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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

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

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2004

OR

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

SECURITIES EXCHANGE ACT OF 1934

Commission file number: 001-31470

PLAINS EXPLORATION & PRODUCTION COMPANY

(Exact name of registrant as specified in its charter)

700 Milam Street, Suite 3100

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)

(713) 579-6000

(Registrant’s telephone number, including area code)

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

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

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

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

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

On February 28, 2005, there were 77.4 million shares of the registrant’s Common Stock outstanding. The aggregate market value of the Common Stock held by non-affiliates of the registrant (treating all executive officers and directors of the registrant, for this purpose, as if they may be affiliates of the registrant) was approximately $1.36 billion on June 30, 2004 (based on $18.35 per share, the last sale price of the Common Stock as reported on the New York Stock Exchange on such date).

DOCUMENTS INCORPORATED BY REFERENCE: The information required in Part III of the Annual Report on Form 10-K is incorporated by reference to the registrant’s definitive proxy statement to be filed pursuant to Regulation 14A for the registrant’s 2005 Annual Meeting of Stockholders.

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PLAINS EXPLORATION & PRODUCTION COMPANY.

2004 ANNUAL REPORT ON FORM 10-K

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STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

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

AVAILABLE INFORMATION

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

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thereto, free of charge from our website. These documents are posted to our website as soon as reasonably practicable after we have filed or furnished these documents with the SEC. We have placed on our website copies of our Corporate Governance Guidelines, charters of our Audit, Organization and Compensation and Nominating and Corporate Governance Committees, and our Policy Concerning Corporate Ethics and Conflicts of Interest. Stockholders may request a printed copy of these governance materials by writing to the Corporate Secretary, Plains Exploration & Production Company, 700 Milam, Suite 3100, Houston, TX 77002.

GLOSSARY OF OIL AND GAS TERMS

The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and this document:

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.

Bcfe.    One billion cubic feet of gas equivalent.

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

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 or gas.

Gas.    Natural gas.

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

MBOE.    One thousand BOE.

Mcf.    One thousand cubic feet of gas.

Mcfe.    One thousand cubic feet of gas equivalent.

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

MMBOE.    One million BOE.

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

MMcf.    One million cubic feet of gas.

MMcfe.    One million cubic feet of gas equivalent.

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

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),

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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.    Proved oil and gas reserves are the estimated quantities of oil, gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

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

Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

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 natural 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 natural gas liquids, that may occur in undrilled prospects; and (iv) oil, gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

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

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

Reserve additions.    Changes in proved reserves due to revisions of previous estimates, extensions, discoveries, improved recovery and other additions and purchases of reserves in-place.

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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.

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.

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.

The terms terms “development well”, “proved developed reserves”, “proved reserved” and “proved undeveloped reserves” are defined by the SEC. References herein to “Plains Exploration”, “Plains”, “PXP”, the “Company”, “we”, “us” and “our” mean Plains Exploration & Production Company.

Items 1 and 2.    Business and Properties.

General

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

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

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Acquisition of Nuevo Energy Company

On May 14, 2004 we acquired Nuevo Energy Company (“Nuevo”) in a stock-for-stock transaction. In the acquisition, each outstanding share of Nuevo common stock was converted into 1.765 shares of PXP common stock and Nuevo became our wholly owned subsidiary. At the closing of this transaction we issued 36.5 million additional PXP common shares and assumed $254 million in net debt and $115 million of $2.875 Term Convertible Securities, Series A, or TECONS. The transaction is expected to qualify as a tax free reorganization under Section 368(a) of the Internal Revenue Code and to be tax free to our stockholders and to be tax free for the stock portion of the consideration received by Nuevo stockholders. We have accounted for the transaction as a purchase of Nuevo under purchase accounting rules and we continue to use the full cost method of accounting for our oil and gas properties.

In connection with our acquisition of Nuevo we completed a series of transactions to refinance a portion of our and all of Nuevo’s outstanding debt (the “Recapitalization Transactions”). The Recapitalization Transactions included amendments to our credit facility and the indenture governing our 8.75% senior subordinated notes, our issuance of $250 million of 7.125% senior notes due 2014, a cash tender offer for Nuevo’s outstanding $150 million of 9.375% senior subordinated notes, the redemption of the TECONS and the termination of Nuevo’s credit facility. All of these transactions were successfully completed on or before June 30, 2004. See—Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations—Financing Activities.

