Plains Exploration & Production 10-K 2005 FY Annual report

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, 2005

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)

Delaware	33-0430755
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

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:

Title of each class	Name of each exchange on which registered
Common Stock, par value $0.01 per share	New York Stock Exchange

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yesþ    No¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes¨    Noþ

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.  Yesþ    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.  þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  þ            Accelerated filer  ¨            Non-accelerated filer  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).  Yes¨    Noþ

On January 31, 2006, there were 78.4 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 $2.7 billion on June 30, 2005 (based on $35.53 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 2006 Annual Meeting of Stockholders.

PLAINS EXPLORATION & PRODUCTION COMPANY.

2005 ANNUAL REPORT ON FORM 10-K

Table of Contents

Part I
Items 1 & 2.	Business and Properties	6
Item 1A.	Risk Factors	21
Item 1B.	Unresolved Staff Comments	28
Item 3.	Legal Proceedings	28
Item 4.	Submission of Matters to a Vote of Security Holders	28
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	29
Item 6.	Selected Financial Data	30
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 7A.	Quantitative and Qualitative Disclosures About Market Risks	51
Item 8.	Financial Statements and Supplementary Data	53
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	53
Item 9A.	Controls and Procedures	54
Item 9B.	Other Information	54
Part III
Item 10.	Directors and Executive Officers of the Registrant	55
Item 11.	Executive Compensation	56
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	57
Item 13.	Certain Relationships and Related Transactions	57
Item 14.	Principal Accounting Fees and Services	57
Part IV
Item 15.	Exhibits, Financial Statement Schedules	58

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STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This annual Report on Form 10-K includes forward-looking information regarding Plains Exploration & Production Company that is intended to be covered by the safe harbor for “forward-looking statements” provided by the Private Securities Litigation Reform Act of 1995. 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. Although we believe that our expectations are based on reasonable assumptions, there are risks, uncertainties and other factors that could cause actual results to be materially different from those in the forward-looking statements. These factors include, among other things:

• uncertainties inherent in the development and production of oil and gas and in estimating reserves;

• unexpected future capital expenditures (including the amount and nature thereof);

• impact of oil and gas price fluctuations, including the impact on our reserve volumes and values and our earnings as a result of our derivative positions;

• the effects of our indebtedness, which could adversely restrict our ability to operate, could make us vulnerable to general adverse economic and industry conditions, could place us at a competitive disadvantage compared to our competitors that have less debt, and could have other adverse consequences;

• the success of our derivative activities;

• the success of our risk management activities;

• unexpected difficulties in integrating our operations as a result of any significant acquisitions;

• the effects of competition;

• the availability (or lack thereof) of acquisition or combination opportunities;

• the impact of current and future laws and governmental regulations;

• environmental liabilities that are not covered by an effective indemnity or insurance; and

• general economic, market, industry or business conditions.

All forward-looking statements in this report are made as of the date hereof, and you should not place undue reliance on these statements without also considering the risks and uncertainties associated with these statements and our business that are discussed in this report and our other filings with the SEC. 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 for any obligation to disclose material information under the Federal securities laws, we do not intend to update these forward-looking statements and information. See Item 1A—“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 100 F Street, NE, Room 1580 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 atwww.sec.gov. No information from the SEC’s website is incorporated by

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reference herein. Our website iswww.plainsxp.com. You may also obtain copies of our annual, quarterly and current reports, proxy statements and certain other information filed with the SEC, as well as amendments thereto, free of charge from our 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 & Compensation and Nominating & 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. No information from our website is incorporated by reference herein.

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

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

Gas.    Natural gas.

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.

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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 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 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.

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

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.

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 volumes.

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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 “development well”, “exploratory well”, “proved developed reserves”, “proved reserves” 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.

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PART I

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 six states with principal operations in:

• the Los Angeles and San Joaquin Basins onshore California;

• the Santa Maria Basin offshore California;

• the Gulf Coast Basin onshore and offshore Louisiana, including the Gulf of Mexico; and

• the Val Verde portion of the greater Permian Basin in Texas.

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 use derivative contracts to manage our exposure to commodity price risk.

Oil and Gas Reserves

As of December 31, 2005 we had estimated proved reserves of 401 MMBOE, of which 89% was comprised of oil and 67% was proved developed. We have a total proved reserve life of over 17 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, 2005 and based on year-end 2005 spot market prices of $61.04 per Bbl of oil and $10.08 per MMBtu of gas, as adjusted for area and quality differentials, our reserves had a standardized measure of $3.1 billion.

The following table sets forth information with respect to our oil and gas properties as of and for the year ended December 31, 2005 (dollars in millions):

	California		Other		Total
Proved reserves
MMBOE	384.8		16.2			401.0
Percent oil	92	%	21	%		89	%
Proved Developed Reserves—MMBOE	253.3		13.7			267.0
2005 Production—MMBOE	19.6		4.0			23.6
Standardized measure (1)					$	3,082.2

(1) Estimated future income taxes are calculated on a combined basis using the statutory income tax rate, accordingly, the standardized measure is presented in total only.

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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 2005 and 2004 and Netherland, Sewell & Associates, Inc. and Ryder Scott Company in 2003. 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.

	As of December 31,
	2005		2004		2003
	(dollars in thousands)
Oil and Gas Reserves
Oil (MBbls)
Proved developed		234,638		233,707		124,822
Proved undeveloped		121,695		117,696		102,906
		356,333		351,403		227,728
Gas (MMcf)
Proved developed		193,904		305,009		235,070
Proved undeveloped		74,017		102,391		84,107
		267,921		407,400		319,177
MBOE		400,987		419,303		280,924
Standardized Measure (1)	$	3,082,166	$	2,236,719	$	1,256,803
Average year-end realized prices (2)
Oil (per Bbl)	$	51.40	$	30.91	$	28.22
Gas (per Mcf)	$	6.99	$	5.40	$	5.53
Year-end spot market prices
Oil (per Bbl)	$	61.04	$	43.45	$	32.52
Gas (per Mcf)	$	10.08	$	6.15	$	5.97
Reserve life (years) (3)		17.3		16.3		19.6

(1) Our year-end 2005 standardized measure includes future development costs related to proved undeveloped reserves of $198 million in 2006, $186 million in 2007 and $113 million in 2008.

(2) Based on prices in effect at year-end with adjustments based on location and quality. The market price for California crude oil differs from the established market indices due primarily to the higher transportation and refining costs associated with heavy oil. At the end of 2004 the basis differentials for California crude oil had widened significantly and the difference between the year-end spot market price and our average year-end realized price for 2004 was significantly greater than in other periods.

(3) 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 volumes. Production volumes are based on annualized fourth quarter production and are adjusted, if necessary, to reflect property acquisitions and dispositions.

During the three-year period ended December 31, 2005 we participated in 55 exploratory wells, of which 36 were successful, and 522 development wells, 517 of which were successful. During this period, we incurred aggregate oil and gas acquisition, exploitation, development and exploration costs of $2.6 billion, approximately 93% of which was for acquisition, exploitation and development activities. During this period proved reserve additions totaled 298 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

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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 standardized measure 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, 2004 we have not filed any estimates of total net proved oil or gas reserves with any federal authority or agency other than the SEC.

Acquisitions

We intend to be opportunistic in pursuing selective acquisitions of oil or gas properties or exploration projects. We will consider opportunities located in our current core areas of operation as well as projects in other areas that meet our investment criteria.

2005 Property Acquisitions

In April 2005 we acquired certain California producing oil and gas properties, primarily located in the Los Angeles Basin of onshore California with some smaller properties located in adjacent Ventura County, from a private company for $117 million. In September 2005 we acquired an additional 16.7% interest in the Point Arguello Unit, Rocky Point development project and related facilities, offshore California, from subsidiaries of Chevron U.S.A. Inc. This acquisition increased our working interest in that operation to 69.3%.

Acquisition of Nuevo Energy Company

In May 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. Prior to the acquisition, Nuevo was engaged in the upstream activities of acquiring, exploiting, developing and producing oil and gas primarily onshore and offshore California and in west Texas. We accounted for the transaction as a purchase under purchase accounting rules effective May 14, 2004.

Acquisition of 3TEC Energy Corporation

In June 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,

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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. We accounted for the transaction as a purchase under purchase accounting rules effective June 1, 2003.

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:

• allocating investment capital prudently after rigorous evaluation;

• optimizing production practices;

• realigning and expanding injection processes;

• performing stimulations, recompletions, artificial lift upgrades and other operating margin and reserve enhancements;

• focusing geophysical and geological talent;

• employing modern seismic applications;

• establishing land and prospect inventory practices to reduce costs; and

• using new technology applications in drilling and completion practices.

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 reserves. During the three-year period ended December 31, 2005 our additions to proved reserves, excluding reserves added as a result of acquisition activities, totaled 44 MMBOE. During this period we incurred aggregate oil and gas exploitation, development and exploration costs of $738.5 million.

The Company has a $430 million capital budget for 2006. Approximately 55% to 60% of the capital budget is allocated to the development of existing proved reserves. Spending on exploitation projects is expected to be about 20%, with exploration spending, primarily in the deep water Gulf of Mexico middle and lower Miocene trend, accounting for the remainder of the capital budget. The capital budget includes estimated capitalized general and administrative and interest expense of approximately $30 million.

Approximately 50% to 55% of the budget is expected to be spent on California onshore projects and 5% to 10% is expected to be spent offshore California. Approximately 20% to 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 Permian Basin in west Texas.

Description of Properties

Los Angeles and San Joaquin Basins in California

LA Basin

We essentially hold a 100% working interest in most of our LA Basin properties, including interests in the Montebello, Inglewood, Inglewood satellite, Las Cienegas, Sansinena and other smaller LA

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Basin fields, and operate 834 producing and 250 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.

In April 2005 we purchased certain LA Basin assets that were producing approximately 2.0 MBOE per day at acquisition. The properties included 25 proved undeveloped drilling locations and 75 wells targeted for workover, 31 of which were initiated in 2005.

In 2005 we spent $112 million on capital projects in the LA Basin. The Inglewood field accounted for $101 million or 90% of the capital associated with LA Basin projects. Our net average daily production from our LA Basin properties in the fourth quarter of 2005 was 15.5 MBOE per day.

During the first three quarters of 2005 we completed 37 wells at Inglewood in the Shallow Vickers/Rindge waterflood interval and in the deeper Sentous and Moynier intervals. In the fourth quarter of 2005, we initiated an aggressive development program and completed 14 wells with an additional 10 wells in progress at year end. An additional 73 wells are budgeted in 2006. This program is an acceleration of our historical shallow development program as well as the initiation of a deeper waterflood program. In 2006 we will also begin development drilling on some of the properties that were purchased in early 2005.

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 or continuous thermal stimulation. These properties also produce lesser amounts of lighter oil and natural gas under primary recovery.

In 2005, we spent $80 million on capital projects in the San Joaquin Basin and drilled 171 wells. In the South Belridge field we spent $17 million and drilled 29 wells, in the Cymric field we spent $30 million and drilled 72 wells, in the Midway Sunset field we spent $21 million and drilled 61 wells and in the other fields we spent $12 million and drilled 9 wells. Our net average daily production from our San Joaquin Basin properties in the fourth quarter of 2005 was 26.3 MBOE per day.

San Joaquin drilling in 2006 will encompass both development of existing tertiary recovery steamfloods as well as expansion and initial development of new primary recovery and steamflood projects. The development will largely be focused in the Midway Sunset, Cymric and Mount Poso fields.

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. 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.

In 2004 we began planning and feasibility engineering for the installation of a reverse osmosis water treatment plant and water out-take facilities needed to remove water from the producing reservoir and increase operating efficiency. During 2005, an initial environmental study was completed, preliminary engineering for various water out-take options was completed, and Phase I of a Pilot Plant study was successfully completed. Phase II of the Pilot Plant study will be conducted in 2006 along with submittal of permit applications to the various regulatory agencies.

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During 2006 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 2005 our net production from the field averaged 1.6 MBOE per day.

Santa Maria Basin Offshore California

Point Arguello Unit/P-0451 E/2.    We are the operator and hold 69.3% working interests in the Point Arguello Unit and the various partnerships owning the related transportation, processing and marketing infrastructure. We are also 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 69.3% working interest in the development of the east half of the P-0451 lease.

The companies from which we purchased our interests in the Point Arguello Unit retained responsibility for the majority of the 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 69.3% share of other abandonment costs which primarily consist of well-bore abandonment’s and conductor removals.

