcing that, after careful consideration, including a thorough review with independent financial and legal advisors, the Special Committee of the Board of Directors of Plains determined that the previously announced proposal by Vulcan Capital, along with Plains’ Chairman James C. Flores and its CEO and President, John T. Raymond to acquire all of Plains’ outstanding stock for $14.25 per share in cash was inadequate and not in the best interests of Plains stockholders.

A Current Report on Form 8-K was filed on February 20, 2004 with respect to the Company’s press release of February 19, 2004 announcing that following discussions and negotiations with the Vulcan Group and other interested parties, on February 19, 2004 the Special Committee of the Board of Directors of Plains announced that it has voted unanimously to recommend to the Board of Directors and to Plains Resources’ stockholders a $16.75 per share proposal from the Vulcan Group.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	PLAINS RESOURCES INC.

Date: April 27, 2004	By:	/s/ STEPHEN A. THORINGTON
		Stephen A. Thorington, Executive Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

PLAINS RESOURCES INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


		Page
Financial Statements

Report of Independent Auditors		F-2

Consolidated Balance Sheets as of December 31, 2003 and 2002		F-3

Consolidated Statements of Income for the years ended December 31, 2003, 2002 and 2001		F-4

Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001		F-5

Consolidated Statements of Comprehensive Income for the years ended December 31, 2003, 2002, and 2001		F-6

Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2003, 2002, and 2001		F-7

Notes to Consolidated Financial Statements		F-8

Financial statements of our equity ownership interest, Plains All American Pipeline, L.P., are included in this report as Exhibit 99.1.

All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or notes thereto.

F-1

REPORT OF INDEPENDENT AUDITORS

To the Board of Directors

and Stockholders of Plains Resources Inc.:

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Plains Resources Inc. and its subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 4 to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations effective January 1, 2003. As discussed in Note 5 to the consolidated financial statements, the Company changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001.

PricewaterhouseCoopers LLP

Houston, Texas

March 3, 2004

F-2

PLAINS RESOURCES INC.

CONSOLIDATED BALANCE SHEETS

(in thousands)


	December 31,
	2003			2002
ASSETS
Current Assets
Cash and cash equivalents	$	4,549		$	8,807
Accounts receivable—Plains All American Pipeline, L.P.		3,533			—
Other accounts receivable		2,072			1,589
Inventory		1,334			2,305
Other current assets		873			1,515

		12,361			14,216

Property and Equipment, at cost
Oil and gas properties—full cost method		353,653			349,517
Other property and equipment		30			27

		353,683			349,544
Less allowance for depreciation, depletion and amortization		(300,370	)		(299,214	)

		53,313			50,330

Ownership Interest in Plains All American Pipeline, L.P.		100,536			70,042

Other Assets
Deferred income taxes		—			16,957
Other		9,838			9,867

		9,838			26,824

	$	176,048		$	161,412

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	2,114		$	1,361
Derivative contracts		2,834			431
Taxes payable		1,975			1,878
Royalties payable		814			348
Interest payable		197			78
Current maturities of long-term debt		20,000			18,000
Other current liabilities		3,882			4,091

		31,816			26,187

Long-Term Debt		30,000			27,000

Asset Retirement Obligation		1,594			—

Other Long-Term Liabilities		4,626			2,716

Deferred Income Taxes		7,108			—

Commitments and Contingencies (Note 13)

Stockholders’ Equity
Series D Cumulative Convertible Preferred Stock, $1.00 par value, 46,600 shares authorized, issued and outstanding, at stated value		—			23,300
Common Stock, $0.10 par value, 50,000,000 shares authorized; 28,410,000 and 28,048,000 shares issued and outstanding at December 31, 2003 and 2002, respectively		2,842			2,806
Additional paid-in capital		278,597			273,162
Retained earnings (deficit)		(87,851	)		(103,882	)
Accumulated other comprehensive income		3,361			(2,862	)
Treasury stock, at cost; 4,678,000 and 3,854,000 shares at December 31, 2003 and 2002, respectively		(96,045	)		(87,015	)

		100,904			105,509

	$	176,048		$	161,412

See notes to consolidated financial statements.

F-3

PLAINS RESOURCES INC.

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per share data)


	Year Ended December 31,
	2003			2002			2001
Revenues
Oil sales to Plains All American Pipeline, L.P.	$	22,164		$	19,275		$	17,211
Hedging		(307	)		(613	)		(1,181	)

		21,857			18,662			16,030

Costs and Expenses
Production expenses		7,401			5,838			7,028
Production and other taxes		1,131			583			369
Oil transportation expenses		3,906			3,775			4,449
Other operating expenses		137			115			—
General and administrative		6,973			5,747			11,083
Depreciation, depletion, amortization and accretion		4,995			4,139			4,816

		24,543			20,197			27,745

Other Income (Expense)
Equity in earnings of Plains All American Pipeline, L.P.		15,073			18,807			18,540
Gains on Plains All American Pipeline, L.P. unit transactions and public offerings		33,237			14,512			170,157
Loss on debt extinguishment		—			(10,319	)		—
Gain (loss) on derivatives		(6,728	)		—			—
Interest expense		(2,222	)		(5,866	)		(8,974	)
Interest and other income (expense)		97			239			(312	)

		39,457			17,373			179,411

Income From Continuing Operations Before Income Taxes		36,771			15,838			167,696
Income tax expense
Current		(1,270	)		963			(3,933	)
Deferred		(15,194	)		(7,069	)		(63,139	)

Income From Continuing Operations		20,307			9,732			100,624
Income from discontinued operations, net of tax		—			27,800			54,693

Income Before Cumulative Effect of Accounting Changes		20,307			37,532			155,317
Cumulative effect of accounting changes, net of income taxes		933			—			(1,986	)

Net Income		21,240			37,532			153,331
Cumulative preferred dividends		(603	)		(1,400	)		(27,245	)

Net Income Available to Common Stockholders	$	20,637		$	36,132		$	126,086

Basic Earnings Per Share
Continuing operations	$	0.84		$	0.35		$	3.48
Discontinued operations		—			1.16			2.59
Change in accounting policy		0.04			—			(0.09	)

	$	0.88		$	1.51		$	5.98

Diluted Earnings Per Share
Continuing operations	$	0.82		$	0.34		$	2.81
Discontinued operations		—			1.14			2.01
Change in accounting policy		0.04			—			(0.07	)

	$	0.86		$	1.48		$	4.75

See notes to consolidated financial statements.

F-4

PLAINS RESOURCES INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	Year Ended December 31,
	2003			2002			2001
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	21,240		$	37,532		$	153,331
Items not affecting cash flows from continuing operating activities
Earnings from discontinued operations, net of taxes		—			(27,800	)		(54,693	)
Depreciation, depletion, amortization and accretion		4,995			4,139			4,816
Equity in earnings of Plains All American Pipeline, L.P.		(15,073	)		(18,807	)		(18,540	)
Distributions received from Plains All American Pipeline, L.P.		30,930			29,063			31,553
Noncash gains on Plains All American Pipeline, L.P. unit transactions and public offerings		(33,237	)		(14,512	)		(170,157	)
Deferred income taxes		15,194			7,069			63,139
Cumulative effect of adoption of SFAS 143		(933	)		—			—
Cumulative effect of adoption of SFAS 133		—			—			1,986
Change in derivative fair value		4,344			—			172
Noncash compensation expense		2,722			1,778			3,518
Other noncash items		84			1,585			1,626
Change in assets and liabilities from operating activities
Accounts receivable and other		(3,687	)		2,338			11,826
Inventory		563			240			1,724
Accounts payable and other		(116	)		(14,987	)		(26,981	)

Net cash provided by (used in) continuing activities		27,026			7,638			3,320
Net cash provided by (used in) discontinued activities		—			82,097			116,808

Net cash provided by (used in) operating activities		27,026			89,735			120,128

CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition, exploration and developments costs		(3,102	)		(5,860	)		(6,032	)
Additions to other property and assets		(3	)		(64	)		(434	)
Proceeds from the sale of Plains All American Pipeline, L.P. units		—			—			106,941
General partner contributions to Plains All American Pipeline, L.P.		(2,311	)		(1,334	)		(3,978	)

Net cash provided by (used in) continuing activities		(5,416	)		(7,258	)		96,497
Net cash provided by (used in) discontinued activities		—			(64,158	)		(125,880	)

Net cash provided by (used in) investing activities		(5,416	)		(71,416	)		(29,383	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		24,000			45,000			204,900
Proceeds from sale of common stock		2,812			5,210			9,169
Purchase of senior subordinated notes		—			—			(7,550	)
Principal payments of long-term debt		(19,000	)		(278,950	)		(220,700	)
Purchase of common stock		(9,030	)		—			(67,729	)
Costs incurred in connection with financing arrangements		(710	)		(632	)		—
Increase in restricted cash		—			(5,000	)		—
Retirement of Series D preferred stock		(23,300	)		—			—
Preferred stock dividends		(603	)		(1,400	)		(8,698	)
Other		(37	)		361			(102	)