Acquisition of 3TEC Energy Corporation

On June 4, 2003, we acquired 3TEC Energy Corporation (“3TEC”) for approximately $312.9 million in cash and common stock plus $90.0 million to retire 3TEC’s outstanding debt. Prior to the acquisition, 3TEC was engaged in the upstream activities of acquiring, exploiting, developing and producing oil and gas in East Texas and the Gulf Coast region, both onshore and in the shallow waters of the Gulf of Mexico. In the transaction each 3TEC common share was converted into 0.85 of a share of our common stock and $8.50 in cash. In connection with the merger, we paid cash consideration to the 3TEC common shareholders of approximately $152.4 million and issued 15.3 million shares. In addition, we paid cash consideration of $8.3 million and issued 0.8 million common shares to redeem outstanding warrants. The cash portion of the purchase price was funded by the issuance of $75.0 million of senior subordinated notes and amounts borrowed under our revolving credit facility. We have accounted for the acquisition of 3TEC under purchase accounting rules effective June 1, 2003.

Acquisition of Oil and Gas Properties

We have entered into an agreement to acquire certain California producing oil and gas properties from a private company for $119 million. The properties, which currently produce approximately 2,000 BOE per day, are primarily located in the Los Angeles Basin of onshore California with some smaller properties located in adjacent Ventura County. The transaction is expected to close in the second quarter of 2005, subject to customary closing conditions. The acquisition will be financed under our existing credit facility.

Oil and Gas Reserves

We had estimated proved reserves of 419.3 MMBOE as of December 31, 2004, of which 84% was comprised of oil and 68% was proved developed. We have a total proved reserve life of over 16 years and a proved developed reserve life of over 11 years. We believe our long-lived, low production decline reserve base combined with our active hedging strategy should provide us with relatively stable and recurring cash flow. As of December 31, 2004 and based on year-end 2004 spot market prices of $43.45 per Bbl of oil and $6.15 per MMBtu of gas, as adjusted for area and quality differentials, our reserves had a PV-10 of $3.3 billion and a standardized measure of $2.2 billion.

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The following table sets forth information with respect to our oil and gas properties as of and for the year ended December 31, 2004 (dollars in millions):

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The following table sets forth certain information with respect to our reserves based upon reserve reports prepared by the independent petroleum consulting firms of Netherland, Sewell & Associates, Inc. in 2004 and Netherland, Sewell & Associates, Inc. and Ryder Scott Company in 2003 and 2002. The reserve volumes and values were determined under the method prescribed by the SEC, which requires the application of year-end prices for each year, held constant throughout the projected reserve life.

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During the three-year period ended December 31, 2004 we participated in 38 exploratory wells, of which 25 were successful, and 352 development wells, 349 of which were successful. During this period, we incurred aggregate oil and gas acquisition, exploitation, development and exploration costs of $2.1 billion, approximately 97% of which was for acquisition, exploitation and development activities. During this period proved reserve additions totaled 291.2 MMBOE.

There are numerous uncertainties inherent in estimating quantities and values of proved reserves, and in projecting future rates of production and timing of development expenditures. Many of the factors that impact these estimates are beyond our control. Reservoir engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. Because all reserve estimates are to some degree speculative, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures, and future oil and gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the PV-10 shown above represents estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties.

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

Since December 31, 2003 we have not filed any estimates of total net proved oil or gas reserves with any federal authority or agency other than the SEC.

Exploitation, Development and Exploration

We expect to continue our reserve and production growth through the exploitation and development of our existing inventory of projects in each of our primary operating areas. To complement the exploitation and development activities, we expect to continue to expand on our success in exploratory drilling by taking advantage of our exploratory projects in south Louisiana, Texas and the Gulf of Mexico. To implement the plans, we will focus on:

By implementing our exploitation, development and exploration plan, we seek to increase cash flows and enhance the value of our asset base. In doing so, we add to and enhance our proved

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reserves. During the three-year period ended December 31, 2004 our additions to proved reserves, excluding reserves added as a result of acquisition activities, totaled 53.4 MMBOE. During this period we incurred aggregate oil and gas exploitation, development and exploration costs of $378.0 million.

The Company has a $375 million capital budget for 2005. Approximately 40-45% of the budget is expected to be spent on California onshore projects and 10-15% is expected to be spent offshore California. Approximately 20-25% is expected to be spent in the Gulf Coast Basin onshore and offshore Louisiana and includes expected participation in new prospect areas in the Gulf of Mexico. The remainder of the budget is expected to be spent in the East Texas Basin and north Louisiana and the Permian Basin in west Texas. Approximately 85% of the budget is allocated toward reserve exploitation, development drilling and maintenance while 15% is allocated for exploration activities. The capital budget includes estimated capitalized general and administrative and interest expense of $25 million.

Description of Properties

Los Angeles and San Joaquin Basins in California

LA Basin

We essentially hold a 100% working interest in our LA Basin properties, including interests in the Montebello, Inglewood and Inglewood satellite fields, and operate approximately 543 production and 223 waterflood injection wells in the fields. The LA Basin properties are characterized by lighter crude (23 to 29 degree API), wells from 2,000 feet to over 10,000 feet at our Deep Inglewood project and include both primary production and waterfloods.