In October 2004, we successfully completed the initial development well, the C-12, into the P-0451 E/2 field also known as the Rocky Point structure. The well had an initial production rate of in excess of 4.3 MBOE per day (gross). Subsequent to the initial well two additional wells, the C-13 and C-14, were drilled, neither of which achieved expected results. We successfully re-drilled the C-14 well and completed it at an initial rate of 2.8 MBOE per day (gross) in November 2005. Following the success of this redrill we solicited and received approval from our partners to re-drill the C-13 to better geological objectives as revealed by the C-12 and confirmed by the C-14 redrill. The C-13 was completed in February 2006 at an initial rate of 2.2 MBOE per day (gross). Based on the results of these two side-track near horizontal wells, a new well, the C-15, will be drilled with operations currently underway. Further Rocky Point drilling beyond the C-15 well is not presently anticipated; however, opportunities for additional drilling in the main Point Arguello Field are under review.

In 2005, we spent $32 million on Point Arguello Unit/P-0451 E/2 capital projects and our net average daily oil production in the fourth quarter of 2005 was 5.8 MBOE per day.

Point Pedernales.    We hold a 100% working interest in the offshore Pt. Pedernales field which includes one platform and support facilities which lie within the onshore Lompoc field. The offshore Pt. Pedernales field utilizes one platform to exploit the Federal OCS Monterey Reservoir utilizing extended reach directional wells. In 2005 we spent $16 million on capital projects in this field. Our combined net average daily production from our Pt. Pedernales field and Lompoc field in the fourth quarter of 2005 was 6.6 MBOE per day.

Our 2006 drilling program includes four infill development wells in the Point Pedernales field. Efforts are also underway to obtain the necessary permits and leasehold rights to allow us 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 jurisdictional limit. We currently have one extended reach directional well drilled into and producing from the portion of the Tranquillon structure that extends beyond the three-mile limit into federal waters.

Gulf Coast Basin—Onshore and Offshore Louisiana

In 2005, we spent $122 million on exploration and development projects in the Gulf Coast Basin. We participated in a total of 13 wells, four of which were successful and three of which were in

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progress at year end. In the Breton Sound Extension area, which is located east-southeast of New Orleans, we spent $15 million and drilled three exploratory wells, two of which were successful. Our net average production for this area was 4.3 MBOE per day in the fourth quarter of 2005.

In 2006 our Gulf Coast Basin projects will be primarily gas-focused. In the Breton Sound area we expect to drill four to six exploitation wells, including wells delayed from 2005 due to hurricanes Katrina and Rita. In the deep water Gulf of Mexico we expect to participate in four to eight wells.

In January 2006 Chevron Corporation announced a deepwater oil discovery at the Big Foot prospect in Walker Ridge Block 29, approximately 225 miles south of New Orleans. The Big Foot #2 discovery well is located in approximately 5,000 feet of water and was drilled to a total depth of 25,127 feet. Further appraisal drilling will be required to determine the commercial potential of the discovery. We own a 12.5% working interest in the Big Foot prospect.

Permian Basin in West Texas

We are the operator with working interests ranging from 81% to 100% 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. In 2005 we spent $10 million on capital projects that included both drilling and recompletion opportunities. Production from the field averaged 2.8 MBOE per day in the fourth quarter of 2005. In 2006 we will continue low risk development drilling and recompletions.

Texas Exploration

In 2006 we will participate in some higher risk prospects in Texas, targeting significant gas potential. We anticipate 7 to 15 wells will be drilled on a series of prospects that were acquired in 2005.

Wyoming

We anticipate securing the required permits to allow drilling in 2007, dependent on permit timing and seasonal considerations, on a gas prospect in Wyoming’s Green River Basin that was acquired during 2005.

Property Divestments

We periodically evaluate and from time to time have elected 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.

In May 2005 we closed the sale to XTO Energy, Inc. of interests in producing properties located in East Texas and Oklahoma for net proceeds of approximately $341 million. The proceeds were primarily used to fund the transactions to eliminate all of our 2006 oil price swaps and collars as discussed in “Management’s Discussion and Analysis of Financial Position and Results of Operations—Derivative Instruments and Hedging”.

In December 2004, we completed the sale of certain properties located offshore California and onshore South Texas, New Mexico, and South Louisiana. These unrelated 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 $152 million from these transactions. We retained certain abandonment obligations in connection with the offshore California properties.

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During 2004 and 2003 we sold our interests in certain non-core producing properties for aggregate net proceeds of $28 million and $23 million, respectively.

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.

	Year Ended December 31,
	2005		2004		2003
	(In thousands of dollars)
Property acquisitions costs:
Unproved properties	$	16,682	$	144,894	$	80,141
Proved properties		134,696		1,210,758		295,553
Exploration costs		129,066		57,530		8,947
Exploitation and development costs		300,439		141,198		101,334
	$	580,883	$	1,554,380	$	485,975

Exploitation and development costs include expenditures of $114 million in 2005, $31 million in 2004 and $30 million in 2003 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, 2005, 2004 and 2003.

	Year Ended December 31,
	2005		2004		2003
Sales Volumes
Oil and liquids (MBbls)		18,671		16,441		9,267
Gas (MMcf)		29,359		38,590		18,195
MBOE		23,564		22,872		12,300
Daily Average Sales Volumes
Oil and liquids (Bbls/d)		51,154		44,920		25,389
Gas (Mcfpd)		80,435		105,436		49,849
BOEPD		64,560		62,493		33,697
Unit Economics (in dollars)
Average NYMEX Prices
Oil	$	56.61	$	41.43	$	30.99
Gas		8.62		6.14		5.39
Average Realized Sales Price Before Derivative Transactions
Oil (per Bbl)	$	46.76	$	36.12	$	26.92
Gas (per Mcf)		7.15		5.90		5.01
Per BOE		45.96		35.92		27.69
Costs and Expenses per BOE
Production costs
Lease operating expenses	$	5.97	$	5.36	$	5.44
Steam gas costs		3.32		1.77		0.23
Electricity		1.35		1.32		1.82
Production and ad valorem taxes		1.03		0.98		0.82
Gathering and transportation		0.43		0.33		0.21
DD&A per BOE (oil and gas properties)		7.39		5.93		3.86

The following table reflects cash receipts (payments) made with respect to derivative contracts that settled during the periods presented (in thousands of dollars):

	Year Ended December 31,
	2005			2004			2003
Contracts accounted for using hedge accounting
Oil revenues	$	(53,044	)	$	(207,414	)	$	(50,875	)
Gas revenues		(6,255	)		(17,504	)		240
Steam gas costs		10,293			3,649			—
Mark-to-market contracts		(279,982	)		(32,187	)		—

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

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We use various derivative instruments to manage our exposure to commodity price risks. The derivatives provide us protection on the volumes if prices decline below the prices at which the derivatives are set. However, ceiling prices in our derivatives may cause us to receive less revenue on the volumes than we would receive in the absence of the derivatives.

A substantial portion of our oil and gas reserves are located in California and approximately 59% of our production is attributable to heavy crude (generally 21 degree API gravity crude oil or lower). 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.

Our heavy crude is primarily sold to ConocoPhillips 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 2007. We are currently receiving approximately 83% of the NYMEX index price for crude oil sold under the ConocoPhillips contract, representing approximately 54% of our total crude oil production.

Approximately 35% of our crude oil production is sold through Plains All American Pipeline, L.P. (“PAA”) with 50% sold under contracts that provide for NYMEX less a fixed price differential (currently averaging NYMEX less $3.48) and the remainder sold under contracts that provide for monthly field posted prices. These contracts expire at various times in 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.

Prices received for our gas are subject to seasonal variations and other fluctuations. Approximately 85% of our gas production is sold monthly based on industry recognized, published index pricing. The remainder is priced daily on the spot market. Fluctuations between the two pricing mechanisms can significantly impact the overall differential to the Henry Hub.

During 2005, 2004 and 2003 sales to PAA accounted for 38%, 33% and 70%, respectively, of our total revenues and during 2005 and 2004 sales to ConocoPhillips accounted for 44% and 33%, respectively, 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.

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.

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Productive Wells and Acreage

As of December 31, 2005 we had working interests in 3,160 gross (3,068 net) active producing oil wells and 354 gross (273 net) active producing gas wells. The following table sets forth information with respect to our developed and undeveloped acreage as of December 31, 2005:

	Developed Acres		Undeveloped Acres (1)
	Gross	Net	Gross	Net
California
Onshore	127,250	86,039	103,498	71,894
Offshore	41,588	34,328	125,330	21,503
Kansas	—	—	40,191	31,471
Louisiana
Onshore	10,541	4,826	38,073	35,216
Offshore	9,213	4,870	111,440	15,494
Oklahoma	3,429	197	—	—
Texas	17,938	16,562	15,453	11,031
Wyoming	—	—	38,175	29,268
Total	209,959	146,822	472,160	215,877

(1) Less than 10% of total net undeveloped acres are covered by leases that expire from 2006 through 2008.

Drilling Activities

Information with regard to our drilling activities during the years ended December 31, 2005, 2004 and 2003 is set forth below:

	Year Ended December 31,
	2005		2004		2003
	Gross	Net	Gross	Net	Gross	Net
Exploratory Wells
Oil	5.0	5.0	13.0	13.0	—	—
Gas	6.0	2.7	5.0	2.0	7.0	2.2
Dry	6.0	3.1	10.0	5.3	3.0	1.0
	17.0	10.8	28.0	20.3	10.0	3.2
Development Wells
Oil	217.0	216.4	65.0	64.2	121.0	121.0
Gas	30.0	12.0	52.0	22.4	32.0	14.0
Dry	3.0	3.0	1.0	1.0	1.0	0.4
	250.0	231.4	118.0	87.6	154.0	135.4
	267.0	242.2	146.0	107.9	164.0	138.6

At December 31, 2005 there were 25 development wells (24.7 net) and 4 exploratory well (1.8 net) in progress.

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Real Estate

We are in the process of pursuing surface development of portions of the following tracts of real property, portions of which are used in our oil and gas operations:

Property	Location	Approximate Acreage (Net to Our Interest)
Montebello	Los Angeles County, California	497
Arroyo Grande	San Luis Obispo County, California	1,080
Lompoc	Santa Barbara County, California	3,727

In January 2006 we entered into real estate consulting agreements with Cook Hill Properties, LLC. Under the terms of the agreements Cook Hill Properties will be responsible for creating a development plan and obtaining all necessary permits for real estate development in an environmentally responsible manner on the surface estates of our holdings at our Montebello property in Los Angeles County, our Lompoc property in Santa Barbara County and our Arroyo Grande property in San Luis Obispo County. Cook Hill Properties is a 15% participant in the venture and can earn an additional incentive on each property.

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 prospects and resources 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

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oil and gas industry and its individual participants. The failure to comply with these rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability. However, we do not believe that we are affected in a significantly different manner by these laws and regulations than are our competitors. Due to the myriad 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, the Research and Sanctuaries Act, the Endangered Species 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 City of La Habra Heights, California, the City of Commerce, California, the county of Kern, California, the county of Ventura, California, the city of Montebello, California, the city of Beverly Hills, 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 2006 cash expenditures related to plugging, abandonment and remediation will be approximately $5 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, $38 million ($78 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). The fair value of our obligation, $0.5 million, is included in Other Long-Term Liabilities in the Consolidated Balance Sheet.

Employees

As of January 31, 2006 we had 640 full-time employees, 322 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.

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Item 1A.    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 or debt securities.

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

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

• weather;

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

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

• the prices of foreign exports and the availability of alternate fuel sources;

• general economic conditions in the United States and worldwide; and

• governmental regulations.

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

• our revenues, cash flows, profitability and earnings;

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

• the amount that we are allowed to borrow; and

• the value of our oil and gas properties and our oil and gas reserve volumes.

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:

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

• the assumed effects of regulations by governmental agencies;

• assumptions concerning future oil and gas prices; and

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• assumptions concerning future operating costs, severance and excise taxes, development costs and workover and remedial costs.

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

• the quantities of oil and gas that are ultimately recovered;

• the timing of the recovery of oil and gas reserves;

• the production and operating costs incurred; and

• the amount and timing of future development expenditures.

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

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

• the amount and timing of actual production;

• supply and demand for oil and gas; and

• changes in governmental regulations or taxation.

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

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.

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

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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.

We intend to continue to enter into derivative contracts for a portion of our crude oil production, which may result in our making cash payments or prevent us from receiving the full benefit of increases in prices for oil and which may cause volatility in our reported earnings.

We use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of increases in oil prices above the maximum fixed amount specified in the derivative agreement. The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy.

For 2006, our crude oil derivative position consists exclusively of purchased put option contracts with a strike price of $55.00 on 50,000 barrels per day. The only cash settlements we are required to make on these contracts are option premiums, which are expected to total approximately $7.5 million per month. In return, to the extent the daily average NYMEX price for West Texas Intermediate crude oil is less than $55.00, we will receive the difference between $55.00 and the daily average NYMEX price for West Texas Intermediate crude oil.