Net cash provided by (used in) continuing activities		(25,868	)		(235,411	)		(90,710	)
Net cash provided by (used in) discontinued activities		—			225,748			(511	)

Net cash provided by (used in) financing activities		(25,868	)		(9,663	)		(91,221	)

Net increase (decrease) in cash and cash equivalents		(4,258	)		8,656			(476	)
Decrease in cash due to deconsolidation of Plains All American Pipeline, L.P.		—			—			(3,425	)
Decrease in cash due to spin-off of Plains Exploration & Production Company		—			(1,028	)		—
Cash and cash equivalents, beginning of year		8,807			1,179			5,080

Cash and cash equivalents, end of year	$	4,549		$	8,807		$	1,179

See notes to consolidated financial statements

F-5

PLAINS RESOURCES INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)


	Year Ended December 31,
	2003			2002			2001
Net Income	$	21,240		$	37,532		$	153,331

Other Comprehensive Income (Loss):
From continuing operations:
Cumulative effect of accounting change, net of tax of ($71)		—			—			(111	)
Commodity hedging contracts:
Change in fair value, net of taxes of $(1,020), $(223) and $75		(952	)		(1,003	)		766
Reclassification adjustment for settled contracts net of taxes of $1,039 and $(7)		1,032			(10	)		—
Interest rate swap, net of taxes of $(13) and $84		—			(20	)		131
Minimum pension liability adjustment, net of taxes of $(12), $66 and $(272)		(14	)		106			(421	)
Equity in other comprehensive income changes of Plains All American Pipeline, L.P., net of taxes of $4,570, $56 and $(1,500)		6,157			19			(2,319	)

		6,223			(908	)		(1,954	)

From discontinued operations:
Commodity hedging contracts:
Cumulative effect of accounting change, net of tax of $4,454		—			—			6,967
Change in fair value, net of taxes of $(24,970) and $7,634		—			(37,298	)		10,978
Reclassification adjustment for settled contracts net of taxes of $5,897 and ($1,388)		—			8,850			(2,061	)
Interest rate swap, net of tax of ($119)		—			(178	)		—
Minimum pension liability adjustment, net of tax of ($77)		—			(116	)		—

		—			(28,742	)		15,884

		6,223			(29,650	)		13,930

Comprehensive Income	$	27,463		$	7,882		$	167,261

See notes to consolidated financial statements.

F-6

PLAINS RESOURCES INC.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(in thousands)


	2003					2002					2001
	Shares		Amount			Shares		Amount			Shares		Amount
Series D Cumulative Convertible Preferred Stock
Balance, beginning of year	47		$	23,300		47		$	23,300		47		$	23,300
Retirements	(47	)		(23,300	)						—			—

Balance, end of year	—			—		47			23,300		47			23,300

Series H Cumulative Convertible Preferred Stock
Balance, beginning of year	—			—		—			—		170			84,785
Conversion of preferred stock into common	—			—		—			—		(170	)		(84,785	)

Balance, end of year	—			—		—			—		—			—

Common Stock
Balance, beginning of year	28,048			2,806		27,677			2,768		18,747			1,875
Common stock issued upon exercise of options, warrants and other	362			36		371			38		1,041			103
Conversion of preferred stock into common	—			—		—			—		7,889			790

Balance, end of year	28,410			2,842		28,048			2,806		27,677			2,768

Additional Paid-in Capital
Balance, beginning of year				273,162					268,520					139,203
Common stock issued upon exercise of options, warrants and other				3,539					4,398					18,429
Restricted stock awards
Issuance of restricted stock				197					2,955					—
Deferred compensation				1,699					(2,711	)				—
Conversion of preferred stock into common				—					—					110,888

Balance, end of year				278,597					273,162					268,520

Retained Earnings (Deficit)
Balance, beginning of year				(103,882	)				37,676					(88,410	)
Net income				21,240					37,532					153,331
Preferred stock dividends				(603	)				(1,400	)				(27,245	)
Treasury stock issued for less than cost				—					(927	)				—
Spinoff of Plains Exploration & Production Company				(4,606	)				(176,763	)				—

Balance, end of year				(87,851	)				(103,882	)				37,676

Accumulated Other Comprehensive Income
Balance, beginning of year				(2,862	)				13,930					—
Other comprehensive income				6,223					(29,650	)				13,930
Spinoff of Plains Exploration & Production Company				—					12,858					—

Balance, end of year				3,361					(2,862	)				13,930

Treasury Stock
Balance, beginning of year	(3,854	)		(87,015	)	(4,121	)		(91,342	)	(1,291	)		(23,613	)
Purchase of common stock	(824	)		(9,030	)	—			—		(2,830	)		(67,729	)
Common stock issued upon exercise of options	—			—		267			4,327		—			—

Balance, end of year	(4,678	)		(96,045	)	(3,854	)		(87,015	)	(4,121	)		(91,342	)

Total			$	100,904				$	105,509				$	254,852

See notes to consolidated financial statements.

F-7

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization and Significant Accounting Policies

Organization

The consolidated financial statements of Plains Resources Inc. (“Plains”, “our”, or “we”) include the accounts of all wholly owned subsidiaries. Our ownership interest in Plains All American Pipeline, L.P. (“PAA”) is accounted for using the equity method of accounting. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to the prior year statements to conform to the current year presentation.

On July 3, 2002, we contributed all of the capital stock of our subsidiaries that owned oil and gas properties offshore California and in Illinois to our wholly-owned subsidiary Plains Exploration & Production Company (“PXP”). PXP also directly owned our onshore California oil and gas properties. We also contributed to PXP the intercompany payables that PXP and its subsidiaries owed to us.

On July 3, 2002, PXP (i) issued $200.0 million of 8.75% senior subordinated notes due 2012; and (ii) entered into a $300.0 million revolving credit facility. PXP distributed the net proceeds of $195.3 million from the 8.75% notes and $116.7 million in initial borrowings under the credit facility to us and we used such amounts to redeem our 10.25% senior subordinated notes on August 2, 2002 ($287.0 million) and to repay amounts outstanding under our credit facility ($25.0 million).

On December 18, 2002, we distributed 100 percent of the common shares of PXP to the holders of record of our common stock as of December 11, 2002 (the “spin-off”). Each stockholder 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 capital 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.

As a result of the spin-off, the historical results of the operations of PXP are reflected in our financial statements as “discontinued operations”. In connection with the spin-off, we entered into certain agreements with PXP (see Note 10).

We are an independent energy company that is engaged in the “upstream” oil and gas business. The Upstream business acquires, exploits, develops, explores for and produces oil and gas. Our upstream activities are all located in the United States. We participate indirectly in the Midstream oil and gas business, which consists of the marketing, gathering, transporting, terminalling and storage of oil, through our ownership interest in PAA. All of PAA’s Midstream activities are conducted in the United States and Canada.

F-8

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Significant Accounting Policies

Oil and Gas Properties. We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration, exploitation and development activities are capitalized. Such costs include internal general and administrative costs such as payroll and related benefits and costs directly attributable to employees engaged in acquisition, exploration, exploitation and development activities. General and administrative costs associated with production, operations, marketing and general corporate activities are expensed as incurred. These capitalized costs, net of salvage values, are amortized to expense by the unit-of-production method using engineers’ estimates of proved oil and gas reserves. The costs of unproved properties are excluded from amortization until the properties are evaluated. Interest is capitalized on oil and gas properties not subject to amortization and in the process of development. Proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs unless such sales involve a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized. Unamortized costs of proved properties are subject to a ceiling which limits such costs to the present value of estimated future cash flows from proved oil and gas reserves of such properties (including the effect of any related hedging activities) reduced by future operating expenses, development expenditures and abandonment costs (net of salvage values), and estimated future income taxes thereon.

Asset Retirement Obligations. Effective January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). SFAS 143 requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred. A legal obligation is a liability that a party is required to settle as a result of an existing or enacted law, statute, ordinance or contract. When the liability is initially recorded, the entity capitalizes the retirement cost of the related long-lived asset. Each period the liability is accreted to its then present value, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized at the time of settlement. In prior periods we included estimated future costs of abandonment and dismantlement in our full cost amortization base and these costs were amortized as a component of our depletion expense.

Other Property and Equipment. Other property and equipment at December 31, 2003 and 2002 is recorded at cost and consists of computer hardware and software. Net gains or losses on property and equipment disposed of are included in interest and other income in the period in which the transaction occurs.