Seismic technology is being utilized to further evaluate the unproved reserves in our LA Basin properties and enhance development of proved undeveloped reserves: conventional 3-D seismic at the Inglewood field and innovative, passive seismic at one of the Inglewood satellite fields. Interpretation of the Inglewood 3-D data was initiated in 2003 and completed in January 2004 and drilling in the Deep Inglewood project started in February 2004. At the end of February 2005, 20 wells had been drilled and 17 are on line producing approximately 2,500 BOE per day. Three wells are being completed and two additional wells are drilling. This is the first application of 3-D seismic technology for exploitation of an onshore LA Basin oil field.

We also own approximately 480 acres of surface fee land in the Montebello field. We are currently in the process of seeking entitlements from the relevant regulatory agencies to enable residential and commercial real estate development on our fee lands as the Montebello field continues to mature.

In 2004, we spent $61.3 million on capital projects in the LA Basin. The Inglewood field accounted for $50.3 million or 82% of the capital associated with LA Basin projects. Our net average daily production from our LA Basin properties in the fourth quarter of 2004 was 16.2 MBOE per day.

San Joaquin Basin

We hold interests in the Cymric, Midway Sunset, South Belridge, Buena Vista Hills and various other fields in the San Joaquin Basin. Our San Joaquin properties are generally characterized by heavier oil (12 to 16 degree API) and shallow wells (generally less than 2,000 feet) that require cyclic and continuous thermal stimulation. These properties also produce lesser amounts of lighter oil and natural gas under primary recovery.

In 2004, we spent $28.2 million on capital projects in the San Joaquin Basin and drilled 58 wells. In the South Belridge field we spent $12.2 million and drilled 26 wells, in the Cymric field we spent $7.7 million and drilled 16 wells, in the Midway Sunset field we spent $5.4 million and drilled 14 wells and in the other fields we spent $2.9 million and drilled two wells. Our net average daily production from our San Joaquin Basin properties in the fourth quarter of 2004 was 28.7 MBOE per day.

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Other Onshore California

We hold a 100% working interest (94% net revenue interest) in the Arroyo Grande field located in San Luis Obispo County, California. We also have surface and related development rights to approximately 1,047 acres (net to our interest) included in the 1,500-acre producing unit. The field is primarily under continuous steam injection. We have drilled wells to downsize the injection patterns in the currently developed area from five acres to one and a quarter acres to accelerate recoveries, and realigned steam injection within these areas to increase the efficiency of the recovery process.

Total proved reserves in Arroyo Grande Field were 54.8 MMBOE at December 31, 2004 with 49.2 MMBOE proved undeveloped which represents approximately 37% of our total proved undeveloped reserves. In 2004 we began final planning, engineering, and permitting for the installation of a reverse osmosis water treatment plant and water out-take pipeline needed to remove water from the producing reservoir and increase operating efficiency. We expect to install those facilities during 2005 and 2006 with completion anticipated in mid to late 2006. During 2005 we will continue with an active program of side-track drilling existing wells, converting existing wells to steam injection, and recompleting wells to open additional pay intervals. Accelerated drilling of new wells is anticipated in 2006. In the fourth quarter of 2004 our net production from the field averaged 1.7 MBOE per day.

Santa Maria Basin Offshore California

Point Arguello Unit.    We hold a 52.6% working interests in the Point Arguello unit and the various partnerships owning the related transportation, processing and marketing infrastructure. The sellers of those interests retained responsibility for certain abandonment costs, including: (1) removing, dismantling and disposing of the existing offshore platforms; (2) removing and disposing of all existing pipelines; and (3) removing, dismantling, disposing and remediating all existing onshore facilities. We are responsible for our 52.6% share of all other abandonment costs, primarily well-bore abandonments and conductor removals.

We are the operator for the Point Arguello unit, which consists of three offshore platforms. In 2004, we spent $4.1 million on capital projects and our net average daily oil production for the unit in the fourth quarter of 2004 was 3.8 MBOE per day.

P-0451 E/2 Development.    We are the operator of federal offshore lease P-0451 and have agreements in place between the P-0451 owners and the Point Arguello unit owners that will allow us to participate with at least a 52.6% working interest in the development of the east half of the P-0451 lease. We applied for and received all the appropriate permits or modifications to existing permits from federal, state, and local agencies to allow for drilling into the east half of offshore lease P-0451. The west half of lease P-0451 has already been developed as part of the Point Arguello unit.

In October 2004, we successfully completed the initial development well into the P-0451 E/2 field also known as the Rocky Point structure. A second well was placed on production in January 2005 and at the end of February the two wells were producing at a combined rate of approximately 4,500 barrels per day (gross). A third well was drilling in late February and we estimate up to five additional wells may be drilled to complete P-0451 E/2 exploitation. In 2004 we spent $15.5 million on capital projects on P-0451 E/2.