Our crude oil derivative position also includes purchased put option contracts with a strike price of $55.00 on 50,000 barrels per day in 2007 and crude oil price collars on 22,000 barrels per day with a floor of $25.00 and an average ceiling of $34.76 in 2007 and 2008. In a typical collar transaction, we have the right to receive from the counterparty the excess of the floor price specified in the derivative agreement over a floating price based on a market index, multiplied by the specified quantity. If the floating price exceeds the floor price and is less than the ceiling price, no payment is required by either party. If the floating price exceeds the ceiling price, we must pay the counterparty this difference multiplied by the specified quantity. If we have less production than we have specified under the collars 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 derivative agreements expose us to risk of financial loss if the counterparty defaults on its contract obligations.

See Item 7A. Qualitative and Quantitative Disclosures About Market Risks for a summary of our current derivative positions. Since all of such derivative contracts are accounted for under mark-to-market accounting we expect continued volatility in our reported earnings due to gains and losses on these contracts as changes occur in the NYMEX price indexes.

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:

• hurricanes and other adverse weather conditions;

• oil field service costs and availability;

• compliance with environmental and other laws and regulations;

• remediation and other costs resulting from oil spill releases of hazardous materials and other environmental damages; and

• failure of equipment or facilities.

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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 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.

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:

• well blowouts;

• cratering;

• explosions;

• uncontrollable flows of oil, gas or well fluids;

• fires;

• pollution; and

• releases of toxic gas.

In addition, our operations in California are susceptible to damage from natural disasters such as earthquakes, mudslides and fires and our Gulf of Mexico operations are susceptible to hurricanes. 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.

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:

• inadequate capital or other factors, such as title problems;

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• weather;

• compliance with governmental regulations or price controls;

• mechanical difficulties; or

• shortages or delays in the delivery of equipment.

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

Furthermore, exploration for oil and gas, 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.

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.

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.

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.

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

Environmental liabilities could adversely affect our financial condition.

The oil and gas business is subject to environmental hazards, such as oil spills, gas leaks and ruptures and discharges of petroleum products and hazardous substances, and historic disposal activities. These environmental hazards could expose us to material liabilities for property damages, personal injuries or other environmental harm, including costs of investigating and remediating contaminated properties. 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:

• well drilling or workover, operation and abandonment;

• waste management;

• land reclamation;

• financial assurance under the Oil Pollution Act of 1990; and

• controlling air, water and waste emissions.

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

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

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

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

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

• diversion of management’s attention;

• the need to integrate acquired operations;

• potential loss of key employees of the acquired companies;

• difficulty in assuming recoverable reserves, future production rates, operating costs, infrastructure requirements, environmental and other liabilities, and other factors beyond our control;

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

• an increase in our expenses and working capital requirements.

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

Our net income could be negatively affected by stock based compensation charges.

Stock appreciation rights (SARs) are subject to variable accounting treatment under generally accepted accounting principles. We will adopt Statement of Financial Accounting Standards No. 123R, “Share-Based Payment” (SFAS 123R) effective January 1, 2006. SFAS 123R requires that the compensation cost relating to share-based payment transactions be recognized in financial statements based on the fair value of the equity or liability instruments issued. Under SFAS 123R our SARs will be remeasured to fair value each reporting period with changes in fair value reported in earnings. As a result, we expect volatility in our earnings as our stock price changes.

Prior to the adoption of SFAS 123R, we accounted for stock based compensation utilizing the intrinsic value method pursuant to APB 25. Accordingly, we have historically recognized compensation expense for our SARs based on changes in intrinsic value. The final expense recognized at settlement under either accounting method will equal the cash payment to settle the SAR. The adoption of SFAS 123R may cause additional volatility in reported earnings.

We recognized $39.9 million, $35.5 million and $18.0 million of SAR expense for the years ended December 31, 2005, 2004 and 2003, respectively.

In addition, we expect that certain of our restricted stock awards will become subject to variable accounting in 2006. Any awards that become subject to variable accounting will be accounted for in a similar manner to our existing SARs and will create additional volatility in our reported earnings.

We will adopt SFAS 123R effective January 1, 2006. We are completing our assessment of SFAS 123R and the effect it 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 transaction, over the fair value of the net assets acquired. At December 31, 2005 goodwill totaled $173.9 million and represented 6% of our total assets.

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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 1B.    Unresolved Staff Comments

Not applicable.

Item 3.    Legal Proceedings

On November 15, 2005, the United States Court of Federal Claims issued a ruling granting the plaintiffs’ motion for summary judgment as to liability and partial summary judgment as to damages in the breach of contract lawsuitAmber Resources Company et al. v. United States, Case No. 02-30c. The Court’s ruling also denied the United States’ motion to dismiss and motion for summary judgment. The United States Court of Federal Claims ruled that the federal government’s imposition of new and onerous requirements that stood as a significant obstacle to oil and gas development breached agreements that it made when it sold 36 federal leases offshore California. The Court further ruled that the Government must give back to the current lessees the more than $1.1 billion in lease bonuses it had received at the time of sale. The final ruling in the case will not be made until the Court addresses the plaintiffs’ additional claims regarding the hundreds of millions of dollars that have been spent in the successful efforts to find oil and gas in the disputed lease area, and other matters. The final ruling, including the rulings made on November 15, 2005 will be subject to appeal, and no payments will be made until all appeals have either been waived or exhausted. We are among the current lessees of the 36 leases. Our share of the $1.1 billion award is in excess of $80 million.

We are a defendant in various other 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.

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PART II

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

Price Range of Common stock

Our common stock is listed 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:

	High		Low
2005
1st Quarter	$	38.30	$	24.25
2nd Quarter		36.66		28.97
3rd Quarter		43.88		34.95
4th Quarter		45.68		35.93
2004
1st Quarter	$	18.64	$	14.87
2nd Quarter		20.53		17.19
3rd Quarter		23.86		18.58
4th Quarter		28.03		23.81

At December 31, 2005 we had approximately 1,502 shareholders of record.

Dividend Policy

We have not paid any cash dividends and 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, repurchase shares of our common stock 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 and Note 5 to the Consolidated Financial Statements, 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.

	Year Ended December 31,
	2005			2004 (1)			2003 (2)			2002			2001
	(In thousands of dollars, except per share amounts)
Revenues	$	944,420		$	671,706		$	304,090		$	188,563		$	204,139
Costs and Expenses
Production costs		285,292			223,080			104,819			78,451			63,795
General and administrative		127,513			85,197			43,158			15,186			10,210
Provision for legal and regulatory settlements		—			6,845			—			—			—
Depreciation, depletion, amortization and accretion		187,915			147,985			52,484			30,359			24,105
		600,720			463,107			200,461			123,996			98,110
Income from Operations		343,700			208,599			103,629			64,567			106,029
Other Income (Expense)
Interest expense		(55,421	)		(37,294	)		(23,778	)		(19,377	)		(17,411	)
Gain (loss) on mark-to-market derivative contracts (3)		(636,473	)		(150,314	)		847			—			—
Interest and other income (expense)		3,324			723			(159	)		174			463
Debt extinguishment costs		—			(19,691	)		—			—			—
Expenses of terminated public equity offering		—			—			—			(2,395	)		—
Income (Loss) Before Income Taxes and Cumulative Effect of Accounting Change		(344,870	)		2,023			80,539			42,969			89,081
Income tax (expense) benefit
Current		229			(375	)		(1,224	)		(6,353	)		(6,014	)
Deferred		130,629			7,192			(32,228	)		(10,379	)		(28,374	)
Income (Loss) Before Cumulative Effect of Accounting Changes		(214,012	)		8,840			47,087			26,237			54,693
Cumulative effect of accounting change, net of tax (expense)/benefit (4)		—			—			12,324			—			(1,522	)
Net Income (Loss)	$	(214,012	)	$	8,840		$	59,411		$	26,237		$	53,171
Earnings (Loss) Per Share
Basic and Diluted
Income (loss) before cumulative effect of accounting change	$	(2.75	)	$	0.14		$	1.41		$	1.08		$	2.26
Cumulative effect of accounting change		—			—			0.37			—			(0.06	)
Net income (loss)	$	(2.75	)	$	0.14		$	1.78		$	1.08		$	2.20
Weighted Average Common Shares Outstanding
Basic		77,726			63,542			33,321			24,193			24,200
Diluted		77,726			64,014			33,469			24,201			24,200

(1) Reflects acquisition of Nuevo effective May 14, 2004.

(2) Reflects acquisition of 3TEC effective June 1, 2003.

(3) We do not use hedge accounting for certain of our derivative instruments, because the derivatives do not qualify or we have elected not to use hedge accounting. Consequently, these derivative contracts are marked-to-market each quarter with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts on the income statement. Cash flow is only impacted to the extent the actual settlements under the contracts result in making or receiving a payment from the counterparty.

As a result of the increase in oil prices, we recognized losses related to mark-to-market derivative contracts of $636.5 million and $150.3 million in 2005 and 2004, respectively. Cash payments related to these contracts that settled totaled $425.4 million and $32.2 million for 2005 and 2004, respectively. The 2005 cash payment amount includes the $145.4 million paid in connection with the elimination of our 2006 oil collars.

(4) Cumulative effect of adopting Statement of Financial Accounting Standards No. 143— “Accounting for Asset Retirement Obligations,” or SFAS 143 in 2003 and Statement of Financial Accounting Standards No. 133—“Accounting for Derivatives,” or SFAS 133 in 2001.

Table continued on following page

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	Year Ended December 31,
	2005			2004			2003			2002			2001
	(In thousands of dollars)
Cash Flow Data
Net cash provided by operating activities	$	463,334		$	363,219		$	118,278		$	78,826		$	116,808
Net cash (used in) provided by investing activities		(168,420	)		5,414			(368,710	)		(64,158	)		(125,880	)
Net cash provided by (used in) financing activities		(294,907	)		(368,465	)		250,781			(13,653	)		8,549
	As of December 31,
	2005			2004			2003			2002			2001
	(In thousands of dollars)
Balance Sheet Data
Assets
Cash and cash equivalents	$	1,552		$	1,545		$	1,377		$	1,028		$	13
Other current assets		291,780			256,622			87,104			47,854			42,798
Property and equipment, net		2,235,303			2,171,089			956,895			493,212			455,117
Goodwill		173,858			170,467			147,251			—			—
Other assets		39,449			33,522			19,641			18,929			18,827
	$	2,741,942		$	2,633,245		$	1,212,268		$	561,023		$	516,755
Liabilities and Stockholders’ Equity
Current liabilities	$	363,998		$	426,395		$	155,086		$	86,175		$	50,648
Long-term debt and payable to Plains Resources		797,375			635,468			487,906			233,166			236,183
Other long-term liabilities		603,422			381,524			65,429			6,303			1,413
Deferred income taxes		258,810			319,483			149,591			61,559			48,424
Stockholders’ equity/combined owner’s equity
Accumulated other comprehensive income (loss)		(89,566	)		(123,874	)		(40,439	)		(12,858	)		15,884
Other		807,903			994,249			394,695			186,678			164,203
	$	2,741,942		$	2,633,245		$	1,212,268		$	561,023		$	516,755

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

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

Company Overview

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 six states with principal operations in:

• the Los Angeles and San Joaquin Basins onshore California;

• the Santa Maria Basin offshore California;

• the Gulf Coast Basin onshore and offshore Louisiana, including the Gulf of Mexico; and

• the Val Verde portion of the greater Permian Basin in Texas.

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. Our primary sources of liquidity are cash generated from our operations and our revolving credit facility. At December 31, 2005 we had approximately $471 million of availability under our revolving credit facility. We have a capital budget for 2006, excluding acquisitions, of $430 million. We believe that we have sufficient liquidity through our cash from operations and borrowing capacity under our revolving credit facility to meet our short-term and long-term normal recurring operating needs, derivative obligations, debt service obligations, contingencies, anticipated capital expenditures and expenditures under our stock repurchase program. In addition, the majority of our capital expenditures and expenditures under our stock repurchase program are discretionary and could be curtailed if our cash flows declined from expected levels.

Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of increases in oil or gas prices above the maximum fixed amount specified in the derivative agreement. The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy (see “—Derivative Instruments and Hedging”).

Acquisitions and Dispositions

In April 2005 we acquired certain California producing oil and gas properties from a private company for $117 million. The properties are primarily located in the Los Angeles Basin of onshore California with some smaller properties located in adjacent Ventura County. The transaction was financed under our credit facility.

In September 2005 we acquired an additional 16.7% interest in the Point Arguello Unit, Rocky Point development project and related facilities, offshore California, from subsidiaries of Chevron U.S.A. Inc. This acquisition increased our working interest to 69.3%.

In May 2004 we acquired Nuevo in a stock-for-stock transaction. We accounted for the acquisition of Nuevo as a purchase effective May 14, 2004. See Items 1 and 2. Business and Properties—Acquisitions—Nuevo Energy Company.