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates made by management include (1) oil and gas reserves, (2) depreciation, depletion and amortization, including future abandonment costs, (3) income taxes and related valuation allowance, and (4) accrued liabilities. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Cash and Cash Equivalents. Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. At December 31, 2003 and 2002, the majority of cash and cash equivalents is concentrated in two institutions and at times may exceed federally insured limits. We periodically assess the financial condition of the institutions and believe that our credit risk is minimal.

F-9

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Inventory. Our oil inventories are carried at the lower of cost to produce or market. Materials and supplies inventory is stated at the lower of cost or market with cost determined on an average cost method.

Inventory consists of the following (in thousands):


	December 31,
	2003		2002
Oil	$	760	$	1,482
Materials and supplies		574		823

	$	1,334	$	2,305

Other Assets. Other assets consists of the following (in thousands):


	December 31,
	2003		2002
Restricted cash	$	5,048	$	5,000
Debt issue costs, net		961		612
Receivable from PXP		3,000		3,000
Other		829		1,255

	$	9,838	$	9,867

Costs incurred in connection with the issuance of long-term debt are capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization.

Federal and State Income Taxes. Income taxes are accounted for in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (“SFAS 109”). SFAS 109 requires recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax bases of assets and liabilities using tax rates in effect for the year in which the differences are expected to reverse. A valuation allowance is established to reduce deferred tax assets if it is more than likely than not that the related tax benefits will not be realized.

Under the terms of a tax allocation agreement, PXP’s taxable income or loss prior to the spin-off is included in the consolidated income tax returns filed by us. 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, we could be liable if any federal tax liability is incurred, but not discharged, by any other member of our consolidated group. To the extent our net operating losses were 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 our federal income tax liability resulting from the utilization of such net operating losses, but such reimbursement shall not exceed $3.0 million exclusive of any interest accruing under the agreement. A receivable from PXP for $3.0 million is reflected in our consolidated balance sheet at December 31, 2003 and 2002 for the use of our net operating losses.

F-10

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

To reflect differences between the amounts included in our financial statements at December 31, 2002 and the final 2002 tax returns filed by us and PXP, in the third quarter of 2003 we increased our deferred tax liability by $4.6 million and decreased our stockholders’ equity by such amount that is reflected as Spin-off of PXP in our statement of changes in stockholders’ equity.

Revenue Recognition. Oil and gas revenue from our interests in producing wells is recognized when the production is delivered and the title transfers. Transportation costs incurred in connection with such operations are reflected as an operating cost.

Derivative Financial Instruments (Hedging). We utilize various derivative instruments to reduce our exposure to decreases in the market price of oil. The derivative instruments consist of oil swap contracts entered into with financial institutions.

Stock-based Employee Compensation. In October 1995, the Financial Accounting Standards Board issued SFAS 123, which established financial accounting and reporting standards for stock-based employee compensation. SFAS 123 defines a fair value based method of accounting for an employee stock option or similar equity instrument. SFAS 123 also allows an entity to continue to measure compensation cost for those instruments using the intrinsic value-based method of accounting prescribed by APB 25. We have elected to follow APB 25 and related interpretations in accounting for our employee stock options because, as discussed below, the alternative fair value accounting provided for under SFAS 123 requires the use of option valuation models that were not developed for use in valuing employee stock options. Under APB 25, if the exercise price of our employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense is recognized in the financial statements.

Pro forma information regarding net income (loss) and earnings per share is required by SFAS 123 and has been determined as if we had accounted for our employee stock options under the fair value method as provided therein. The fair value for the options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted average assumptions for grants in 2002 and 2001: risk-free interest rates of 3.0% for 2002 and 2.5% for 2001; a volatility factor of the expected market price of our common stock of 0.33 for 2002 and 0.50 for 2001; no expected dividends; and weighted average expected option lives of 4.4 years in 2002 and 5.3 years in 2001. There were no option grants during 2003. For purposes of pro forma disclosures, the estimated fair value of the options is amortized to expense over the options’ vesting period.

The Black-Scholes option valuation model and other existing models were developed for use in estimating the fair value of traded options that have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of and are highly sensitive to subjective assumptions including the expected stock price volatility. Because our employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management’s opinion, the existing models do not provide a reliable single measure of the fair value of its employee stock options.

F-11

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Set forth below is a summary of our net income and earnings per share as reported and pro forma as if the fair value based method of accounting defined in SFAS 123 had been applied (in thousands, except per share data).


	Year Ended December 31,
	2003			2002			2001
Net income available to common stockholders, as reported	$	20,637		$	36,132		$	126,086
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects		1,503			929			2,586
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(4,708	)		(4,337	)		(3,002	)

Pro forma net income	$	17,432		$	32,724		$	125,670

Earnings per share:
Basic—as reported	$	0.88		$	1.51		$	5.98

Basic—pro forma	$	0.74		$	1.37		$	5.96

Diluted—as reported	$	0.86		$	1.48		$	4.75

Diluted—pro forma	$	0.73		$	1.34		$	4.74

Sale of Units by PAA. When PAA sells additional units to a third party, resulting in a change in our percentage ownership interest, we recognize a gain or loss in our consolidated statement of operations if the selling price per unit is more or less than our average carrying amount per unit.

Recent Accounting Pronouncements. The Financial Accounting Standards Board (FASB) issued Financial Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities” in January 2003. FIN 46 addresses the consolidation of variable interest entities (VIEs) by business enterprises that are the primary beneficiaries. A VIE is an entity that does not have sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or whose equity investors lack the characteristics of a controlling financial interest. The primary beneficiary of a VIE is the enterprise that has the majority of the risks or rewards associated with the VIE. In December 2003, the FASB issued a revision to FIN 46, Interpretation No. 46R (FIN 46R), to clarify some of the provisions of FIN 46, and to exempt certain entities from its requirements. Application of FIN 46R is required in financial statements of public entities that have interests in structures that are commonly referred to as special-purpose entities for periods ending after December 15, 2003. Application for all other types of VIEs is required in financial statements for periods ending after March 15, 2004. We do not believe we participate in any arrangement that would be subject to the provisions of FIN 46R.

Note 2—Discontinued Operations

As discussed in Note 1, on December 18, 2002, we distributed the common shares of PXP to the holders of record of our common stock as of December 11, 2002. As a result of the spin-off, we have accounted for the business of PXP as a discontinued operation.

F-12

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The results of operations of PXP, which have been reclassified as discontinued operations in the Consolidated Statements of Income for the years ended December 31, 2002 and 2002, are summarized as follows (in thousands):


	Year Ended December 31,
	2002			2001
Revenues	$	181,184		$	204,139
Costs and expenses		(115,195	)		(98,110	)

Income from operations		65,989			106,029
Other income (expense)		(20,961	)		(16,948	)

Income before income taxes		45,028			89,081
Income tax expense		(17,228	)		(34,388	)

Income from discontinued operations	$	27,800		$	54,693

Note 3—Ownership Interest in Plains All American Pipeline, L.P.

At December 31, 2003, our aggregate 22% ownership in PAA consisted of: (i) a 44% ownership interest in the 2% general partner interest and incentive distribution rights, (ii) 3.3 million subordinated units and (iii) 9.0 million common units (including 1.3 million Class B common units). In February 2004 all of PAA’s then outstanding subordinated units were converted into common units.

Sale of PAA Interest

In a series of transactions in June 2001, we sold a portion of our interests in PAA to a group of investors and management of PAA for approximately $155.2 million and recognized a gain of $128.3 million. The assets we sold in this restructuring included 52% of the subordinated units of PAA 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 consideration for the sale. In connection with our strategic restructuring, the holders of the remaining shares of our series F preferred stock converted their shares into 2.2 million shares of our common stock and received from us a cash payment of approximately $2.5 million, equal to, with respect to each share of our series F preferred stock converted, the accrued dividends on each share from June 8, 2001 until the first date on which we could cause conversion of the shares, plus a 20% premium on the amount of the accrued dividends. Also, in connection with our strategic restructuring, holders of our series H preferred stock converted an aggregate of 132,022 shares into approximately 4.4 million shares of our common stock. In addition, in September 2001 PAA management exercised an option to acquire an additional 2% ownership interest in the general partner of PAA by paying us $1.5 million in cash and notes. These transactions in the aggregate are hereinafter referred to as the “Transactions”.

As a result of the Transactions, 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 the Series F Preferred stock as consideration for the PAA Units over the carrying value of the Series F Preferred Stock ($21.4 million) for accounting purposes is deemed to be a dividend to preferred stockholders and is deducted in determining the income available to common stockholders for the purpose of determining basic and fully diluted earnings per share in

F-13

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

2001. In connection with the conversion of the Series F Preferred Stock into common stock, we made a $2.5 million inducement payment representing a 20% premium to the amount of dividends that would accrue on the Series F Preferred Stock between the closing of the Transactions and the first date we could potentially cause such conversion. Such amounts are included in preferred dividends.