Point Pedernales.    As a result of the Nuevo acquisition, we acquired a 100% working interest in the Pt. Pedernales field which includes the onshore Lompoc facilities and one platform, which is utilized to exploit the Federal OCS Monterey Reservoir. In 2004 we spent $1.1 million on capital projects. Our net average daily production from our Pt. Pedernales field in the fourth quarter of 2004 was 5.7 MBOE per day. Efforts are also underway to obtain the necessary permits and leasehold rights to exploit the offsetting Tranquillon Ridge Monterey structure, utilizing directional wells drilled from the existing platform to a reservoir within the three mile state water limit.

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Gulf Coast Basin Onshore and Offshore Louisiana

In 2004, we spent $30.3 million on exploration and development projects in this area. We drilled a total of 16 wells, six of which were successful (38% success rate). Our successful wells included one non-operated onshore well, four operated wells in state waters and one operated well in federal waters of the Gulf of Mexico. Planned 2005 activity includes two to three onshore wells, six to eight wells in state waters and five to seven wells in federal waters. Our net average daily oil and gas production for this area was 6.7 MBOE in the fourth quarter of 2004.

In 2003 we acquired an interest in the Breton Sound Extension area which is located east-southeast of New Orleans. We operate portions of the area (where we have a 56.25% working interest) and portions are operated by others (where we have a 37.5% working interest). The wells are in water depths of ten to twenty-five feet. In 2004 we drilled and completed our first operated well in federal waters, in Chandeleur Area 30, as an expansion of our Breton Sound Extension joint venture.

In 2004 we entered into a new joint venture covering six blocks in Main Pass area where two to three wells are planned for 2005. We have a 50% working interest in the joint venture which is operated by an industry partner.

We are pursuing additional opportunities and to date have acquired the right to participate in six “deep water” drilling opportunities in the Gulf of Mexico.

East Texas Basin and North Louisiana

As a result of the 3TEC merger we acquired interests included in the Rosewood, White Oak/Glenwood, Beckville, Carthage, East Henderson and Oak Hill fields in east Texas. The predominant producing formation is the Cotton Valley Sand gas reservoir with indicated potential additional pay in the shallower Travis Peak and Pettit formations. There are many proved undeveloped Cotton Valley drilling locations under regulatory field rules that now permit wells to be drilled on 80 acre spacing as opposed to 160 acre or larger spacing. At year-end 2004 we had 81 identified proved undeveloped locations in this area.

In 2004, we spent $25.6 million on exploitation and development projects on these properties and participated in the drilling of 45 development wells, all of which were successful. Our net average daily oil and gas production for this area was 6.3 MBOE in the fourth quarter of 2004.

Permian Basin in West Texas

As a result of the Nuevo acquisition we acquired an interest in the Pakenham field in west Texas which currently has 164 producing gas wells. The field is located in Terrell County, Texas within the overall Permian Basin complex of West Texas on the southern margin of the Val Verde Basin. We are the operator with working interests ranging from 81% to 100%. In 2004 we spent $14.9 million on capital projects that included the drilling of seven development wells, one of which was dry. Production from the field averaged 3.1 MBOE per day in the fourth quarter of 2004.

Property Divestments

We periodically evaluate and from time to time elect to sell certain of our mature producing properties that we consider to be nonstrategic. Such sales enable us to focus on our core properties, maintain financial flexibility and redeploy the proceeds therefrom to activities that we believe potentially have a higher financial return.

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In December 2004, we completed the sale of certain properties located offshore California and onshore South Texas, New Mexico, and South Louisiana. These transactions included the divestment of 11 platforms in federal and state waters off the coast of California and three related onshore facilities and essentially all our remaining assets in South Texas and New Mexico. These divestments were conducted via negotiated and auction transactions. In aggregate, we received net proceeds of approximately $153 million from these transactions. These amounts are subject to customary post closing adjustments and the offshore California sale is subject to certain post closing regulatory approvals and transfer conditions. The offshore California properties were acquired in May 2004 as a result of the Nuevo acquisition. We have agreed to retain certain abandonment obligations in connection with the offshore California properties.

In a series of transactions in the first and second quarters of 2004 we sold our interests in certain non-core producing properties in New Mexico, Texas, Mississippi, Louisiana, and Illinois for proceeds of approximately $28 million. Our oil and gas interests in the Illinois Basin were not in our core areas of operation and did not compete well for capital with the properties within our core areas. The Illinois properties also had high operating costs. These factors led to the sale of our Illinois properties through an extensive auction process. The sale was completed through a stock purchase agreement with standard terms, including typical purchase price adjustments, representations and warranties, and assumption of liabilities by the purchaser for an adjusted purchase price of approximately $14 million. The reserves attributable to our Illinois properties were not material in relation to our total reserves.

In 2003, we sold our interest in 36 predominantly non-operated and noncore fields in the Permian Basin, the Texas Panhandle, east Texas, the Mid-continent Area, Alabama, Arkansas, Mississippi, North Dakota and New Mexico for aggregate proceeds of approximately $23 million.