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In June 2003, we acquired 3TEC for a combination of cash and common stock. We accounted for the acquisition of 3TEC as a purchase effective June 1, 2003. See Items 1 and 2. Business and Properties—Acquisitions—3TEC Energy Corporation.

We periodically evaluate and from time to time have elected 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.

In May 2005 we closed the sale to XTO Energy, Inc. of interests in producing properties located in East Texas and Oklahoma for net proceeds of approximately $341 million. The proceeds were primarily used to fund the transactions to eliminate all of our 2006 oil price swaps and collars as discussed in “—Derivative Instruments and Hedging”.

In December 2004, we completed the sale of certain properties located offshore California and onshore south Texas, New Mexico and south Louisiana. These divestments were conducted via negotiated and auction transactions and we received net proceeds of approximately $153 million. In a series of unrelated 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.

Derivative Instruments and Hedging

In May 2005 we completed a series of transactions that eliminated our 2006 collars on 22,000 barrels of oil per day with a floor price of $25.00 and an average ceiling price of $34.76 and our 2006 swaps on 15,000 barrels of oil per day with an average price of $25.28 at a pre-tax cost of approximately $292.7 million (approximately $145.4 million attributable to the collars and $147.3 million attributable to the swaps).

The collars were not accounted for as hedges, therefore, the $145.4 million loss in the fair value of these instruments was currently recognized in our income statement and there will be no income statement effect subsequent to March 31, 2005. We used hedge accounting for the swaps through March 2005 and as a result the $145.8 million loss in fair value attributable to the swaps has been deferred in Other Comprehensive Income (OCI) and will be recognized as a noncash reduction to oil revenues in 2006 when the hedged production is sold. The $145.4 million cash payment for the collars is reflected as a financing cash outflow in our statement of cash flows and the $147.3 million cash payment for the swaps is reflected as an operating cash outflow in our statement of cash flows. These payments reduced derivative liabilities on our balance sheet.

For 2006, our crude oil derivative position consists exclusively of purchased put option contracts with a strike price of $55.00. The only cash settlements we are required to make on these contracts are option premiums, which are expected to total approximately $7.5 million per month. In return, to the extent the daily average NYMEX price for West Texas Intermediate crude oil is less than $55.00, we will receive the difference between $55.00 and the daily average NYMEX price for West Texas Intermediate crude oil.

In addition to the 2006 put options, our crude oil hedge position includes additional put options in 2007 and collar positions in 2007 and 2008. In 2006 we also have call options on 30,000 MMBtu per day of natural gas. See Item 7A. Qualitative and Quantitative Disclosures About Market Risks for a summary of our current derivative positions. As all of such derivative contracts are accounted for under mark-to-market accounting we expect continued volatility in our reported earnings due to gains and losses on these contracts as changes occur in the NYMEX price index.

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General

We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration, exploitation and development activities are capitalized. Our revenues are derived from the sale of oil, gas and natural gas liquids. We recognize revenues when our production is sold and title is transferred. Our revenues are highly dependent upon the prices of, and demand for, oil 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 and our levels of production are subject to wide fluctuations and depend on numerous factors beyond our control, including supply and demand, economic conditions, foreign imports, the actions of OPEC, political conditions in other oil-producing countries, and governmental regulation, legislation and policies. Under the SEC’s full cost accounting rules, we review the carrying value of our proved oil and gas properties each quarter. These rules generally require that we price our future oil and gas production at the oil and gas prices in effect at the end of each fiscal quarter to determine a ceiling value of our properties. The rules require a write-down if our capitalized costs exceed the allowed “ceiling.” We have had no write-downs due to these ceiling test limitations since 1998. Given the volatility of oil and gas prices, it is likely that our estimate of discounted future net revenues from proved oil and gas reserves will fluctuate in the near term. If oil and gas prices decline significantly in the future, write-downs of our oil and gas properties could occur. Write-downs required by these rules do not directly impact our cash flows from operating activities. Decreases in oil and gas prices have had, and will likely have in the future, an adverse effect on the carrying value of our estimated proved reserves, our reserve volumes and our revenues, profitability and cash flow.

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

General and administrative expenses (“G&A”) consist primarily of salaries and related benefits of administrative personnel, office rent, systems costs and other administrative costs.

Results Overview

Our results include the effect of our 2004 acquisition of Nuevo, which is included with effect from May 14, 2004, and our 2003 acquisition of 3TEC, which is included with effect from June 1, 2003.

In 2005, primarily as a result of a $636.5 million derivative mark-to-market loss, we reported a net loss of $214.0 million, or $2.75 per share compared to net income of $8.8 million, or $0.14 per diluted share for 2004. Cash payments related to mark-to-market derivative contracts totaled $425.4 million for 2005, including the $145.4 million cash payment to eliminate our 2006 collars.

In 2004, primarily as a result of a $150.3 million derivative mark-to-market loss, we reported net income of $8.8 million, or $0.14 per diluted share compared to net income of $59.4 million, or $1.78 per diluted share for 2003. Cash payments related to mark-to-market derivative contracts totaled $32.2 million for 2004. Net income for 2003 includes a non-cash, after-tax $12.3 million credit related to the adoption of SFAS 143.

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Results of Operations

The following table reflects the components of our oil and gas production and sales prices and sets forth our operating revenues and costs and expenses on a BOE basis:

	Year Ended December 31,
	2005		2004		2003
Sales Volumes
Oil and liquids (MBbls)		18,671		16,441		9,267
Gas (MMcf)		29,359		38,590		18,195
MBOE		23,564		22,872		12,300
Daily Average Sales Volumes
Oil and liquids (Bbls/d)		51,154		44,920		25,389
Gas (Mcfpd)		80,435		105,436		49,849
BOEPD		64,560		62,493		33,697
Unit Economics (in dollars)
Average NYMEX Prices
Oil	$	56.61	$	41.43	$	30.99
Gas		8.62		6.14		5.39
Average Realized Sales Price Before Derivative Transactions
Oil (per Bbl)	$	46.76	$	36.12	$	26.92
Gas (per Mcf)		7.15		5.90		5.01
Per BOE		45.96		35.92		27.69
Costs and Expenses per BOE
Production costs
Lease operating expenses	$	5.97	$	5.36	$	5.44
Steam gas costs		3.32		1.77		0.23
Electricity		1.35		1.32		1.82
Production and ad valorem taxes		1.03		0.98		0.82
Gathering and transportation		0.43		0.33		0.21
DD&A per BOE (oil and gas properties)		7.39		5.93		3.86

The following table reflects cash receipts (payments) made with respect to derivative contracts that settled during the periods presented (in thousands):

	Year Ended December 31,
	2005			2004			2003
Contracts accounted for using hedge accounting
Oil revenues	$	(53,044	)	$	(207,414	)	$	(50,875	)
Gas revenues		(6,255	)		(17,504	)		240
Steam gas costs		10,293			3,649			—
Mark-to-market contracts		(279,982	)		(32,187	)		—

Comparison of Year Ended December 31, 2005 to Year Ended December 31, 2004

Oil and gas revenues.    Oil and gas revenues increased $271.4 million, to $940.8 million for 2005 from $669.4 million for 2004. The increase is primarily due to increased production volumes attributable to the properties acquired in the Nuevo acquisition and higher realized prices.

Oil revenues excluding the effects of hedging, increased $279.3 million to $873.1 million for 2005 from $593.8 million for 2004 reflecting higher realized prices ($175.0 million) and higher production ($104.3 million). Our average realized price for oil increased $10.64 to $46.76 per Bbl for 2005 from $36.12 per Bbl for 2004. The increase is primarily attributable to an improvement in the NYMEX oil

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price, which averaged $56.61 per Bbl in 2005 versus $41.43 per Bbl in 2004. Oil production increased to 18.7 MMBbls in 2005 from 16.4 MMBbls in 2004, primarily due to production attributable to the properties acquired in the Nuevo acquisition that were in our results for the full year 2005.

Hedging had the effect of decreasing our oil revenues by $139.1 million, or $7.45 per Bbl in 2005 compared to $145.8 million or $8.87 per Bbl in 2004. The 2005 amount includes $106.2 million of deferred losses related to 2005 swaps that were terminated in 2004. These losses were deferred in OCI until the production that was originally hedged was produced and delivered during 2005.

Gas revenues excluding the effects of hedging, decreased $17.7 million to $209.8 million in 2005 from $227.5 million in 2004 due to decreased production volumes ($66.0 million) partially offset by higher realized prices ($48.3 million). Our average realized price for gas was $7.15 per Mcf for 2005 compared to $5.90 per Mcf for 2004. Gas production decreased from 38.6 Bcf in 2004 to 29.4 Bcf in 2005 primarily due to the sale of our properties in East Texas and Oklahoma in the second quarter of 2005 and shut-in production due to hurricanes Katrina and Rita.

Hedging had the effect of decreasing our 2005 gas revenues by $3.1 million, or $0.10 per Mcf, and decreased our 2004 gas revenues by $6.1 million, or $0.16 per Mcf.

Lease operating expenses.    Lease operating expenses (including steam gas costs and electricity) increased $57.5 million, to $250.7 million for 2005 from $193.2 million for 2004. On a per unit basis, lease operating expenses increased to $10.64 per BOE in 2005 versus $8.45 per BOE in 2004. The per unit increase is primarily attributable to the steam gas costs attributable to the properties acquired in the Nuevo acquisition and higher lease operating expenses due to workover activity, increased field costs and lost volumes associated with shut-in production from Gulf of Mexico hurricanes.

Production and ad valorem taxes.    Production and ad valorem taxes increased $2.2 million, to $24.5 million for 2005 from $22.3 million for 2004 primarily due to the properties acquired in the Nuevo acquisition and increased oil and gas prices.

Gathering and transportation expenses.    Gathering and transportation expenses increased $2.5 million, to $10.1 million for 2005 from $7.6 million for 2004 primarily due to the properties acquired in the Nuevo acquisition.

General and administrative expense.    Our G&A expense consists of (in thousands of dollars):

	Year Ended December 31,
	2005		2004
G&A excluding items below	$	50,321	$	41,641
Stock appreciation rights		39,856		35,464
Other stock-based compensation		37,336		8,092
	$	127,513	$	85,197

G&A expense, excluding amounts attributable to SARs and other stock based compensation, was $50.3 million in 2005 compared to $41.6 million in 2004. G&A expense for 2004 includes $6.2 million of merger related costs associated with the Nuevo acquisition. Excluding such items, G&A expense increased from $35.5 million in 2004 to $50.3 million in 2005, primarily reflecting increased costs resulting from the Nuevo acquisition and higher employee headcount and related compensation costs.

G&A expense related to SARs was $39.9 million in 2005 compared to $35.5 million in 2004. Accounting for SARs requires that we record an expense or credit for vested or deemed vested SARs

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depending on whether, during the period, our stock price either rose or fell, respectively. Such expense in 2005 and 2004 reflects additional vesting of outstanding SARs as well as an increase in our stock price. Our stock price was $39.73 per share on December 31, 2005 versus $26.00 per share on December 31, 2004 and $15.39 per share on December 31, 2003. In 2005 and 2004 we made cash payments of $22.5 million and $15.1 million, respectively, for SARs that were exercised during the period.

G&A expense for 2005 and 2004 includes other stock based compensation costs of $37.3 million and $8.1 million, respectively, related to restricted stock and restricted stock unit grants. Other stock based compensation costs for 2005 includes approximately $19 million related to restricted stock units that vested based on the performance of our common stock.

G&A expense does not include amounts capitalized as part of our acquisition, exploration and development activities. We capitalized $24.5 million and $16.2 million of G&A expense in 2005 and 2004, respectively.

Provision for legal and regulatory settlements.    In 2004 we made a $6.8 million provision with respect to legal and regulatory matters, primarily related to leasehold ownership and operations and permit compliance matters.

Depreciation, depletion and amortization, or DD&A.    DD&A expense increased $40.9 million, to $180.3 million in 2005 from $139.4 million in 2004. Approximately $38.4 million of the increase was attributable to our oil and gas DD&A due to a higher per unit rate and higher production. Our oil and gas unit of production rate increased to $7.39 per BOE in 2005 compared to $5.93 per BOE in 2004. The increase primarily reflects the effect of property acquisitions, higher future development costs and 2005 capital costs for which there were no immediate reserve additions.

Interest expense.    Interest expense increased $18.1 million, to $55.4 million for 2005 from $37.3 million for 2004 primarily due to higher outstanding debt as a result of the Nuevo acquisition and 2005 property acquisitions. Interest expense does not include interest capitalized on oil and gas properties not subject to amortization. We capitalized $3.5 million and $7.0 million of interest in 2005 and 2004, respectively.