We entered into value assurance agreements with each of the parties that acquired PAA subordinated units from us in the Transactions. The value assurance agreements require us to pay to them 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. In the fourth quarter of 2003, 25% of PAA’s subordinated units were converted into common units and in February 2004 the remaining subordinated units were converted and the value assurance agreements expired. We were not required to make any payments under the value assurance agreements.

PAA Equity Offerings

When PAA issues common units in a public equity offering, we recognize a gain or a loss if the selling price is more or less than our average carrying amount per unit. Such gains or losses reflect the change in the book value of our equity in PAA compared to our proportionate share of the change in the underlying net assets of PAA due to the sale of the additional units. In addition, we are required to make cash contributions to the general partner to enable the general partner to maintain its 2% interest in the partnership. In the years ended December 31, 2003, 2002 and 2001 as a result of PAA equity offerings we recognized gains and made cash contributions to the general partner as follows (in thousands of dollars):


	Gain on Unit Offering		General Partner Contribution
2003
December	$	8,297	$	820
September		9,119		902
March		6,108		589

	$	23,524	$	2,311

2002
August	$	14,512	$	1,334

2001
October	$	19,196	$	1,215
May		19,623		2,763

	$	38,819	$	3,978

Conversion of PAA Subordinated Units

Prior to the fourth quarter of 2003 PAA had outstanding 10.0 million subordinated units, of which we owned 4.5 million. The subordinated units are not publicly traded and are subordinated in the right to distributions. 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 ends when PAA meets certain financial tests for three consecutive four-quarter periods. PAA met certain of the financial requirements and 25% of the subordinated units converted to common units in the fourth quarter of 2003. The remaining subordinated units converted to common units in February 2004.

F-14

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Upon the conversion of the subordinated units in the fourth quarter of 2003 we recognized a gain of $9.7 million resulting from the increase in the book value of our equity in PAA to reflect the increase in our proportionate share of the underlying net assets of PAA.

PAA Financial Statement Information

The following table presents summarized financial statement information of PAA (in thousands of dollars):


	Year Ended December 31,
	2003		2002
Revenues	$	12,589,849	$	8,384,223
Cost of sales and operations		12,492,293		8,289,663
Gross margin		97,556		94,560
Operating income		98,204		94,560
Net income		59,448		65,292

	December 31,
	2003		2002
Current assets	$	732,974	$	602,935
Property and equipment, net		1,151,039		952,753
Other assets		211,618		110,887
Total assets		2,095,631		1,666,575
Current liabilities		801,919		637,249
Long-term debt		518,991		509,736
Other long-term liabilities		27,994		7,980
Partners’ capital		746,727		511,610
Total liabilities and partners’ capital		2,095,631		1,666,575

Note 4—Asset Retirement Obligations

Effective January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). SFAS 143 requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred. A legal obligation is a liability that a party is required to settle as a result of an existing or enacted law, statute, ordinance or contract. When the liability is initially recorded, the entity should capitalize the retirement cost of the related long-lived asset. Each period the liability is accreted to its then present value, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized at the time of settlement. In prior periods we included estimated future costs of abandonment and dismantlement in our full cost amortization base and these costs were amortized as a component of our depletion expense.

At January 1, 2003 the present value of our future Asset Retirement Obligation for oil and gas properties and equipment was $2.6 million. The cumulative effect of our adoption of SFAS No. 143 and the change in accounting principle resulted in an increase in income in 2003 of $0.9 million (reflecting a $2.8 million decrease in accumulated DD&A, partially offset by $1.3 million in accretion expense, and $0.6 million deferred income tax expense). We recorded a liability of $2.6 million and an asset of $1.2 million in connection with the adoption of SFAS 143. Adopting SFAS No. 143 did not affect our cash flows.

F-15

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table reflects the changes in our asset retirement obligation for the year ended December 31, 2003, and on a pro forma basis for the years ended December 31, 2002 and 2001, assuming adoption of SFAS 143 on January 1, 2001 (in thousands):


	Year Ended December 31,
	2003			2002		2001
				Pro forma		Pro forma
Asset retirement obligation—beginning of period	$	2,556		$	2,344	$	2,149
Accretion expense		231			212		195
Asset retirement cost settlements		(405	)		—		—

Asset retirement obligation—end of period	$	2,382	(1)	$	2,556	$	2,344

(1)	$788 included in other current liabilities

On a pro forma basis the effect of the adoption of SFAS 143 on our income from continuing operations, our net income and our earnings per share for the years ended December 31, 2002 and 2001 is not material.

Note 5—Derivative Instruments and Hedging Activities

We have entered into various derivative instruments to reduce our exposure to fluctuations in the market price of oil. The derivative instruments consist primarily of oil swap contracts entered into with financial institutions. Derivative instruments are accounted for in accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” as amended, or SFAS 133. All derivative instruments are recorded on the balance sheet at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. If the derivative qualifies for hedge accounting, the gain or loss on the derivative is deferred in Accumulated Other Comprehensive Income (“OCI”), a component of our stockholders’ equity, to the extent the hedge is effective. Gains and losses on oil hedging instruments related to OCI and adjustments to carrying amounts on hedged volumes are included in oil revenues in the period that the related volumes are delivered. On January 1, 2001, in accordance with the transition provisions of SFAS 133, we recorded a loss of $0.1 million in OCI, representing the cumulative effect of an accounting change to recognize at fair value all cash flow derivatives. We recorded cash flow hedge derivative assets and liabilities of $10.9 million and $13.9 million, respectively, and a net-of-tax non-cash charge of $2.0 million was recorded in earnings as a cumulative effect adjustment.

F-16

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.

At December 31, 2003, accumulated OCI consisted of unrealized losses of $0.3 million ($0.2 million, net of tax) on our oil hedging instruments generated prior to the discontinuation of hedge accounting, unrealized losses of $0.5 million ($0.3 million, net of tax) related to pension liabilities and an unrealized gain of $7.0 million ($3.9 million, net of tax) related to our equity in the OCI gains of PAA. At December 31, 2003, the liability related to our open oil hedging instruments was included in current liabilities ($2.8 million), other long-term liabilities ($1.8 million), and deferred income taxes (a tax benefit of $0.1 million).

At December 31, 2003, we had the following open oil derivative positions:


	2004	2005	2006
Swaps
Average price $25.01/bbl	1,500	—	—
Average price $24.70/bbl	—	1,000	—
Average price $24.43/bbl	—	—	1,000

Location and quality differentials attributable to our properties are not included in the foregoing prices. Because of the quality and location of our oil production, these adjustments will reduce our net price per barrel.

Note 6—Long-Term Debt and Credit Facilities

Long-term debt consists of the following at December 31, 2003 and 2002 (in thousands):


	2003				2002
	Current		Long-Term		Current		Long-Term
Secured term loan facility	$	20,000	$	30,000	$	18,000	$	27,000

Aggregate total maturities of long-term debt in the next five years are as follows: 2004—$20.0 million; 2005—$20.0 million; and 2006—$10.0 million.

F-17

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Secured Term Loan Facility

In December 2002, we entered into a $45 million secured term loan facility with a group of banks. We used proceeds from the term loan and cash on hand to make a $40 million capital contribution and repay a $7.2 million note payable to PXP. In June 2003, the facility was restructured to allow us to borrow an additional $24 million that was used to repurchase the 46,600 outstanding shares of our Series D Cumulative Convertible Preferred Stock and pay accrued dividends and related expenses. At December 31, 2003, $50.0 million was outstanding under the secured term loan facility. The term loan is repayable in twelve quarterly installments of $5.0 million each, that commenced on August 31, 2003 with a final maturity of May 31, 2006. Amounts outstanding under the term loan bear an annual interest rate, at our election, equal to either the Base Rate (as defined in the agreement) plus 1.5%, or LIBOR plus 3%. The term loan requires that we maintain $5.0 million on deposit in a debt service reserve account with one of the lending banks. Our average borrowing rate for 2003 was 4.3% (4.2% at December 31, 2003).

Revolving Credit Facility and 10.25% Senior Subordinated Notes Due 2006

In July 2002 all amounts outstanding under our $225.0 million revolving credit facility were repaid and the credit facility was terminated. In August 2002 we redeemed the $267.5 million principal amount of our 10.25% Senior Subordinated Notes Due 2006 (the “10.25% notes”) for $287.0 million. The redemption payment consisted of the $267.5 million principal amount outstanding; a $9.1 million call premium due as a result of the early redemption; and $10.4 million in interest accrued and payable on the redemption date. Upon redemption, all guarantees with respect to the 10.25% notes were terminated. As a result of the redemption of the 10.25% notes and the termination of our revolving credit facility, we recognized a $10.3 million loss on debt extinguishment in 2002.