Other

During the second and third quarters of 2004, we sold certain real estate parcels acquired in the Nuevo merger and received aggregate proceeds of approximately $4 million. The properties represented approximately 609 surface acres located in Santa Barbara and Los Angeles counties in California.

In April 2004, Nuevo entered into definitive agreements for the sale of the stock of its subsidiaries that held oil and gas interests in the Republic of Congo. The sale closed on July 30, 2004 and we received net cash consideration of approximately $54 million. When we acquired Nuevo, the fair value of the investment in the Congo operations was accounted for as an asset held for sale.

In December 2003, Nuevo sold its Tonner Hills residential development property for approximately $47 million. To date approximately $41 million of the purchase price has been received and the remainder is due upon completion of certain habitat restoration activities, which we expect to complete during 2005.

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Acquisition, Exploration, Exploitation and Development Expenditures

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

Exploitation and development costs include expenditures of $31.2 million in 2004, $30.2 million in 2003 and $27.3 million in 2002 related to the development of proved undeveloped reserves included in our proved oil and gas reserves at the beginning of each year. Exploitation and development costs include capital costs required to maintain our proved developed producing reserves. Amounts presented do not include the cumulative effect adjustment for the January 1, 2003 adoption of SFAS 143 of $15.9 million.

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Production and Sales

The following table presents information with respect to oil and gas production attributable to our properties, the revenues we derived from the sale of this production, average sales prices we realized and our average production expenses during the years ended December 31, 2004, 2003 and 2002.

Product Markets and Major Customers

Our revenues are highly dependent upon the prices of, and demand for, oil and gas. Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile in the future. The prices we receive for our oil and gas production are subject to wide fluctuations and depend on numerous factors beyond our control, including location and quality differentials, seasonality, economic conditions, foreign imports, political conditions in other oil-producing and gas-producing countries, the actions of OPEC, and domestic government regulation, legislation and policies. Decreases in oil and

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gas prices have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and our revenues, profitability and cash flow.

To manage our exposure to commodity price risks, we use various derivative instruments to hedge our exposure to price fluctuations on oil and gas sales. Our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. However, ceiling prices in our hedges may cause us to receive less revenue on the hedged volumes than we would receive in the absence of hedges.

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

A substantial portion of our oil and gas reserves are located in California and approximately 55% of our production is attributable to heavy crude (generally 21 degree API gravity crude oil or lower). Our heavy crude is primarily sold to ConocoPhilips under a 15 year contract which expires on December 31, 2014. This contract provides for pricing based on a percentage of the NYMEX crude oil price for each type of crude oil that we produce and deliver to ConocoPhillips in California. This percentage may be renegotiated every two years, with the current percentage rates eligible for renegotiation effective at the end of 2005. We are currently receiving approximately 80% of the NYMEX index price for crude oil sold under the ConocoPhillips contract, representing approximately 46% of our total crude oil production.

Approximately 44% of our crude oil production is sold through Plains All American Pipeline, L.P. (“PAA”) with 71% sold under contracts that provide for NYMEX less a fixed price differential (currently averaging NYMEX less $4.80) and 29% sold under contracts that provide for monthly field posted prices. These contracts expire at various times from January 1, 2006 through 2008. The marketing agreement with PAA provides that PAA will purchase for resale at market prices certain of our oil production for which PAA charges a marketing fee of either $0.20 or $0.15 per barrel based upon the contract the barrels are resold under.

The remaining 10% of our crude oil production is sold to others under contracts tied to monthly field posted prices. All production volumes in the foregoing discussion are based on the Company’s fourth quarter 2004 production volumes, pro forma as if the property sales completed in the fourth quarter were effective as of October 1, 2004.

The market price for California crude oil differs from the established market indices in the U.S., due principally to the higher transportation and refining costs associated with heavy oil. While the contracts providing for NYMEX based pricing do not reduce our exposure to price volatility, they do help manage the risk of widening basis differentials between the NYMEX index price and the field posted prices for our California oil production. During 2004, the basis differentials for California crude oil widened significantly from past levels and the prices received by the Company under NYMEX based crude oil contracts were favorable relative to the current market prices. There can be no assurance that the Company will continue to receive the favorable differentials when the price differentials are renegotiated or that the market differentials will not decrease below our contracted prices.

Deregulation of gas prices has increased competition and volatility of gas prices. Prices received for our gas are subject to seasonal variations and other fluctuations. Approximately 84% of our gas production is sold monthly based on industry recognized, published index pricing. The remaining 16% is priced daily on the spot market. Fluctuations between the two pricing mechanisms can significantly impact the overall differential to the Henry Hub.