Gain (loss) on mark-to-market derivative contracts.    We do not use hedge accounting for certain of our derivative instruments, because the derivatives do not qualify or we have elected not to use hedge accounting. Consequently, these derivative contracts are marked-to-market each quarter with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts on the income statement. Cash flow is only impacted to the extent the actual settlements under the contracts result in making or receiving a payment from the counterparty.

As a result of the significant increase in oil prices, we recognized a $636.5 million loss related to mark-to-market derivative contracts in 2005. Cash payments related to these contracts that settled in 2005 totaled $425.4 million, including $145.4 million we paid in connection with the elimination of our 2006 oil collars during this period. In 2004 we recognized a loss on mark-to-market derivative contracts of $150.3 million. Cash payments related to these contracts that settled in 2004 totaled $32.2 million.

Debt extinguishment costs.    In connection with the retirement of the debt assumed in the acquisition of Nuevo, in 2004 we recorded $19.7 million of debt extinguishment costs.

Income tax expense.    Our 2005 income tax expense was a benefit of $130.9 million, reflecting an annual effective tax rate of 38%. Variances in our annual effective tax rate from the 35% federal

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statutory rate are caused by state income taxes, Enhanced Oil Recovery (EOR) credits and permanent differences primarily reflecting expenses that are not deductible because of IRS limitations. Our 2005 income tax expense includes a charge of $3.3 million to deferred income tax expense to reflect an increase in the estimated California apportionment factor as a result of the sale of the Company’s properties in East Texas and Oklahoma and the purchase of California.

In 2004 our income tax expense was a benefit of $6.8 million that included a $9.5 million deferred benefit related to EOR credits and a $2.8 million deferred benefit related to state income taxes as a result of the restructuring of certain subsidiaries. These benefits were partially offset by approximately $4.0 million of expenses that are not deductible because of IRS limitations. Our 2004 income tax expense included $0.7 million of state income taxes (net of federal benefit).

EOR credits are a credit against federal and state income taxes for certain costs related to extracting high-cost oil, utilizing certain prescribed “enhanced” (tertiary) recovery methods. EOR credits are subject to phase-out according to the level of average domestic crude prices. No phase-out occurred in 2005. However, as a result of the increase in oil prices in 2005, based on current rules, the Company will not earn EOR credits in 2006.

Comparison of Year Ended December 31, 2004 to Year Ended December 31, 2003

Oil and gas revenues.    Oil and gas revenues increased $366.2 million, to $669.4 million for 2004 from $303.2 million for 2003. The increase is primarily due to increased production volumes attributable to the properties acquired from Nuevo and 3TEC and higher realized prices. Our average realized price per BOE increased to $35.92 and our production increased to 22.9 MMBOE. Production attributable to the properties acquired from Nuevo was 9.6 MMBOE in 2004.

Oil revenues excluding the effect of hedging, increased $344.3 million, to $593.8 million for 2004 from $249.5 million for 2003, reflecting higher realized prices ($85.2 million) and higher production ($259.1 million). Our average realized price for oil increased $9.20, to $36.12 per Bbl for 2004 from $26.92 per Bbl for 2003. The increase is primarily attributable to an improvement in the NYMEX oil price, which averaged $41.43 per Bbl in 2004 versus $30.99 per Bbl in 2003.

Hedging had the effect of decreasing our oil revenues by $145.8 million in 2004 compared to $51.4 million in 2003. Oil production increased to 16.4 MMBbls in 2004 from 9.3 MMBbls in 2003. Production attributable to the properties acquired from Nuevo was 8.4 MMBbls in 2004.

Gas revenues excluding the effect of hedging, increased $136.2 million, to $227.5 million in 2004 from $91.3 million in 2003. A 20.4 Bcf increase in production volumes, primarily from the properties acquired from Nuevo and 3TEC, accounted for a $120.2 million increase in gas revenues. Our average realized price for gas increased $0.89, to $5.90 per Mcf for 2004 from $5.01 per Mcf for 2003 increasing revenues by $16.0 million. In 2004 hedging decreased our gas revenues by $6.1 million while in 2003 hedging increased our gas revenues by $13.8 million.

Lease operating expenses.    Lease operating expenses (including steam gas costs and electricity) increased $101.1 million, to $193.2 million for 2004 from $92.1 million for 2003, primarily due to the properties acquired from Nuevo which accounted for $98.7 million of the 2004 operating expenses. On a per unit basis, lease operating expenses increased to $8.45 per BOE in 2004 versus $7.49 per BOE in 2003. The per unit increase is primarily attributable to the steam gas costs attributable to the properties acquired from Nuevo. Steam gas costs averaged $1.77 per BOE in 2004 versus $0.23 per BOE in 2003.

Production and ad valorem taxes.    Production and ad valorem taxes increased $12.2 million, to $22.3 million for 2004 from $10.1 million for 2003 primarily due to the properties acquired from Nuevo and 3TEC and increased oil prices.

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Gathering and transportation expenses.    Gathering and transportation expenses increased $5.0 million, to $7.6 million for 2004 from $2.6 million for 2003 primarily due to the properties acquired from Nuevo and 3TEC.

General and administrative expense.    Our G&A expense consists of (in thousands of dollars):

	Year Ended December 31,
	2004		2003
G&A excluding items below	$	41,641	$	23,958
Stock appreciation rights		35,464		18,010
Other stock-based compensation		8,092		1,190
	$	85,197	$	43,158

G&A expense, excluding amounts attributable to SARs and other stock based compensation, increased from $24.0 million in 2003 to $41.6 million in 2004. G&A expense for 2004 includes $6.2 million of merger related costs associated with the Nuevo acquisition and 2003 includes $5.3 million of such expenses related to the 3TEC acquisition. Merger related expenses primarily consist of severance and other compensation costs and accounting system integration and conversion expenses. Excluding such items, G&A expense increased from $18.7 million in 2003 to $35.4 million in 2004, primarily reflecting increased audit costs, costs of compliance with the Sarbanes-Oxley Act and increased costs resulting from the Nuevo and 3TEC acquisitions.

G&A expense related to outstanding stock appreciation rights or SARs was $35.5 million and $18.0 million in 2004 and 2003, respectively. Accounting for SARs requires that we record an expense or credit for vested or deemed vested SARs depending on whether, during the period, our stock price either rose or fell, respectively. Such expense in 2004 and 2003 reflects additional vesting of outstanding SARs as well as an increase in our stock price. Our stock price was $26.00 per share on December 31, 2004, $15.39 per share on December 31, 2003 and $9.75 per share on December 31, 2002. In 2004 and 2003 we made cash payments of $15.1 million and $2.1 million, respectively, for SARs that were exercised during the period.

G&A expense for 2004 and 2003 includes other stock based compensation costs of $8.1 million and $1.2 million, respectively, related to restricted stock and restricted stock unit grants.

G&A expense does not include amounts capitalized as part of our acquisition, exploration and development activities. We capitalized $16.2 million and $11.0 million of G&A expense in 2004 and 2003, respectively.

Provision for legal and regulatory settlements.    In 2004 we made a $6.8 million provision with respect to legal and regulatory matters, primarily related to leasehold ownership and operations and permit compliance matters.

Depreciation, depletion and amortization, or DD&A.    DD&A expense increased $89.6 million, to $139.4 million in 2004 from $49.8 million in 2003. Approximately $88.0 million of the increase was attributable to our oil and gas DD&A due to a higher per unit rate and higher production. Our oil and gas unit of production rate increased to $5.93 per BOE in 2004 compared to $3.86 per BOE in 2003. The increase primarily reflects the effect of the Nuevo acquisition.

Accretion expense.    Accretion expense increased $6.0 million to $8.6 million in 2004 from $2.6 million in 2003. The increase is primarily attributable to the increase in asset retirement obligations related to the Nuevo acquisition.

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Interest expense.    Interest expense increased $13.5 million, to $37.3 million for 2004 from $23.8 million for 2003 primarily due to higher outstanding debt as a result of the Nuevo and 3TEC acquisitions. Interest expense does not include interest capitalized on oil and gas properties not subject to amortization. We capitalized $7.0 million and $3.2 million of interest in 2004 and 2003, respectively.

Debt extinguishment costs.    In connection with the retirement of the debt assumed in the acquisition of Nuevo we recorded $19.7 million of debt extinguishment costs.

Gain (loss) on mark-to-market derivative contracts.    We do not use hedge accounting for certain of our derivative instruments, because the derivatives do not qualify or we have elected not to use hedge accounting. Consequently, these derivative contracts are marked-to-market each quarter with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts on the income statement. Cash flow is only impacted to the extent the actual settlements under the contracts result in making or receiving a payment from the counterparty.

During 2004 we recognized a pre-tax loss of $150.3 million from derivatives that do not qualify for hedge accounting consisting of a mark-to-market loss of $118.1 million and cash settlements of $32.2 million. We recognized a mark-to-market gain of $0.9 million in 2003.

Income tax expense.    Income tax expense for 2004 was a benefit of $6.8 million compared to an expense of $33.5 million for 2003. The decrease in income tax expense primarily reflects: (i) the reduction of pre-tax income from $80.5 million in 2003 to $2.0 million in 2004; (ii) a $9.5 million deferred benefit related to EOR credits in 2004; and (iii) a $2.8 million deferred benefit in 2004 related to the restructuring of certain subsidiaries with respect to the payment of state income taxes.

Current income tax expense for 2004 was $0.4 million compared to $1.2 million in 2003. A $2.9 million benefit related to provision-to-return adjustments for 2003 income tax returns (which is offset by a $2.9 million deferred tax expense) was offset by the federal and state impacts of reduced deductions as required by EOR credit rules, an increase in the alternative minimum tax and increased state income taxes on our operating subsidiary that is required to file a stand-alone income tax return in the states of Louisiana and Texas. Our current effective rate was 18.5% for 2004 compared to 2% for 2003.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from our operations and our revolving credit facility. At December 31, 2005 we had approximately $471 million of availability under our revolving credit facility. We believe that we have sufficient liquidity through our cash from operations and borrowing capacity under our revolving credit facility to meet our short-term and long-term normal recurring operating needs, derivative obligations, debt service obligations, expenditures under our stock repurchase program, contingencies and anticipated capital expenditures.

Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of increases in oil or gas prices above the maximum fixed amount specified in the derivative agreement. The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy. In addition, the majority of our capital expenditures and expenditures under our stock repurchase program are discretionary and could be curtailed if our cash flows declined from expected levels.

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At December 31, 2005 we had a working capital deficit of approximately $71 million. Approximately $64 million of the working capital deficit is attributable to the fair value of our commodity derivative instruments (net of related deferred income taxes). In accordance with SFAS 133, the fair value of all derivative instruments is recorded on the balance sheet. Our hedge agreements provide for monthly settlement based on the difference between the fixed price in the contract and the actual NYMEX oil price. Cash received for the sale of physical production will be based on actual market prices and, if necessary, will be available to meet derivative settlement obligations. None of our derivative contracts have margin requirements or collateral provisions that could require funding prior to the scheduled cash settlement date. The seven financial institutions that are contract counterparties for our derivative commodity contracts all have Standard & Poor’s ratings of A or better and all seven of the financial institutions are participating lenders in our revolving credit facility. At December 31, 2005 we were in a net liability position with all such counterparties.

Financing Activities

Senior Revolving Credit Facility.    On May 16, 2005, we entered into an Amended and Restated Credit Agreement (the “Amended Credit Agreement”) which established the facility size at $750 million. The borrowing base is redetermined on a semi-annual basis, with PXP and the lenders each having the right to one annual interim unscheduled redetermination, and may be adjusted based on PXP’s oil and gas properties, reserves, other indebtedness and other relevant factors. Our borrowing base was redetermined in November 2005 and is currently $1.2 billion. At this time we have not elected to seek an increase in the size of our credit facility. Additionally, the Amended Credit Agreement contains a $75 million sub-limit for letters of credit. The Amended Credit Agreement matures on May 16, 2010. Collateral consists of 100% of the shares of stock of all our domestic subsidiaries and mortgages covering at least 80% of the total present value of our domestic oil and gas properties.

The Amended Credit Agreement contains negative covenants that limit our ability, as well as the ability of our restricted subsidiaries, among other things, to incur additional debt, pay dividends on stock, make distributions of cash or property, change the nature of our business or operations, redeem stock or redeem subordinated debt, make investments, create liens, enter into leases, sell assets, sell capital stock of subsidiaries, guarantee other indebtedness, enter into agreements that restrict dividends from subsidiaries, enter into certain types of swap agreements, enter into gas imbalance or take-or-pay arrangements, merge or consolidate and enter into transactions with affiliates. In addition, we are required to maintain a current ratio, which includes availability under the Amended Credit Agreement, of at least 1.0 to 1.0 and a ratio of debt to EBITDAX (as defined) of no greater than 4.25 to 1.00.