F-18

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 7—Common Stock and Non-Redeemable Preferred Stock

Common and Preferred Stock

We have authorized capital stock consisting of 50.0 million shares of common stock, $0.10 par value, and 2.0 million shares of preferred stock, $1.00 par value. At December 31, 2003 and 2002, there were 23.7 million shares and 24.2 million shares of common stock outstanding (net of treasury shares), respectively, and at December 31, 2002 there were 46,600 shares of preferred stock outstanding.

Series D Cumulative Convertible Preferred Stock

At December 31, 2002 we had 46,600 shares of Series D Cumulative Convertible Preferred Stock, or Series D Preferred, outstanding that had an aggregate stated value of $23.3 million ($500 per share) and bore an annual dividend of $30.00 per share. In June 2003 we redeemed the Series D Preferred for $23.3 million in cash plus payment of accrued dividends.

Treasury Stock

Our Board of Directors has authorized the repurchase of up to eight million shares of our common stock. In 2003 we repurchased 0.8 million common shares at a cost of $9.0 million and in 2001 we repurchased 2.8 million common shares at a cost of $67.7 million. No repurchases were made in 2002.

F-19

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 8—Earnings Per Share

The following is a reconciliation of the numerators and the denominators of the basic and diluted earnings per share computations for income (loss) from continuing operations before extraordinary items and the cumulative effect of accounting change for the years ended December 31, 2003, 2002 and 2001 (in thousands, except per share amounts):


	Year Ended December 31,
	2003						2002						2001
	Basic			Diluted			Basic			Diluted			Basic			Diluted
Income from continuing operations	$	20,307		$	20,307		$	9,732		$	9,732		$	100,624		$	100,624
Preferred dividends		(603	)		(603	)		(1,400	)		(1,400	)		(27,245	)		(23,880	)

Income (loss) from continuing operations available to common stockholders		19,704			19,704			8,332			8,332			73,379			76,744
Income from discontinued operations		—			—			27,800			27,800			54,693			54,693
Effect of accounting changes, net of tax		933			933			—			—			(1,986	)		(1,986	)

Net income available to common stockholders	$	20,637		$	20,637		$	36,132		$	36,132		$	126,086		$	129,451

Weighted average number of shares of common stock outstanding		23,575			23,575			23,871			23,871			21,090			21,090
Effect of dilutive securities
Convertible preferred stock		—			—			—			—			—			5,280
Employee stock options and restricted stock		—			318			—			580			—			874

Average common shares, including dilutive effect		23,575			23,893			23,871			24,451			21,090			27,244

Earnings (loss) per share
Continuing operations	$	0.84		$	0.82		$	0.35		$	0.34		$	3.48		$	2.81
Discontinued operations		—			—			1.16			1.14			2.59			2.01
Effect of accounting changes		0.04			0.04			—			—			(0.09	)		(0.07	)

Net income available to common stockholders	$	0.88		$	0.86		$	1.51		$	1.48		$	5.98		$	4.75

In 2002 our preferred stock was not included in the computation of diluted earnings per share because the effect was antidilutive. See Note 12 for additional information concerning outstanding options and warrants.

F-20

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 9—Income Taxes

Our deferred income tax assets and liabilities at December 31, 2003 and 2002 consist of the tax effect of income tax carryforwards and differences related to the timing of recognition of certain types of costs as follows (in thousands):


	December 31,
	2003			2002
U.S. Federal
Deferred tax assets:
Net operating losses	$	14,312		$	16,232
Tax credit carryforwards		4,712			6,040
Commodity hedging contracts and other		157			1,941

		19,181			24,213

Deferred tax liabilities:
Net oil & gas acquisition, exploration and development costs		(5,924	)		(7,277	)
Ownership interest in PAA		(20,674	)		423

		(26,598	)		(6,854	)

Total U.S. Federal		(7,417	)		17,359

States
Deferred tax liability		—			(1,175	)
EOR credit		1,180			734

Total State		1,180			(441	)

Foreign
Ownership interest in PAA		(871	)		39

Net deferred tax asset (liability)	$	(7,108	)	$	16,957

At December 31, 2003, we have carryforwards of $40.9 million of regular tax net operating losses (“NOL”), $0.3 million of alternative minimum tax credits and $4.4 million of enhanced oil recovery (“EOR”) credits. At December 31, 2003, we also had $18.0 million of alternative minimum tax NOL carryforwards available as a deduction against future alternative minimum tax income. The NOL carryforwards expire in 2019 and 2020.

F-21

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Set forth below is a reconciliation between the income tax provision (benefit) computed at the United States statutory rate on income (loss) before income taxes and the income tax provision in the accompanying consolidated statements of operations (in thousands):


	Year Ended December 31,
	2003		2002			2001
U.S. federal income tax provision at statutory rate	$	12,868	$	5,575		$	58,771
State income taxes, net of federal benefit		1,128		559			5,292
Foreign income taxes, net of federal benefit		2,347		1,479			916
Other		121		(1,507	)		2,093

Income tax expense (benefit) on income before cumulative effect of accounting change		16,464		6,106			67,072
Income tax benefit allocated to cumulative effect of accounting change		594		—			(228	)

Income tax provision	$	17,058	$	6,106		$	66,844

Under the terms of a tax allocation agreement, PXP has agreed to indemnify us if the spin-off is not tax-free as a result of various actions taken by PXP or with respect to PXP’s failure to take various actions. In addition, PXP agreed that, during the three-year period following the spin-off, without our prior written consent, they will not engage in transactions that could adversely affect the tax treatment of the spin-off unless they obtain a supplemental tax ruling from the IRS or a tax opinion acceptable to us from a 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 may not be able to control some of the events that could trigger this indemnification obligation.

Note 10—Related Party Transactions

Reimbursement of Expenses of the General Partner and Its Affiliates

Prior to the Transactions, the general partner of PAA was a wholly-owned subsidiary of Plains. As a result of the Transactions another entity was named general partner and our ownership in that entity is 44%. Previously, we had sole responsibility for conducting PAA’s business and managing its operations. We did not receive any management fee or other compensation in connection with the management of PAA’s business, but were reimbursed for all direct and indirect expenses incurred on its behalf. For the period from January 1, 2001 to June 8, 2001 we were reimbursed approximately $31.2 million for direct and indirect expenses on PAA’s behalf. The reimbursed costs consisted primarily of employee salaries and benefits. PAA does not employ any persons to manage its business. These functions are provided by employees of the general partner.

Oil Marketing Agreement

PAA is the exclusive marketer/purchaser for all of our equity oil production. The marketing agreement provides that PAA will purchase for resale at market prices all of our equity oil production for which PAA charges a fee of $0.20 per barrel. For the years ended December 31, 2003, 2002 and 2001, PAA paid approximately $26.2 million, $22.7 million and $21.3 million, respectively, for the purchase of oil under the agreement, including the royalty share of production. We paid $0.2 million in marketing fees to PAA in each of 2003, 2002 and 2001.

F-22

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Transaction Grant Agreements

In 1998 at no cost to PAA, we agreed to grant 400,000 of our PAA common units (including distribution equivalent rights attributable to such units) to certain key officers and employees of the general partner and its affiliates. All of the outstanding grants (198,000 units) vested in 2001 as a result of the Transactions. PAA recognized noncash compensation expense related to the transaction grants of approximately $4.8 million in 2001 and we reflected capital contributions of a similar amount. Our share of the noncash compensation is included in our equity in the earnings of PAA in 2001.

Agreements with PXP

Other

The Executive Chairman of our Board of Directors and our Chief Executive Officer own a limited partnership that owns 20% of Plains All American GP LLC, the general partner of PAA.

From time to time we charter private aircraft from Gulf Coast Aviation Inc. (“Gulf Coast”), which is not affiliated with us or our employees. On certain occasions, the aircraft that Gulf Coast charters is owned by our Chairman of the Board. In the years ended December 31, 2003, 2002 and 2001, we paid Gulf Coast $0.1 million, $0.4 million and $0.2, respectively, for aircraft chartering services provided by Gulf Coast using an aircraft owned by our Chairman. The charters were arranged through arms-length dealings with Gulf Coast and the rates were market based.

Note 11—Benefit Plans

We have a nonqualified retirement plan (the “Plan”) for certain of our former officers. Benefits under the Plan are based on salary at the time of adoption, vest over a 15-year period and are payable over a 15-year period commencing at age 60. The Plan is unfunded. In connection with the spin-off, certain of the obligations were transferred to PXP and we paid PXP $0.5 million for the assumption of such obligations.