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During 2004, 2003 and 2002 sales to PAA accounted for 33%, 70% and 95%, respectively, of our total revenues and during 2004 sales to ConocoPhillips accounted for 33% of our total revenues. During such periods no other purchaser accounted for more than 10% of our total revenues. The loss of any single significant customer or contract could have a material adverse short-term effect, however, we do not believe that the loss of any single significant customer or contract would materially affect our business in the long-term. We believe such purchasers could be replaced by other purchasers under contracts with similar terms and conditions. However, their role as the purchaser of a significant portion of our oil production does have the potential to impact our overall exposure to credit risk, either positively or negatively, in that they may be affected by changes in economic, industry or other conditions.

Productive Wells and Acreage

As of December 31, 2004 we had working interests in 2,662 gross (2,620 net) active producing oil wells and 1,077 gross (573 net) active producing gas wells. The following table sets forth information with respect to our developed and undeveloped acreage as of December 31, 2004:

.

Drilling Activities

Information with regard to our drilling activities during the years ended December 31, 2004, 2003 and 2002 is set forth below:

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At December 31, 2004 there were 13 development wells (4.7 net) and 6 exploratory wells (5.4 net) in progress.

Real Estate

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

In the course of our business, certain of our properties may be subject to easements or other incidental property rights and legal requirements that may affect the use and enjoyment of our property.

Title to Properties

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

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

Competition

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

Regulation

Our operations are subject to extensive regulations. Many federal, state and local departments and agencies are authorized by statute to issue, and have issued, laws and regulations binding on the oil and gas industry and its individual participants. The failure to comply with these rules and

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regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability. However, we do not believe that we are affected in a significantly different manner by these laws and regulations than are our competitors. Due to the myriad 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, or OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard, the United States Environmental Protection Agency community-right-to know regulations, and similar state statutes require that we maintain certain information about hazardous materials used or produced in our operations and that we provide this information to our employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances.

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

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

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

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Sale of gas.    The FERC regulates interstate gas pipeline transportation rates and service conditions. Although the FERC does not regulate gas producers such as us, the agency’s actions are intended to foster increased competition within all phases of the gas industry. To date, the FERC’s pro-competition policies have not materially affected our business or operations. It is unclear what impact, if any, future rules or increased competition within the gas industry will have on our gas sales efforts.

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

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

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

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

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Plugging, Abandonment and Remediation Obligations

Consistent with normal industry practices, substantially all of our oil and gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. Typically when producing oil and gas assets are purchased, one assumes the obligation to plug and abandon wells that are part of such assets. However, in some instances, we receive an indemnity with respect to those costs.

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

We estimate our 2005 cash expenditures related to plugging, abandonment and remediation will be approximately $4.3 million. Due to the long life of our onshore California reserve base we do not expect our cash outlays for such expenditures for these properties will increase significantly in the next several years. Although our offshore California properties have a shorter reserve life, third parties have retained the majority of the obligations for abandoning these properties.

In connection with the sale of certain properties offshore California in December 2004 we retained the responsibility for certain abandonment costs, including removing, dismantling and disposing of the existing offshore platforms. The present value of such abandonment costs, $35.0 million ($62.5 million undiscounted), are included in our asset retirement obligation as reflected on our consolidated balance sheet. In addition, we agreed to guarantee the performance of the purchaser with respect to the remaining abandonment obligations related to the properties (approximately $44 million).

Employees

As of February 28, 2005 we had 696 full-time employees, 410 of whom were field personnel involved in oil and gas producing activities. We believe our relationship with our employees is good. None of our employees is represented by a labor union.

Risk Factors

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

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

Our success is largely dependent on oil and gas prices, which are extremely volatile. Any substantial or extended decline in the price of oil and gas below current levels will have a negative

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impact on our business operations and future revenues. Moreover, oil and gas prices depend on factors we cannot control, such as:

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

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

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

In addition, there are limitations related to the methods of transportation for our production. Substantially all of our oil and gas production is transported by pipelines and trucks owned by third parties. The inability or unwillingness of these parties to provide transportation services to us for a reasonable fee could result in our having to find transportation alternatives, increased transportation costs or involuntary curtailment of a significant portion of our oil and gas production, any of which could have a negative impact on our results of operations and cash flows.

The majority of our oil production in California is dedicated to two customers and as a result, our credit exposure to those customers is significant.

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

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

Our future success depends on our ability to find, develop and acquire additional oil and gas reserves that are economically recoverable which, in itself, is dependent on oil and gas prices. Without continued successful exploitation, acquisition or exploration activities, our reserves and revenues will decline as a result of our current reserves being depleted by production. We may not be able to find or acquire additional reserves at acceptable costs.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Our business is subject to federal, state and local laws and regulations as interpreted by governmental agencies and other bodies, including those in California, vested with broad 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, or their interpretations, could be changed, and any changes could increase costs of compliance and costs of operating drilling equipment or significantly limit drilling activity.