The effective interest rate on our borrowings under the Amended Credit Agreement was 5.4% at December 31, 2005. At that date we were in compliance with the covenants contained in the Amended Credit Agreement and could have borrowed the full amount available under the Amended Credit Agreement.

7.125% Senior Notes.    On December 31, 2005 we had $250.0 million principal amount of ten year senior unsecured notes due 2014 (the “7.125% Notes”) outstanding. The 7.125% Notes were issued at 99.478% and bear interest at 7.125% with a yield to maturity of 7.2%. During the period from June 15, 2009 to June 14, 2012, we may redeem all or part of the 7.125% Notes at our option, at rates varying from 103.563% to 101.188% of the principal amount and at 100% of the principal amount thereafter. In addition, before June 15, 2009, we may redeem all or part of the 7.125% Notes at the make-whole price set forth under the indenture. At any time prior to June 15, 2007, we may redeem up to 35% of the 7.125% Notes with the net cash proceeds of certain equity offerings at the redemption price set forth under the indenture. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the 7.125% Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase.

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The 7.125% Notes are our unsecured general obligations and are jointly and severally guaranteed on a full, unconditional basis by all of our existing and future domestic restricted subsidiaries.

8.75% Senior Subordinated Notes.    At December 31, 2005, we had $275.0 million principal amount of 8.75% Senior Subordinated Notes due 2012 (the “8.75% Notes”) outstanding. The 8.75% Notes are not redeemable until July 1, 2007. During the period from July 1, 2007 to June 30, 2010 they are redeemable, at our option, at rates varying from 104.375% to 101.458% of the principal amount and at 100% of the principal amount thereafter. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the 8.75% Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase.

The 8.75% Notes are our unsecured general obligations, are subordinated in right of payment to all of our existing and future senior indebtedness and are jointly and severally guaranteed on a full, unconditional basis by all of our existing and future domestic restricted subsidiaries.

The indentures governing the 8.75% Notes and the 7.125% Notes contain covenants that limit our ability, as well as the ability of our subsidiaries, among other things, to incur additional indebtedness, make certain investments, pay dividends, or make other distributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness, sell assets, incur dividends or other payment restrictions affecting subsidiaries, enter into transactions with affiliates, create liens, merge, consolidate and transfer assets and enter into different lines of business.

Short-term Credit Facility.    In May 2005 we amended our uncommitted short-term credit facility to extend its term and increase the facility size. We may make borrowings from time to time until May 27, 2006, not to exceed at any time the maximum principal amount of $25.0 million. No advance under the short-term facility may have a term exceeding fourteen days and all amounts outstanding are due and payable no later than May 27, 2006. Each advance under the short-term facility shall bear interest at a rate per annum mutually agreed on by the bank and the Company. No amounts were outstanding under the short-term credit facility at December 31, 2005.

Shelf Registration.    We have filed with the Securities and Exchange Commission a universal shelf registration statement, which became effective May 2, 2005, that allows us to issue up to $500 million of debt and/or equity securities. The prices and terms of the debt and/or equity securities will be determined at the time of the sale.

Cash Flows

	Year Ended December 31,
	2005			2004			2003
	(in millions)
Cash provided by (used in):
Operating activities	$	463.3		$	363.2		$	118.3
Investing activities		(168.4	)		5.4			(368.7	)
Financing activities		(294.9	)		(368.4	)		250.8

Net cash provided by operating activities was $463.3 million in 2005, $363.2 million in 2004 and $118.3 million in 2003. The 2005 amount was reduced by the $147.3 million payment to eliminate all of our 2006 oil price swaps as discussed in “Company Overview—Hedge Restructuring.” The increases in net cash provided by operating activities in 2005 and 2004 are primarily a result of increased oil and gas prices and sales volumes. As discussed below, certain of our derivative cash payments are classified as a financing activity.

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Net cash used in investing activities was $168.4 million in 2005 primarily reflecting additions to oil and gas properties of $509.1 million partially offset by property sales proceeds of $346.5 million. Net cash provided by investing activities was $5.4 million in 2004. The net cash inflow in 2004 was primarily a result of property sales proceeds of $239.0 million net of additions to oil and gas properties of $211.4 million. Net cash used in investing activities was $368.7 million in 2003 primarily reflecting additions to oil and gas properties of $122.1 million and $267.5 million for the acquisition of 3TEC.

Net cash used in financing activities in 2005 was $294.9 million, primarily reflecting $162.0 million in net borrowings under our credit facility and the payment of $459.5 million in financing derivative settlements. Under SFAS 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”, certain of our derivatives are deemed to contain a significant financing element and cash settlements with respect to such derivatives are required to be reflected as financing activities. Accordingly, in 2005 derivative cash settlements totaling $459.5 million, including the $145.4 million payment to eliminate all of our 2006 price collars, were classified as financing activities. Net cash used in financing activities in 2004 was $368.4 million. During 2004 borrowings under our credit facility decreased $101.0 million and we received $248.7 million in proceeds from the issuance of our 7.125% Senior Notes. These proceeds and funds generated by our operations were used to retire $405.0 million in debt assumed in the Nuevo acquisition and to pay $9.3 million in debt financing costs and $103.5 million in derivative settlements. Net cash provided by financing activities in 2003 was $250.8 million. Cash receipts in 2003 included net borrowings of $175.2 million under our credit facility and $80.1 million in proceeds received from the issuance of our 8.75% notes. Cash outflows in 2003 included payments for debt issuance costs ($4.3 million); principal payments on long-term debt ($0.5 million); and repurchases of treasury stock ($0.1 million).

Capital Requirements

We have made and will continue to make substantial capital expenditures for the acquisition, exploitation, development, exploration and production of oil and gas. We have a capital budget for 2006, excluding acquisitions, of approximately $430 million. We believe that we have sufficient liquidity through our cash from operations and borrowing capacity under our revolving credit facility to meet our short-term and long-term normal recurring operating needs, derivative obligations, debt service obligations, expenditures under our stock repurchase program,, contingencies and anticipated capital expenditures. In addition, the majority of our capital expenditures and expenditures under our stock repurchase program are discretionary and could be curtailed if our cash flows declined from expected levels.

Stock Repurchase Program

Our Board of Directors has authorized the repurchase of up to $500 million of our common stock. The shares will be repurchased from time to time in open market transactions or privately negotiated transactions at our discretion, subject to market conditions and other factors. We expect that the funds for these purchases will come primarily from cash flow in excess of capital investments.

Stock Appreciation Rights

Accounting for SARs requires that we record an expense or credit for vested or deemed vested SARs depending on whether, during the period, our stock price either rose or fell, respectively. Our stock price was $39.73 per share on December 31, 2005 versus $26.00 per share on December 31, 2004 and we recognized $39.9 million of expense in 2005. We incur cash expenditures upon the exercise of SARs, but our common shares outstanding do not increase. At December 31, 2005 we had approximately 2.6 million SARs outstanding of which 1.5 million were vested. If all of the vested SARs were exercised, based on $39.73, the price of our common stock as of December 31, 2005, we would pay $46.4 million to holders of the SARs. In 2005 we made cash payments of $22.5 million for SARs that were exercised during that period.

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Commitments and Contingencies

Contractual obligations.    At December 31, 2005, the aggregate amounts of contractually obligated payment commitments for the next five years are as follows (in thousands):

	2006		2007 and 2008		2009 and 2010		Thereafter
Operating leases	$	3,828	$	6,392	$	4,383	$	5,568
Producing property remediation		600		600		600		300
Commodity derivative contracts		134,030		101,625		—		—
Long-term debt		—		—		272,000		525,000
Interest on debt		58,139		116,286		106,145		97,695
Other		—		5,365		827		822
	$	196,597	$	230,268	$	383,955	$	629,385

Operating leases relate primarily to obligations associated with our office facilities and certain cogeneration operations in California. The obligation for commodity derivative contracts represents the cost to purchase certain crude oil put options and natural gas call options that will be paid when such options are settled and amounts payable in 2006 related to contracts that matured in 2005. The obligation for producing property remediation consists of obligations associated with the purchase of certain of our California properties.

The long-term debt and interest payments amounts consist of amounts due under our credit facility, 7.125% Notes and 8.75% Notes and interest payments to maturity. The principal amount under our credit facility varies based on our cash inflows and outflows and the amounts reflected in this table assume the principal amount outstanding at December 31, 2005 remains outstanding to maturity with interest and commitment fees calculated at the rates in effect at that date.

Our liabilities also include:

• Asset retirement obligations ($5.1 million current and $155.9 million long-term) that represent the estimated fair value at December 31, 2005 of our obligations with respect to the retirement/abandonment of our oil and gas properties. Each reporting period the liability is accreted to its then present value. The ultimate settlement amount and the timing of the settlement of such obligations is unknown because they are subject to, among other things, federal, state and local regulation and economic factors. See Note 4 to the Consolidated Financial Statements.

• Commodity derivative contracts ($290.5 million) that represent net liabilities for oil and gas commodity derivatives based on their estimated fair value at December 31, 2005. The ultimate settlement amounts of such contracts are unknown because they are subject to continuing market risk. See “Critical Accounting Policies and Factors that May Affect Future Results—Commodity pricing and riskmanagement activities” and Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” for additional information regarding our derivative obligations.

• Stock appreciation rights ($55.2 million current and $2.0 million long-term) that represent the net liability for the deemed vested portion of SARs. The liability at December 31, 2005 is calculated based on our closing stock price at that date. The ultimate settlement amount of such liability is unknown because settlements are based on the market price of our common stock at the time the SARs are exercised. See “Critical Accounting Policies and Factors that May Affect Future Results—Stock appreciation rights”.

Environmental matters.    As discussed under “Business & Properties—Regulation—Environmental,” as an owner or lessee and operator of oil and gas properties, we are subject to various federal, state, and local laws and regulations relating to discharge of materials into, and protection of,

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the environment. Typically when producing oil and gas assets are purchased, one assumes the obligation to plug and abandon wells that are part of such assets. However, in some instances, we have received an indemnity in connection with such purchase. There can be no assurance that we will be able to collect on these indemnities. Often these regulations are more burdensome on older properties that were operated before the regulations came into effect such as some of our properties in California that have operated for over 90 years. We have established policies for continuing compliance with environmental laws and regulations. We also maintain insurance coverage for environmental matters, which we believe is customary in the industry, but we are not fully insured against all environmental risks. There can be no assurance that current or future local, state or federal rules and regulations will not require us to spend material amounts to comply with such rules and regulations.

In January 2005 we discovered and self-reported a violation related to flared gas emissions in excess of permitted levels on properties acquired in the Nuevo acquisition. Estimated excess emissions from the San Joaquin Valley casing vent recovery system located on the Gamble Lease were approximately 881 tons over a 745 day period. We brought the facility into compliance within 10 days of discovering the violation. We settled this matter in 2005 for $750,000.

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 the purchaser assumes the obligation to plug and abandon wells that are part of such assets. However, in some instances, we received an indemnity with respect to those costs. We cannot assure you that we will be able to collect on these indemnities.

We estimate our 2006 cash expenditures related to plugging, abandonment and remediation will be approximately $5 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, $38 million ($78 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). The fair value of our obligation, $0.5 million, is included in Other Long-Term Liabilities in the Consolidated Balance Sheet.

For a further discussion of our obligations to incur plugging, abandonment and remediation costs, see “Items 1 and 2. Business and Properties—Plugging, Abandonment and Remediation Obligations”.

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

Operating risks and insurance coverage.    Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and gas, including well blowouts, cratering,

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explosions, oil spills, releases of gas or well fluids, fires, pollution and releases of toxic gas, each of which could result in damage to or destruction of oil and gas wells, production facilities or other property, or injury to persons. Our operations in California, including transportation of oil by pipelines within the city and county of Los Angeles, are especially susceptible to damage from earthquakes and involve increased risks of personal injury, property damage and marketing interruptions because of the population density of southern California. Although we maintain insurance coverage considered to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of high premium costs. We maintain coverage for earthquake damages in California but this coverage may not provide for the full effect of damages that could occur and we may be subject to additional liabilities. The occurrence of a significant event that is not fully insured against could have a material adverse effect on our financial position. Our insurance does not cover every potential risk associated with operating our pipelines, including the potential loss of significant revenues. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences.

Sale of Nuevo’s Congo operations.    Upon our acquisition of Nuevo, we became a party to an existing agreement between Nuevo, CMS NOMECO Oil & Gas Co. (CMS) and a third party. Under the agreement, Nuevo and CMS may be liable to the third party for the recapture of dual consolidated losses (DCLs) in connection with each company’s 1995 acquisition of Congolese properties. Nuevo and CMS agreed to indemnify each other for any act that would cause the third party to experience a liability from the recapture of DCLs as a result of a triggering event.