Net pension expense for the years ended December 31, 2003, 2002 and 2001 is comprised of the following components (in thousands):


	Year Ended December 31,
	2003		2002		2001
Service cost—benefits earned during the period	$	—	$	196	$	156
Interest on projected benefit obligation		91		142		131
Amortization of prior service cost		10		19		31
Unrecognized loss		19		37		17

Net pension expense	$	120	$	394	$	335

F-23

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Summarized information of our retirement plan for the periods indicated is as follows (in thousands):


	December 31,
	2003			2002
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,377		$	1,907
Service cost		—			40
Interest cost		91			126
Settlement losses		—			131
Transfer of obligation to PXP		—			(510	)
Benefits paid		(69	)		(69	)
Settlement payments		—			(252	)
Actuarial (gains) losses		45			4

Benefit obligation at end of year	$	1,444		$	1,377

Amounts recognized in the consolidated balance sheets:
Projected benefit obligation for service rendered to date	$	1,444		$	1,377
Plan assets at fair value		—			—

Benefit obligation in excess of fair value of plan assets		(1,444	)		(1,377	)
Unrecognized (gain) loss		547			521
Unrecognized prior service costs		114			124
Adjustment to recognize minimum liability		(661	)		(645	)

Net amount recognized	$	(1,444	)	$	(1,377	)

The weighted-average discount rate used in determining the projected benefit obligation was 6.25% and 6.75% for the years ended December 31, 2003 and 2002, respectively.

We also maintain a 401(k) defined contribution plan whereby we match 100% of an employee’s contribution (subject to certain limitations in the plan). Matching contributions were made 50% in cash and 50% in common stock of the Company, with the number of shares for the stock match based on the market value of the common stock at the time the shares are granted, through September 30, 2002. Thereafter, matching contributions were made 100% in cash. At the time of the spin-off the plan was transferred to PXP and we established a new 401 (k) plan for the employees that remained with us. The new plan is substantially identical to the plan transferred to PXP. For the years ended December 31, 2003, 2002 and 2001, defined contribution plan expense was $0.1 million, $0.5 million and $0.3 million, respectively.

Note 12—Stock Compensation Plans

Stock Options

Historically, we have used stock options as a long-term incentive for our employees, officers and directors under various stock option plans. We have options outstanding under our 2001 and 1996 plans, under which a maximum of 5.6 million shares of common stock were reserved for issuance. Generally, the options are granted: (i) at an exercise price equal to or greater than the market price of the underlying stock on the date of grant; and (ii) with a pro rata vesting period of two to five years and

F-24

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

an exercise period of five to ten years. Certain options have vesting provisions related to the market price of our common stock. If such options do not vest under such provisions, they vest at the end of a five-year period.

As a result of the spin-off, the exercise price for our stock options was adjusted to approximately 61% of the exercise price at the date of grant. The adjustment was 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’s common stock on the spin-off date ($9.10 per share), both as reported on the NYSE, and the closing price of PXP common stock ($9.10 per share).

Performance options to purchase a total of 500,000 shares of common stock were granted to two executive officers in 1996. Terms of the options provided for an exercise price of $13.50, the market price on the date of grant, and were to vest if shares of our common stock traded at or above $24.00 per share for any 20 trading days in any 30 consecutive trading day period prior to August 2001, or upon a change in control if certain conditions were met. The performance options vested in the second quarter of 2001 and we recognized $4.0 million of noncash compensation expense, which is included in general and administrative expense.

In May 2001, we granted options on 2,250,000 shares under the terms of our 2001 plan subject to the approval of such plan by our board of directors. The market price of our common stock at the time the plan was approved in July 2001 exceeded the exercise price with respect to 1,450,000 of such options and, accordingly, we recognized noncash compensation with respect to such options. During 2003, 2002 and 2001, $0.3 million, $0.5 million and $0.3 million, respectively, in compensation expense with respect to such options is included in general and administrative expense.

A summary of the status of our stock options as of December 31, 2003, 2002, and 2001, and changes during the years ending on those dates are presented below (shares in thousands):


	2003				2002					2001
Fixed Options	Shares		Weighted Average Exercise Price		Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price
Outstanding at beginning of year	4,347		$	13.16		3,667		$	20.30		2,749		$	12.11
Granted	—			—		1,474			19.32		2,464			24.02
Exercised	(361	)		8.77		(457	)		12.00		(1,431	)		11.51
Forfeited	(139	)		13.41		(337	)		23.37		(115	)		14.06

Outstanding at end of year	3,847		$	13.56		4,347		$	13.16		3,667		$	20.30

Options exercisable at year-end	1,606					1,491		$	12.06		1,084		$	13.32

Weighted-average fair value of options granted during the year					$	6.41				$	10.12

F-25

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table summarizes information about stock options outstanding at December 31, 2003 (share amounts in thousands):


Range of Exercise Price	Number Outstanding at 12/31/03	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price		Number Exercisable at 12/31/03	Weighted Average Exercise Price
$ 3.79–$12.79	971	6.0	$	10.70	462	$	8.90
13.92– 13.92	1,000	7.4		13.92	—		—
14.35– 14.35	564	3.1		14.35	190		14.35
14.37– 14.37	288	2.4		14.37	154		14.37
14.50– 16.11	1,024	3.1		15.26	800		15.30

$ 3.79–$16.11	3,847	4.9	$	13.56	1,606	$	13.25

Share Grant

In May 2001, an officer was granted the right to receive an amount, payable in our common stock, equal to the excess of the “fair market value” (as defined in our 2001 plan) of a share of common stock on the effective date and $22.00, multiplied by one million. On the effective date, May 8, 2001, the closing price of our common stock was $23.00 and accordingly, the employee will receive $1.0 million, to be paid in five annual installments as of each anniversary of the effective date, in the form of a direct grant of shares of common stock. The number of shares is determined by dividing the annual installment by the fair market value of a share on the applicable anniversary date. We will recognize $1.0 million of noncash compensation expense ratably over the five-year period.

Restricted Share Grants

During 2003, certain officers and directors were granted awards totaling 146,500 restricted shares of our common stock which will vest in three years, or less based on certain performance criteria.

During 2002, certain officers were granted awards totaling 180,000 restricted shares of our common stock which will vest in three equal annual installments beginning on the first anniversary of the date of grant.

General and administrative expense for 2003 and 2002 includes $2.2 million and $0.3 million, respectively of noncash compensation expense with respect to these share grants.

Note 13—Commitments, Contingencies and Industry Concentration

Commitments and Contingencies

Historically, we leased certain real property, equipment and operating facilities under various operating leases. Prior to the spin-off substantially all of such leases were transferred to PXP. Our future non-cancelable commitments under operating leases at December 31, 2003, which relate to certain real property, are as follows: 2004—$23,000; 2005—$23,000; and 2006—$6,000. Total expenses related to operating lease commitments for the years ended December 31, 2003, 2002 and 2001 were $23,000, $0.7 million and $0.7 million, respectively.

F-26

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

We entered into value assurance agreements with each of the parties that acquired PAA subordinated units from us in the Transactions. The value assurance agreements require us to pay to them 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 expire upon the earlier of (a) the conversion of the subordinated units to common units or (b) June 8, 2006. In the fourth quarter of 2003 25% of PAA’s subordinated units were converted into common units and in February of 2004 the remaining subordinated units were converted. We were not required to make any payments under the value assurance agreements.

Also in connection with the Transactions, 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.

In connection with the reorganization and the spin-off we entered into certain agreements with PXP, including a master separation agreement; an intellectual property agreement; the Plains Exploration & Production transition services agreement; the Plains Resources transition services agreement; and a technical services agreement. 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 spin-off (and related reorganization), regardless of the time those liabilities arise, and to place sole financial responsibility for liabilities associated with our businesses with us and our subsidiaries. We agree to indemnify PXP and PXP agreed to indemnify us 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, if such information was prepared by us or PXP, as the case may be.

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 comply with such rules and regulations

Consistent with normal industry practices, substantially all of our oil and gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. We have estimated that the costs to perform these tasks is approximately $8.1 million, net of salvage value and other considerations. Such costs are accounted for in accordance with SFAS 143 (see Note 1). For valuation and realization purposes of the affected oil and gas properties, these estimated future costs are also deducted from estimated future gross revenues to arrive at the estimated future net revenues and the Standardized Measure disclosed in Note 17.

As is common within the industry, we have entered into various commitments and operating agreements related to the exploration and development of and production from proved oil and gas properties and the marketing, transportation, terminalling and storage of oil. It is management’s belief that such commitments will be met without a material adverse effect on our financial position, results of operations or cash flows.

F-27

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Industry Concentration

Financial instruments which potentially subject us to concentrations of credit risk consist principally of accounts receivable with respect to our oil and gas operations and derivative instruments related to our hedging activities. PAA is the exclusive marketer/purchaser for all of our equity oil production. This concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that PAA may be affected by changes in economic, industry or other conditions. We do not believe the loss of PAA as the exclusive purchaser of our equity production would have a material adverse affect on our results of operations. We believe PAA could be replaced by other purchasers under contracts with similar terms and conditions

There are a limited number of alternative methods of transportation for our production. 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 result in our having to find transportation alternatives, increased transportation costs or involuntary curtailment of a significant portion of our oil and gas production which could have a negative impact on future results of operations or cash flows.