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

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. We also may be liable for environmental damages caused by the previous owners or operators of properties we have purchased or are currently operating. A variety of stringent federal, state and local laws and regulations govern the environmental aspects of our business and impose strict requirements for, among other things:

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

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

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

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existing or future laws, rules and guidelines could prohibit or limit our operations and our planned activities for this property.

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

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

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

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

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

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

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

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

Prior to December 18, 2002 we were a wholly owned subsidiary of Plains Resources Inc. (“Plains Resources”, now known as Vulcan Energy Corporation). On December 18, 2002 Plains Resources distributed 100% of the issued and outstanding shares of our common stock to the holders of record of Plains Resources’ common stock as of December 11, 2002. Each Plains Resources stockholder received one share of our common stock for each share of Plains Resources common stock held. Plains Resources received a favorable private letter ruling from the Internal Revenue Service stating that for United States federal income tax purposes, the distribution of our common stock qualified as a tax-free distribution under Section 355 of the Internal Revenue Code.

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

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

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

Stock appreciation rights (SARs) are subject to variable accounting treatment. As a result, at the end of each quarter, we compare the per share closing price of our common stock to the exercise price of each stock appreciation right that is vested or for accounting purposes is deemed vested at the end of the quarter. Under current accounting rules, to the extent the closing price exceeds the exercise price, we will recognize the excess as an accounting charge to the extent we did not previously recognize such excess. If, at the end of the quarter, the per share closing price of our common stock

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decreased, the stock appreciation right accounting charge would decrease, resulting in increased net income for us. For the year ended December 31, 2004 we recognized $35.5 million of SAR expense. Based on the number of stock appreciation rights outstanding at December 31, 2004, a $0.25 change in the price of our common stock would result in a change of $0.6 million in our net income.

In December 2004 the FASB issued SFAS No. 123R (revised 2004), “Share-Based Payment” (“SFAS 123(R)”). SFAS 123(R) requires that the compensation cost relating to share-based payment transactions be recognized in financial statements effective with the third quarter of 2005, Under SFAS No. 123(R) our SARs will be remeasured to fair value each reporting period. We have not determined how the new method of valuing stock-based compensation as prescribed in SFAS 123(R) will be applied to valuing stock-based awards and the impact the recognition of compensation expense related to such awards will have on our financial statements.

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

In a purchase transaction, goodwill represents the excess of the purchase price plus the liabilities assumed, including deferred income taxes recorded in connection with the merger, over the fair value of the net assets acquired. In our acquisitions of 3TEC and Nuevo, goodwill totaled $170.5 million and represented 6% of our total assets at December 31, 2004.

Goodwill is not amortized, but instead must be tested at least annually for impairment by applying a fair-value based test. Goodwill is deemed impaired to the extent of any excess of its carrying amount over the residual fair value of the reporting unit. Such impairment could significantly reduce earnings during the period in which the impairment occurs and would result in a corresponding reduction to goodwill and stockholders’ equity. The most significant factors that could result in the impairment of our goodwill would be significant declines in oil and gas prices and/or reserve volumes which would result in a decline in the fair value of our oil and gas properties.

Item 3.    Legal Proceedings

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

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

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

Directors and Executive Officers of Plains Exploration & Production Company

Listed below are our directors and executive officers, their age as of February 28, 2005 and their business experience for the last five years.

Directors

James C. Flores, age 45, Chairman of the Board, Chief Executive Officer and a Director since September 2002 and President since March 2004.    He has also been a director of Nabors Industries Ltd. since January 2005. He was Chairman of the Board from December 2002 to July 2004 of Plains’ former parent, Plains Resources. He was Chairman of the Board and Chief Executive Officer of Plains

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Resources from May 2001 to December 2002. He was Co-founder as well as Chairman, Vice Chairman and Chief Executive Officer at various times from 1992 until January 2001 of Ocean Energy, Inc., an oil and gas company. From January 2001 to May 2001 Mr. Flores managed various private investments.

Isaac Arnold, Jr., age 69, Director since May 2004.    He also was a director of Nuevo from 1990 to May 2004. He has been a director of Legacy Holding Company since 1989 and Legacy Trust Company since 1997. He has been a director of Cullen Center Bank & Trust since its inception in 1969 and is a director of Cullen/Frost Bankers, Inc. Mr. Arnold is a trustee of the Museum of Fine Arts and The Texas Heart Institute. Mr. Arnold received his B.B.A. from the University of Houston in 1959.

Alan R. Buckwalter, III, age 58, Director since March 2003.    He retired in January 2003 as Chairman of JPMorgan Chase Bank, South Region, a position he had held since 1998. From 1990 to 1998 he was President of Texas Commerce Bank-Houston, the predecessor entity of JPMorgan Chase Bank. Prior to 1990 Mr. Buckwalter held various executive management positions within the organization. Mr. Buckwalter currently serves on the boards of Service Corporation International, the Texas Medical Center, Greater Houston Area Red Cross, University of St. Thomas and St. Luke’s Hospital System. He sits on the Audit Committee and is Chairman of the Compensation Committee for Service Corporation International.