CMS sold its interest in the Congolese properties to a subsidiary of Perenco, S.A. (Perenco) in 2002. Both CMS and Perenco, have received from the Internal Revenue Service (IRS), in accordance with the U.S. consolidated return regulations, a closing agreement confirming that the transaction will not trigger recapture. We and Perenco have finalized closing agreements with the IRS confirming that neither our merger with Nuevo, nor the sale of our interest in the Congolese properties to Perenco will trigger recapture. The estimated remaining contingent liabilities are $15.2 million relative to Nuevo’s former interest, and $21.4 million relative to CMS’ former interest, for which we would be jointly liable. We believe the occurrence of a triggering event in the future is remote and we do not believe the agreements will have a material adverse affect upon us.

Industry Concentration

Financial instruments which potentially subject us to concentrations of credit risk consist principally of accounts receivable with respect to our oil and gas operations and derivative instruments related to our hedging activities. During 2005, 2004 and 2003 sales to PAA accounted for 38%, 33% and 70%, respectively, of our total revenues and during 2005 and 2004 sales to ConocoPhillips accounted for 44% and 33%, respectively, 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.

The seven financial institutions that are contract counterparties for our derivative commodity contracts all have Standard & Poor’s ratings of A or better and all seven of the financial institutions are participating lenders in our revolving credit facility. At December 31, 2005 we were in a net liability position with all such counterparties.

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There are a limited number of alternative 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 which could have a negative impact on future results of operations or cash flows.

Critical Accounting Policies and Factors that May Affect Future Results

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

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

Periodically, we enter into derivative arrangements relating to a portion of our oil and gas production to achieve a more predictable cash flow, as well as to reduce our exposure to adverse price fluctuations. Derivative instruments used are typically fixed price swaps and collars and purchased puts and calls. While the use of these types of instruments limits our downside risk to adverse price movements, we are subject to a number of risks, including instances in which the benefit to revenues and cash flows is limited when commodity prices increase.

We do not use hedge accounting for certain of our derivative instruments, because the derivatives do not qualify or we have elected not to use hedge accounting. These derivative contracts are marked-to-market each quarter with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts on the income statement. Consequently, we expect continued volatility in our reported earnings as changes occur in the NYMEX indexes. Cash flow is only impacted to the extent the actual settlements under the contracts result in making or receiving a payment from the counterparty.

The estimation of fair values of derivative instruments requires substantial judgment. We estimate the fair values of our derivatives using an option-pricing model. The option-pricing model utilizes various factors including NYMEX and over-the-counter price quotations, volatility and the time value of options. The estimated future prices are compared to the prices fixed by the agreements and the resulting estimated future cash inflows (outflows) over the lives of the derivative instruments are discounted using rates under our revolving credit facility. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts, regional price differentials and interest rates.

For a further discussion concerning our risks related to oil and gas prices and our hedging programs, see “Item 7A—Quantitative and Qualitative Disclosures about Market Risks”.

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

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

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

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

Oil and gas reserves.    Our proved reserve information is based on estimates prepared by outside engineering firms. Estimates prepared by others may be higher or lower than these estimates.

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

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

A large portion of our reserve base (approximately 89% at December 31, 2005) is comprised of oil properties that are sensitive to oil price volatility. Historically, we have experienced significant upward and downward revisions to our reserves volumes and values as a result of changes in year-end oil and gas prices and the corresponding adjustment to the projected economic life of such properties. Prices for oil and gas are likely to continue to be volatile, resulting in future downward and upward revisions to our reserve base.

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

Stock based compensation.    SARs are subject to variable accounting treatment under generally accepted accounting principles. We will adopt SFAS 123R effective January 1, 2006. SFAS 123R requires that the compensation cost relating to share-based payment transactions be recognized in financial statements based on the fair value of the equity or liability instruments issued. Under SFAS 123R our SARs will be remeasured to fair value each reporting period with changes in fair value reported in earnings. As a result, we expect volatility in our earnings as our stock price changes.

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Prior to the adoption of SFAS 123R, we accounted for stock based compensation utilizing the intrinsic value method pursuant to APB 25. Accordingly, we have historically recognized compensation expense for our SARs based on changes in intrinsic value. The final expense recognized at settlement under either accounting method will equal the cash payment to settle the SAR. The adoption of SFAS 123R may cause additional volatility in reported earnings.

We recognized $39.9 million, $35.5 million and $18.0 million of SAR expense for the years ended December 31, 2005, 2004 and 2003, respectively.

In addition, we expect that certain of our restricted stock awards will become subject to variable accounting in 2006. Any awards that become subject to variable accounting will be accounted for in a similar manner to our existing SARs and will create additional volatility in our reported earnings.

We will adopt SFAS 123R effective January 1, 2006. We are completing our assessment of SFAS 123R and the effect it will have on our financial statements.

Goodwill.    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. At December 31, 2005 goodwill totaled $173.9 million and represented approximately 6% of our total assets.

We account for goodwill in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets”. Goodwill is not amortized, it is tested at least annually for impairment at a level of reporting referred to as a reporting unit. Impairment is the condition that exists when the carrying amount of goodwill exceeds its implied fair value. A two-step impairment test is used to identify potential goodwill impairment and measure the amount of a goodwill impairment loss to be recognized (if any). The first step of the goodwill impairment test, used to identify potential impairment, compares the fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered not impaired, thus the second step of the impairment test is unnecessary.

The second step of the goodwill impairment test, used to measure the amount of impairment loss, compares the implied fair value of reporting unit goodwill with the carrying amount of that goodwill. If the carrying amount of reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess. The loss recognized cannot exceed the carrying amount of goodwill.

We follow the full cost method of accounting and all of our operations are located in the United States. We have determined that for the purpose of performing an impairment test in accordance with SFAS No. 142, the Company is the reporting unit. SFAS 142 states that quoted market prices in active markets are the best evidence of fair value and shall be used as the basis for the measurement, if available. Accordingly, we use the quoted market price of our common stock to determine the fair value of our reporting unit.

An impairment of goodwill 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 estimated reserve volumes which would result in a decline in the fair value of our reporting unit.

Recent Accounting Pronouncements

SFAS 123R.    In December 2004 the FASB issued SFAS No. 123R that requires that the compensation cost relating to share-based payment transactions be recognized in financial

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statements. That cost will be measured based on the fair value of the equity or liability instruments issued. SFAS 123R covers a wide range of share-based compensation arrangements including stock options, restricted stock plans, performance-based awards, stock appreciation rights, and employee stock purchase plans. SFAS 123R replaces SFAS 123 and supersedes APB 25. Public entities (other than those filing as small business issuers) were originally required to apply SFAS 123R as of the first interim or annual reporting period that begins after June 15, 2005. On April 14, 2005 the SEC announced the adoption of a new rule that amends the compliance dates for SFAS 123R. The Commission’s new rule allows registrants to implement SFAS 123R at the beginning of their next fiscal year.

We will adopt SFAS 123R effective January 1, 2006 using the “modified prospective approach” as allowed under SFAS 123R. Under this approach, the valuation of equity instruments (i.e., restricted stock and restricted stock units) granted prior to the adoption of 123R will not be affected, however, the valuation of liability instruments (i.e., SARs) granted prior to the adoption of 123R will be revalued under a fair value approach instead of the previously applied intrinsic valuation. In addition, SFAS 123R requires us to begin estimating expected future forfeitures under each stock compensation plan. We are completing our assessment of SFAS 123R and the effect it will have on our financial statements.

FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations”.    In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). FIN 47 clarifies the definition and treatment of conditional asset retirement obligations as discussed in SFAS 143. A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the company. FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. FIN 47 is intended to provide more information about long-lived assets and future cash outflows for these obligations and more consistent recognition of these liabilities. Our financial position, results of operations or cash flows were not impacted by the implementation of FIN 47.

SFAS No. 154, “Accounting Changes and Error Corrections”.    In June 2005 the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections” (SFAS 154), which changes the requirements for the accounting for and reporting of a change in accounting principle by requiring voluntary changes in accounting principles to be reported using retrospective application, unless impracticable to do so. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. Application is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. Early adoption is permitted. We will adopt SFAS 154 on January 1, 2006 and we do not believe that our financial position, results of operations or cash flows will be impacted.

EITF 04-13 “Accounting for Purchases and Sales of Inventory with the Same Counterparty”. Steam generators utilized in our thermal recovery operations in California are fueled by natural gas. In certain instances we have entered into buy/sell contracts that allow us to exchange gas we produce elsewhere for gas delivered to our thermal recovery operations. We did not enter into buy/sell contracts in periods prior to our acquisition of Nuevo Energy Company in May 2004.

In September 2005 in Issue No. 04-13, the EITF reached a consensus that two or more inventory transactions with the same counterparty should be viewed as a single nonmonetary if the transactions were entered into in contemplation of one another (as determined in accordance with Issue No. 04-13).

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We have determined that transactions under certain of our buy/sell contracts should be presented net in accordance with Issue No. 04-13. We will apply Issue No. 04-13 effective January 1, 2006 and, accordingly, certain costs included in operating costs in 2005 and 2004 will be included as a reduction of revenues in 2006 and subsequent periods. Our financial position, results of operations or cash flows will not be impacted by the implementation of Issue No. 04-13.

Item 7A.    Qualitative and Quantitative Disclosures About Market Risks

Commodity Price Risk

We use various derivative instruments to manage our exposure to commodity price risk on sales of oil and gas production. All derivative instruments are recorded on the balance sheet at fair value. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value, both realized and unrealized, are recognized currently in our income statement as gain (loss) on mark-to-market derivative contracts. Cash flow is only impacted to the extent the actual settlements under the contracts result in making or receiving a payment from the counterparty. If a derivative is designated as a cash flow hedge and qualifies for hedge accounting, any unrealized gain or loss is deferred in accumulated OCI, a component of Stockholders’ Equity, until the hedged oil and gas production is sold. Realized gains and losses on derivative instruments that are designated as a hedge and qualify for hedge accounting are generally included in oil and gas revenues in the period the hedged volumes are sold. Gains and losses deferred in OCI related to cash flow hedges for which hedge accounting has been discontinued remain in OCI until the related product has been delivered.

In May 2005 we completed a series of transactions that eliminated our 2006 collars on 22,000 barrels of oil per day with a floor price of $25.00 and an average ceiling price of $34.76 and our 2006 swaps on 15,000 barrels of oil per day at an average price of $25.28 at a pre-tax cost of approximately $292.7 million (approximately $145.4 million attributable to the collars and $147.3 million attributable to the swaps).

The collars were not accounted for as hedges, therefore, the $145.4 million loss in the fair value of these instruments was currently recognized in our income statement and there will be no income statement effect subsequent to March 31, 2005. We used hedge accounting for the swaps through March 2005 and as a result the $145.8 million loss in fair value attributable to the swaps has been deferred in OCI and will be recognized as a noncash reduction to oil revenues in 2006 when the hedged production is sold. These payments reduced derivative liabilities on our balance sheet.

In 2005 we entered into a series of transactions that resulted in us now holding NYMEX put options with a strike price of $55.00 per barrel on 50,000 barrels of oil per day in 2006 and 2007. These put options cost an average of $4.91 per barrel for 2006 and $5.57 per barrel for 2007, which will be paid when the options are settled. We have elected not to use hedge accounting for the puts, consequently, the puts are marked-to-market with fair value gains and losses recognized as a gain or loss on mark-to-market derivative contracts on the income statement.

We purchase natural gas that is utilized in our steam flood operations. In October 2005 we acquired NYMEX call options with a strike price of $12.00 per MMBtu on 30,000 MMBtu of natural gas per day in 2006. These call options cost an average of $1.04 per MMBtu, which will be paid when the options are settled. We have elected not to use hedge accounting for the calls, consequently, the calls will be marked-to-market with fair value gains and losses recognized as a gain or loss on mark-to-market derivative contracts on the income statement.

See Note 3 to the Consolidated Financial Statements—“Derivative Instruments and Hedging Activities” for a complete discussion of our hedging activities.

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At December 31, 2005 we had the following open commodity derivative positions, none of which were designated as hedging instruments:

Period	Instrument Type	Daily Volumes	Average Price	Index
Sales of Crude Oil Production
2006
Jan-Dec	Put options	50,000 Bbls	$55.00 Strike price	WTI
2007
Jan-Dec	Collar	22,000 Bbls	$25.00 Floor-$34.76 Ceiling	WTI
Jan-Dec	Put options	50,000 Bbls	$55.00 Strike price	WTI
2008
Jan-Dec	Collar	22,000 Bbls	$25.00 Floor-$34.76 Ceiling	WTI
Purchases of Natural Gas
2006
Jan-Dec	Call options	30,000 MMBtu	$12.00 Strike price	Socal

The average price for the put options and call options do not reflect the cost to purchase such options.