Note 14—Litigation

PLX Stockholder Suits

Beginning November 21, 2003, six putative class action lawsuits were filed against Plains Resources, our directors and our CEO and President, Mr. John T. Raymond, in the Court of Chancery in the State of Delaware, in and for New Castle County, seeking to enjoin the sale of Plains Resources. The lawsuits, and dates of filing, are as follows: No. 071-N, Twist Partners LLP v. Flores et al. (filed Nov. 21, 2003); No. 073-N, Klein v. Flores et al. (filed Nov. 21, 2003); No. 074-N, Levy v. Flores et al. (filed Nov. 21, 2003); No. 075-N, Lanza v. Flores et al. (filed Nov. 21, 2003); No. 076-N, Burt v. Flores et al. (filed Nov. 21, 2003); and No. 143-N, South Broadway Capital v. Flores et al. (filed Dec. 30, 2003).

Four of the complaints (Twist Partners, Klein, Levy, and South Broadway Capital) also named Vulcan Capital as a defendant. Each complaint alleged that the $14.25 per share Vulcan Capital proposal would be inadequate compensation. The Twist Partners complaint alleged that our stock traded as high as $23.05 per share as recently as December 2002 and as high as $14.75 per share as recently as June 2003. It further alleged that the downward trend of the price of our stock reflects temporary market conditions in our industry, and that Mr. Flores and Mr. Raymond recognized a strong likelihood that the price would soon rebound to the levels at which it traded in 2003 and late 2002. The complaint further alleged that Mr. Flores, Mr. Raymond, and Vulcan Capital determined to “usurp this hidden value for themselves,” thereby allegedly denying our minority stockholders the opportunity to obtain fair value for their equity interest. The Twist Partners November 21, 2003 complaint alleged that all individual defendants breached fiduciary duties of due care and loyalty to our stockholders. Vulcan Capital was alleged to have aided and abetted these alleged breaches of fiduciary duty. The complaint alleged, among other things, that the November 20, 2003 announcement of a November 19, 2003 buyout offer represented “a paltry premium of 7.6 percent to Plains’ current trading price and . . . a very significant discount to what it had traded at earlier in the year.” As of the November 21, 2003 filing of the complaint, Twist Partners alleged that the individually named defendants had failed to auction the Company, had failed to conduct an active market check, had not appointed an independent person to negotiate on behalf of our stockholders.

F-28

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

On February 24, 2004, the first amended consolidated complaint was filed in No. 071-N, In re Plains Resources Inc. Shareholders Litigation. That complaint makes additional factual allegations. It alleges that the $14.25 per share Vulcan Capital proposal failed to adequately reflect the value of certain assets and results of the transaction, including: the resulting controlling interest in PAA (for which plaintiffs allege the fair market value of the premium for such control is between $360 and $540 million); incentive distribution rights in Plains AAP (for which plaintiffs allege an estimated present value of $54.4 million); limited partner interest in PAA; our proved oil reserves (of which plaintiffs allege the market value is 15% higher than our standardized measure); certain unspecified tax credits not reflected on our balance sheet; and other unspecified assets, net of liabilities.

The amended consolidated complaint also alleges that: Mr. O’Malley has “significant business and/or personal relationships” with Mr. Flores and Mr. Raymond and is not capable of being a truly independent member of the special committee; the Leucadia proposal was rejected without adequate consideration by the special committee; the special committee’s January 22, 2004 statement that it was “prepared to enter into discussions or negotiations with . . . other parties relating to a transaction” was materially false and misleading, and that the special committee “never intended to entertain proposals from anyone other than Vulcan and/or the Company’s directors”; the Vulcan Capital proposal is not the result of a full and fair auction process or active market check, that the $16.75 per share price was reached without a full and thorough investigation, that the price and process are intrinsically unfair and inadequate; and our directors failed to make an informed decision with respect to the Vulcan Capital proposal.

F-29

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

real value of their equity ownership in the Company,” and that unless an injunction is entered, Vulcan Capital and Messrs. Flores and Raymond “will continue to aid and abet a process that inhibits the maximization of shareholder value.” For purported causes of action, the Texas lawsuit alleges that our directors breached fiduciary duties of loyalty and due care by allegedly failing to (1) inform themselves of our market value before taking action, (2) act in the best interest of our shareholders, (3) maximize shareholder value, (4) obtain the best financial and unspecified other terms when our independent existence will be materially altered by a transaction, and (5) act in accordance with their fundamental duties of due care and loyalty. It further alleges that Vulcan Capital and Messrs. Flores and Raymond aided and abetted our directors’ alleged breaches of fiduciary duties. The relief sought includes (1) declaration of a class action, (2) declaration that the proposed merger agreement “was entered into in breach of the fiduciary duties of” our directors, (3) injunction prohibiting us from proceeding with and consummating the proposed merger, (4) injunction requiring the implementation of procedures to obtain the highest price, (5) injunction requiring our directors “to exercise their fiduciary duties to obtain a transaction which is in the best interests of shareholders until the process for the sale or auction of the Company is completed and the highest possible price is obtained,” (6) unspecified “appropriate damages,” (7) “costs and disbursements,” including reasonable attorneys’ and experts’ fees, and (8) other and further relief which the Court may deem just and proper.

PAA Lawsuit

F-30

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

alleged that all defendants to that action owe fiduciary duties to PAA, its limited partners, and its unitholders which allegedly have been breached by the failure to take actions to protect the interests of PAA, its limited partners, and its unitholders.

Other

The lawsuit regarding the termination of an electric services contract with Commonwealth Energy Corporation was settled in January 2004 by PXP under its indemnity obligation to us. All claims of the lawsuit have been released.

Note 15—Financial Instruments

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standards No. 107, Disclosures About Fair Value of Financial Instruments (“SFAS 107”). The estimated fair value amounts have been determined using available market information and valuation methodologies described below. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying values of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. Derivative financial instruments included other assets are stated at fair value. The carrying amounts and fair values of our other financial instruments are as follows (in thousands):


	December 31,
	2003				2002
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt:
Bank debt	$	50,000	$	50,000	$	45,000	$	45,000

The carrying value of bank debt approximates its fair value, as interest rates are variable, based on prevailing market rates.

F-31

PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 16—Supplemental Disclosures of Cash Flow Information

Selected cash payments and noncash activities were as follows (in thousands):


	Year Ended December 31,
	2003		2002		2001
Cash paid for interest (net of amount capitalized)	$	2,070	$	25,129	$	27,939

Cash paid for taxes	$	3,010	$	4,282	$	7,048

Noncash sources and (uses) of investing and financing activities:
Tax benefit from exercise of employee stock options	$	754	$	2,248	$	6,990

Note 17—Oil and Gas Activities

Costs Incurred

Our oil and gas acquisition, exploration, exploitation and development activities are conducted in the United States. The following table summarizes the costs incurred during the last three years (in thousands).


	Year Ended December 31,
	2003		2002		2001
Property acquisitions costs:
Unproved properties	$	—	$	—	$	—
Proved properties		—		—		153
Exploration costs		—		—		43
Exploitation and development costs		2,912		5,860		10,526

	$	2,912	$	5,860	$	10,722

Amounts presented for 2003 do not include $1.2 million related to the cumulative effect of the adoption of SFAS 143, see Note 4. Costs incurred for discontinued operations for the years ended December 31, 2002 and 2001 was $64.5 million and $125.8 million, respectively.

Capitalized Costs

The following table presents the aggregate capitalized costs subject to amortization relating to our oil and gas acquisition, exploration, exploitation and development activities, and the aggregate related accumulated DD&A (in thousands).


	December 31,
	2003			2002
Proved properties	$	353,653		$	349,517
Accumulated DD&A		(300,344	)		(299,187	)

	$	53,309		$	50,330

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PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The DD&A rate per equivalent unit of production was $4.78, $3.73 and $2.74 for the years ended December 31, 2003, 2002, and 2001, respectively.

Capitalized costs for discontinued operations at December 31, 2002 was $462.2 million.

Costs Not Subject to Amortization

The following table summarizes the categories of costs comprising the amount of unproved properties not subject to amortization (in thousands).


	December 31,
	2003		2002		2001
Acquisition costs	$	—	$	—	$	2,515
Exploration costs		—		—		3,579
Capitalized interest		—		—		1,042

	$	—	$	—	$	7,136

During 2001 we capitalized $0.5 million of interest related to the costs of unproved properties in the process of development.

Costs not subject to amortization for discontinued operations at December 31, 2002 and 2001 was $30.0 million and $33.4 million, respectively.

Results of Operations for Oil and Gas Producing Activities

The results of operations from oil and gas producing activities below exclude non-oil and gas revenues, general and administrative expenses, interest charges, interest income and interest capitalized. Income tax (expense) or benefit was determined by applying the statutory rates to pretax operating results (in thousands).