Jerry L. Dees, age 65, Director since September 2002.    He also was a director of Plains Resources from 1997 to December 2002. He retired in 1996 as Senior Vice President, Exploration and Land, for Vastar Resources, Inc. (previously ARCO Oil and Gas Company), a position he had held since 1991. From 1987 to 1991 he was Vice President of Exploration and Land for ARCO Alaska, Inc., and from 1985 to 1987 he held various positions as Exploration Manager of ARCO. From 1980 to 1985 Mr. Dees was Manager of Exploration Geophysics for Cox Oil and Gas Producers.

Tom H. Delimitros, age 64, Director since September 2002.    He also was a director of Plains Resources from 1988 to December 2002. He has been a General Partner of AMT Venture Funds, a venture capital firm, since 1989. He is also a director of Tetra Technologies, Inc., a publicly-traded energy services company. He currently serves as Chairman for three privately-owned companies. Previously, he has served as President and CEO for Magna Corporation, (now Baker Petrolite, a unit of Baker Hughes). From 1983 to 1988, Mr. Delimitros was a General Partner of Sunwestern Investment Funds and Senior Vice President of Sunwestern Management, Inc.

Robert L. Gerry III, age 67, Director since May 2004.    He was also a director of Nuevo from 1990 to May 2004. He has been chairman and chief executive officer of Vaalco Energy, Inc., a publicly traded independent oil and gas company which does not compete with Plains, since 1997. From 1994 to 1997, Mr. Gerry was vice chairman of Nuevo. Prior to that, he was president and chief operating officer of Nuevo since its formation in 1990. Mr. Gerry also currently serves as a trustee of Texas Children’s Hospital.

John H. Lollar, age 66, Director since September 2002.    He also was a director of Plains Resources from 1995 to December 2002. He has been the Managing Partner of Newgulf Exploration L.P. since December 1996. He is also a director of Lufkin Industries, Inc., a manufacturing firm, where he is a member of the Compensation Committee and Chairman of the Audit Committee. Mr. Lollar was Chairman of the Board, President and Chief Executive Officer of Cabot Oil & Gas Corporation from 1992 to 1995, and President and Chief Operating Officer of Transco Exploration Company from 1982 to 1992.

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Executive Officers

Stephen A. Thorington, age 49, Executive Vice President and Chief Financial Officer since September 2002.    He was also Plains Resources’ Executive Vice President and Chief Financial Officer from February 2003 to June 2004. He was Plains Resources’ Acting Executive Vice President and Chief Financial Officer from December 2002 to February 2003. Previously, he was Senior Vice President—Finance and Corporate Development of Ocean Energy, Inc. from July 2001 to September 2002 and Senior Vice President—Finance, Treasury and Corporate Development of Ocean Energy, Inc. from March 1999 to July 2001.

John F. Wombwell, age 43, Executive Vice President, General Counsel and Secretary since September 2003.    He was also Plains Resources’ Executive Vice President, General Counsel, and Secretary from September 2003 to June 2004. He was previously a Senior Executive Officer with two New York Stock Exchange traded companies, serving as General Counsel of ExpressJet Holdings, Inc. from April 2002 until September 2003 and prior to joining ExpressJet, Mr. Wombwell was General Counsel of Integrated Electrical Services, Inc. from January 1998 to April 2002. Prior to that time, Mr. Wombwell was a partner at the national law firm of Andrews Kurth LLP with a practice focused on representing public companies with respect to corporate and securities matters.

Thomas M. Gladney, age 52, Executive Vice President—Exploration and Production since June 2003.    He was Plains’ Senior Vice President of Operations from September 2002 to June 2003. He also was Plains Resources’ Senior Vice President of Operations from November 2001 to December 2002. He was President of Arguello, Inc., a subsidiary of Plains, from December 1999 to November 2001.

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 on the New York Stock Exchange under the symbol “PXP”. The following table sets forth the range of high and low closing sales prices for our common stock as reported on the New York Stock Exchange Composite Tape for the periods indicated below:

At December 31, 2004 we had approximately 1,542 shareholders of record.

Dividend Policy

We do not anticipate declaring or paying any cash dividends in the future. We intend to retain our earnings to finance the expansion of our business and for general corporate purposes. Our board of directors will have the authority to declare and pay dividends on our common stock in its discretion, as long as we have funds legally available to do so. As discussed in Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations—Financing Activities, our credit facility and the indentures relating to our 8.75% and 7.125% notes restrict our ability to pay cash dividends.

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Item 6.    Selected Financial Data

The following selected financial information was derived from, and is qualified by reference to, our consolidated financial statements, including the notes thereto, appearing elsewhere in this report. You should read this information in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and notes thereto. This information is not necessarily indicative of our future results.