	Year Ended December 31,
	2003			2002			2001
Revenues from oil and gas producing activities	$	21,857		$	18,662		$	16,030
Production costs		(8,669	)		(6,536	)		(7,397	)
Oil transportation expenses		(3,906	)		(3,775	)		(4,449	)
Depreciation, depletion, amortization and accretion		(4,655	)		(3,239	)		(3,302	)
Income tax (expense) benefit		(2,072	)		(1,971	)		(353	)

Results of operations from producing activities (excluding corporate overhead and interest costs)	$	2,555		$	3,141		$	529

The results of operations from discontinued oil and gas producing activities for the years ended December 31, 2002 and 2001 was $49.2 million and $71.6 million, respectively.

Supplemental Reserve Information (Unaudited)

The following information summarizes our net proved reserves of oil (including condensate and gas liquids) and gas and the present values thereof for the three years ended December 31, 2003. The

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PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

following reserve information is based upon reports of the independent petroleum consulting firm of Netherland, Sewell & Associates, Inc. The estimates are in accordance with regulations prescribed by the SEC.

In management’s opinion, the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation principles consistently applied, are believed to be reasonable. However, 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. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data 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 and gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the Standardized Measure shown below represents estimates only and should not be construed as the current value of the estimated oil and gas reserves attributable to our properties. In this regard, the information set forth in the following 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.

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. All of our reserves are comprised of oil properties that are sensitive to oil price volatility.

Estimated Quantities of Oil Reserves (Unaudited)

The following table sets forth certain data pertaining to our proved and proved developed reserves for the three years ended December 31, 2003 (in thousands).


	As of or for the Year Ended December 31,
	2003		2002		2001
	Oil (MBbls)
Proved Reserves
Beginning balance	16,313		17,343		18,775
Revision of previous estimates	(921	)	(60	)	(2,470	)
Extensions, discoveries, improved recovery and other additions	—		—		1,992
Production	(845	)	(970	)	(954	)

Ending balance	14,547		16,313		17,343

Proved Developed Reserves
Beginning balance	14,499		15,456		17,853

Ending balance	12,730		14,499		15,456

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PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Proved oil and gas reserves for discontinued operations totaled 240.2 MMBbls of oil and 77.1 Bcf of gas at December 31 2002; and 223.3 MMBbls of oil and 96.2 Bcf of gas at December 31, 2001.

Standardized Measure of Discounted Future Net Cash Flows (Unaudited)

The Standardized Measure of discounted future net cash flows relating to proved oil reserves is presented below (in thousands):


	December 31,
	2003			2002			2001
Future cash inflows	$	302,307		$	330,377		$	171,319
Future development costs		(28,088	)		(30,992	)		(24,131	)
Future production expense		(151,290	)		(151,539	)		(112,503	)
Future income tax expense		(22,558	)		(27,136	)		—

Future net cash flows		100,371			120,710			34,685
Discounted at 10% per year		(34,813	)		(47,371	)		(8,140	)

Standardized measure of discounted future net cash flows	$	65,558		$	73,339		$	26,545

The Standardized Measure of discounted future net cash flows related to discontinued operations at December 31, 2002 and 2001 was $883.5 million and $384.5 million, respectively.

The Standardized Measure of discounted future net cash flows (discounted at 10%) from production of proved reserves was developed as follows:

An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions.

In accordance with SEC guidelines, the engineers’ estimates of future net revenues from our proved 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. We have entered into various arrangements to fix or limit the NYMEX oil price for a significant portion of our oil production. Arrangements in effect at December 31, 2003 are discussed in Note 5. Such arrangements are not reflected in the reserve reports. The overall average year-end realized price used in the reserve reports as of December 31, 2003, was $20.78 per barrel of oil. Such price as of December 31, 2002 was $20.25 per barrel of oil.

The future gross revenue streams were reduced by estimated future operating costs (including production and ad valorem taxes) and future development and abandonment costs, all of which were based on current costs.

The reports reflect the pre-tax Present Value of Proved Reserves to be $77.5 million, $87.9 million and $26.5 million at December 31, 2003, 2002 and 2001, respectively. SFAS No. 69 requires us to further reduce these estimates by an amount equal to the present value of estimated income taxes which might be payable by us in future years to arrive at the Standardized Measure. Future income taxes were 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 operations.

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PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The principal sources of changes in the Standardized Measure of the future net cash flows for the three years ended December 31, 2003, are as follows (in thousands):


	Year Ended December 31,
	2003			2002			2001
Balance, beginning of year	$	73,339		$	26,545		$	41,210
Sales, net of production expenses		(9,589	)		(8,964	)		(5,355	)
Net change in sales and transfer prices, net of production expenses		(5,078	)		77,743			(16,188	)
Changes in estimated future development costs		1,526			(3,185	)		1,374
Extensions, discoveries and improved recovery, net of costs		—			—			5,768
Previously estimated development costs incurred during the year		1,910			915			840
Revision of quantity estimates		(7,342	)		(8,125	)		(6,239	)
Accretion of discount		8,103			2,986			5,135
Net change in income taxes		2,689			(14,576	)		—

Balance, end of year	$	65,558		$	73,339		$	26,545

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PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 18—Quarterly Financial Data (Unaudited)

As a result of the spin-off, the historical results of operations of PXP are reflected as discontinued operations. The following table shows summary financial data for 2003 and 2002 (in thousands, except per share data):


	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Year
2003
Revenues	$	6,970		$	4,347		$	4,917		$	5,623		$	21,857
Costs and expenses		6,653			5,480			5,701			6,709			24,543
Equity in earnings of PAA		6,325			5,397			3,142			209			15,073
Gains on PAA unit transactions and public offerings		6,108			—			9,119			18,010			33,237
Income before cumulative effect of accounting change		6,391			1,096			5,825			6,995			20,307
Cumulative effect of accounting change		933			—			—			—			933
Cumulative preferred dividends		(350	)		(253	)		—			—			(603	)
Income available to common stockholders		6,974			843			5,825			6,995			20,637
Basic EPS
Continuing operations		0.25			0.04			0.25			0.30			0.84
Cumulative effect of accounting change		0.04			—			—			—			0.04
Net income		0.29			0.04			0.25			0.30			0.88
Diluted EPS
Continuing operations		0.24			0.04			0.24			0.29			0.82
Cumulative effect of accounting change		0.04			—			—			—			0.04
Net income		0.28			0.04			0.24			0.29			0.86
2002
Revenues	$	4,056		$	4,659		$	5,151		$	4,796		$	18,662
Costs and expenses		5,261			5,196			4,950			4,790			20,197
Equity in earnings of PAA		4,350			5,256			4,454			4,747			18,807
Gains on PAA unit transactions and public offerings		—			—			14,512			—			14,512
Income from continuing operations		732			1,456			3,767			3,777			9,732
Income from discontinued operations		5,864			8,218			7,418			6,300			27,800
Net income		6,596			9,674			11,185			10,077			37,532
Cumulative preferred dividends		(350	)		(350	)		(350	)		(350	)		(1,400	)
Income available to common stockholders		6,246			9,324			10,835			9,727			36,132
Basic EPS
Continuing operations		0.02			0.05			0.14			0.14			0.35
Discontinued operations		0.25			0.34			0.31			0.26			1.16
Net income		0.27			0.39			0.45			0.40			1.51
Diluted EPS
Continuing operations		0.02			0.04			0.14			0.14			0.34
Discontinued operations		0.24			0.33			0.30			0.26			1.14
Net income		0.26			0.37			0.44			0.40			1.48

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PLAINS RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 19—Subsequent Event

On February 18, 2004 a special committee comprised of board members William C. O’Malley and William M. Hitchcock, voted unanimously to recommend to our Board of Directors and to Plains Resources stockholders a proposal from Vulcan Capital, Inc., our Chairman, James C. Flores, and our CEO and President, John T. Raymond, or the Vulcan Group, to acquire all of our outstanding stock for $16.75 per share in cash. Our Board of Directors, excluding Mr. Flores, has approved the merger agreement and recommends that stockholders vote in favor of the transactions contemplated thereby.

The merger agreement contains customary fiduciary termination rights. If the merger agreement is terminated, under specified circumstances, we have agreed to reimburse all of the Vulcan Group’s reasonable out-of-pocket expenses. In addition, in certain circumstances we have agreed to pay a termination fee of $15 million. In all other circumstances, each party must pay all fees and expenses it incurs relating to the merger. The closing of the merger is subject to approval by the stockholders of Plains Resources and other customary closing conditions. We plan to hold a special meeting of stockholders as soon as practicable. Completion of the transaction is expected during the second quarter of 2004. If the merger is consummated, Plains Resources will become a privately held company. Accordingly, upon closing, the registration of the Company’s common stock under the Securities Exchange Act of 1934 will terminate and the Company will cease filing reports with the Securities and Exchange Commission (“SEC”).

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