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

	December 31,
	2005						2004
	Fair Value			Effect of 10% Price Increase			Fair Value			Effect of 10% Price Increase
Derivatives designated as cash flow hedges	$	—		$	—		$	(111.8	)	$	(29.6	)
Derivatives not designated as hedging instruments		(290.5	)		(141.0	)		(283.0	)		(113.8	)

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

We have NYMEX put options with a strike price of $55.00 per barrel on 50,000 barrels of oil per day in 2006 and 2007. These put options cost an average of $4.91 per barrel for 2006 and $5.57 per barrel for 2007 (a total of $191 million), which will be paid when the options are settled. We also have NYMEX call options with a strike price of $12.00 per MMBtu on 30,000 MMBtu of natural gas per day in 2006. These call options cost an average of $1.04 per MMBtu (a total of $11 million), which will be paid when the options are settled. Such amounts is not included in the fair value of derivatives not designated as hedging instruments in the foregoing table.

The seven financial institutions that are contract counterparties for our derivative commodity contracts all have Standard & Poor’s ratings of A or better and all seven of the financial institutions are participating lenders in our revolving credit facility. At December 31, 2005 we were in a net liability position with all such counterparties.

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Our management intends to continue to maintain derivative arrangements for a portion of our production. These contracts may expose us to the risk of financial loss in certain circumstances. Our derivative arrangements provide us protection on the volumes if prices decline below the prices at which these derivatives are set, but ceiling prices in our derivatives may cause us to receive less revenues on the volumes than we would receive in the absence of derivatives.

Price differentials.    Our realized wellhead oil and gas prices are lower than the NYMEX index level as a result of area and quality differentials. See Items 1 and 2. Business and Properties—Product Markets and Major Customers.

Approximately 85% of our gas production is sold monthly off of industry recognized, published index pricing and the remainder is priced daily on the spot market. Fluctuations between the two pricing mechanisms can significantly impact the overall differential to the Henry Hub.

Interest Rate Risk

We use both fixed and variable rate debt and are exposed to market risk due to the floating interest rates on our credit facilities. Our 7.125% Notes and 8.75% Notes are fixed rate notes and are not subject to market risk. Our senior revolving credit facility and our short-term credit facility have variable rates. At December 31, 2005 $272 million was outstanding under our senior revolving credit facility at an effective interest rate of 5.4%. No amounts were outstanding under our short-term credit facility at December 31, 2005.

Based on the $272 million outstanding under our senior revolving credit facility at December 31, 2005, on an annualized basis a 1% change in the effective interest rate would result in a $2.7 million change in our interest costs.

The following table reflects the carrying amounts and fair values of our fixed and variable rate debt (in millions):

	December 31, 2005
	Carrying Amount		Fair Value
Long-Term Debt
Senior revolving credit facility	$	272.0	$	272.0
7.125% Notes		248.8		258.8
8.75% Notes		276.5		296.3

The carrying value of our senior revolving credit facility approximates its fair value, as interest rates are variable, based on prevailing market rates. The fair values of the 7.125% Notes and 8.75% Notes are based on quoted market prices based on trades of such debt.

Item 8.    Financial Statements and Supplementary Data

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

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

Not Applicable.

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Item 9A.    Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer (our principal executive officer) and our Chief Financial Officer (our principal financial officer), we evaluated the effectiveness of our disclosure controls and procedures (as defined under Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on this evaluation, our Chief Executive Officer and our Chief Financial Officer believe that the disclosure controls and procedures as of December 31, 2005 were effective to ensure that information we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and implemented by the Company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2005. Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

Changes in Internal Controls

There were no changes in our internal control over financial reporting during the quarter ended December 31, 2005 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.    Other Information

Not Applicable

54

PART III

Item 10.    Directors and Executive Officers of the Registrant

Information regarding our directors and executive officers will be included in an amendment to this Form 10-K or in the proxy statement for the 2006 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2005, and is incorporated by reference to this report.

Directors and Executive Officers of Plains Exploration & Production Company

Listed below are our directors and executive officers, their age as of January 31, 2006 and their business experience for the last five years.

Directors

James C. Flores, age 46, 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 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 70, 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, BMC Technologies Inc., the Texas Medical Center, Greater Houston Area Red Cross 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 and has been a director of Geotrace since May 2005. 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 65, 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.

55

Robert L. Gerry III, age 68, 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 67, 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.

Executive Officers

James C. Flores, age 46, 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 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.

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.

Stephen A. Thorington, age 50, 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 44, 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.

Item 11.    Executive Compensation

Information regarding executive compensation will be included in an amendment to this Form 10-K or in the proxy statement for the 2006 annual meeting of stockholders and is incorporated by reference to this report.

56

Item 12.    Security Ownership of Certain Beneficial Owners and Management

Information regarding beneficial ownership will be included in an amendment to this Form 10-K or in the proxy statement for the 2006 annual meeting of stockholders and is incorporated by reference to this report.

Item 13.    Certain Relationships and Related Transactions

Information regarding certain relationships and related transactions will be included in an amendment to this Form 10-K or in the proxy statement for the 2006 annual meeting of stockholders and is incorporated by reference to this report.

Item 14.    Principal Accountant Fees and Services

Information regarding principal accountant fees and services will be included in an amendment to this Form 10-K or in the proxy statement for the 2006 annual meeting of stockholders and is incorporated by reference to this report.

57

PART IV

Item 15.    Exhibits, Financial Statement Schedules

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

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

(a) (3) Exhibits

Exhibit Number	Description
3.1	Certificate of Incorporation of Plains Exploration & Production Company (incorporated by reference to Exhibit 3.1 to the Company’s Amendment No. 2 to Registration Statement on Form S-1 (file no. 333-90974) filed on October 3, 2002 (the “Amendment No. 2 to Form S-1”)).
3.2	Certificate of Amendment to the Certificate of Incorporation of Plains Exploration & Production Company dated May 14, 2004 (incorporated by reference to Exhibit 3.1 to the Company’s Form 10-Q for the period ending June 30, 2004 (the “June 30, 2004 10-Q”)).
3.3	Bylaws of Plains Exploration & Production Company (incorporated by reference to Exhibit 3.2 to the Amendment No. 2 to Form S-1).
4.1	Amended and Restated Indenture, dated as of June 18, 2004, among Plains Exploration & Production Company, Plains E&P Company, the Subsidiary Guarantor Parties Thereto, and J.P. Morgan Chase Bank, as Trustee (including form of 8 3/4% Senior Subordinated Note) (incorporated by reference to Exhibit 4.1 to the June 30, 2004 10-Q).
4.2	First Amendment to Amended and Restated Indenture dated as of June 18, 2004, among PXP, the Subsidiary Guarantors, and JP Morgan Chase Bank, National Association as Trustee, dated as of December 1, 2005 (incorporated by reference to Exhibit 4.01 to the Company’s Current Report on Form 8-K filed December 6, 2005).
4.3	Second Supplemental Indenture to Amended and Restated Indenture dated as of June 18, 2004, dated as of June 30, 2004, among Plains Exploration & Production Company, Plains E&P Company, the Subsidiary Guarantor Parties Thereto, and J.P. Morgan Chase Bank, as Trustee (incorporated by reference to Exhibit 4.2 to the June 30, 2004 10-Q).
4.4	Third Supplemental Indenture to Amended and Restated Indenture dated as of June 18, 2004, dated as of December 30, 2004, among Plains Exploration & Production Company, the Subsidiary Guarantor Parties thereto, Plains Louisiana Inc., PXP Louisiana L.L.C. and J.P. Morgan Chase Bank, as Trustee (incorporated by reference to Exhibit 4.3 to the Company’s Form 10-K for the year ended December 31, 2004 (the “2004 10-K”)).
4.5	Fourth Supplemental Indenture to Amended and Restated Indenture dated as of June 18, 2004, dated as of June 30, 2005, among Plains Exploration & Production Company, the Subsidiary Guarantor Parties thereto and J.P. Morgan Chase Bank, as Trustee (incorporated by reference to Exhibit 4.1 to the Company’s Form 10-Q for the period ending June 30, 2005 (the “June 30, 2005 10-Q”).
4.6	Indenture dated as of June 30, 2004, among Plains Exploration & Production Company, the Subsidiary Guarantor Parties thereto, and Wells Fargo Bank, N.A., as Trustee (including form of 7 1/8% Senior Note) (incorporated by reference to Exhibit 4.1 to the Company’s Form S-4 (file no. 333-118350) filed on August 18, 2004 (the “August 2004 S-4”)).

58

Exhibit Number	Description
4.7	First Supplemental Indenture to Indenture dated as of June 30, 2004, dated as of December 30, 2004, among Plains Exploration & Production Company, Plains Louisiana Inc., PXP Louisiana L.L.C., and Wells Fargo Bank, N.A., as Trustee (incorporated by reference to Exhibit 4.5 to the 2004 10-K).
4.8	Second Supplemental Indenture to Indenture dated as of June 30, 2004, dated as of June 30, 2005, among Plains Exploration & Production Company, the Subsidiary Guarantor Parties thereto, and Wells Fargo Bank, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the June 30, 2005 10-Q).
4.9	First Amendment to Indenture dated as of June 30, 2004, among PXP, the Subsidiary Guarantors and Wells Fargo Bank, N.A. as Trustee, dated as of December 1, 2005 (incorporated by reference to Exhibit 4.02 to the Company’s Current Report on Form 8-K filed December 6, 2005).
4.10	Amended and Restated Credit Agreement dated as of May 16, 2005, among Plains Exploration & Production Company, as borrower, each of the lenders that is a signatory thereto, and J.P. Morgan Chase Bank as administrative agent (incorporated by reference to Exhibit 10.1 to the June 30, 2005 10-Q).
4.11	First Amendment to Amended and Restated Credit Agreement, dated as of November 1, 2005, among Plains Exploration & Production Company, the Guarantors, JPMorgan Chase Bank, N.A. as administrative agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed November 15, 2005).
10.1	Purchase and Sale Agreement made and entered into on March 31, 2005, by and among PXP Texas Limited Partnership, PXP Gulf Coast Inc., and PXP Louisiana LLC, and XTO Energy Inc., (incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q for the period ending March 31, 2005 (the “March 31, 2005 10-Q”).
10.2	Purchase and Sale Agreement dated as of March 11, 2005, by and between Bentley-Simonson, Inc., and Plains Exploration & Production Company, ((incorporated by reference to Exhibit 10.2 to the March 31, 2005 10-Q).
10.3*	Consulting Agreement, dated as of January 19, 2006, between Montebello Land Company LLC and Cook Hill Properties LLC
10.4*	Consulting Agreement, dated as of January 19, 2006, between Lompoc Land Company LLC and Cook Hill Properties LLC.
10.5*	Consulting Agreement, dated as of January 19, 2006, between Arroyo Grande Land Company LLC and Cook Hill Properties LLC.
10.6	Crude Oil Marketing Agreement, dated as of July 15, 2004, among Plains Exploration & Production Company, Arguello, Inc., PXP Gulf Coast Inc., and Plains Marketing, L.P. (incorporated by reference to Exhibit 10.7 to the 2004 10-K).
10.7	First Amendment to Crude Oil Marketing Agreement, dated as of October 19, 2004, among Plains Exploration & Production Company, Arguello, Inc., PXP Gulf Coast Inc., and Plains Marketing, L.P (incorporated by reference to Exhibit 10.2 to the September 30, 2004 10-Q).
10.8	Crude Oil Purchase Agreement dated February 4, 2000 between Plains Exploration & Production Company (as successor to Nuevo Energy Company) and ConocoPhillips (as successor to Tosco Corporation) (incorporated by reference to Exhibit 10.1 to Nuevo Energy Company’s Current Report on Form 8-K filed February 23, 2000).

59

Exhibit Number	Description
10.9	Plains Exploration & Production Company 2002 Stock Incentive Plan (incorporated by reference to Exhibit 10.21 to the Amendment No. 1 to Form 10).
10.10	Form of Plains Restricted Stock Agreement under the 2002 Incentive Plan (incorporated by reference to Exhibit 10.19 to the Company’s 2002 Form 10-K).
10.11	Form of Plains Stock Appreciation Rights Agreement under the 2002 Incentive Plan (incorporated by reference to Exhibit 10.18 to the Company’s 2002 Form 10-K).
10.12	Form of Restricted Stock Unit Agreement under the 2002 Incentive Plan (incorporated by reference to Exhibit 10.33 to the Company’s 2002 Form 10-K).
10.13	First Amendment to the Plains Exploration & Production Company 2002 Stock Incentive Plan (incorporated by reference to Exhibit 10.32 to the Company’s Amendment No. 1 to Form S-4 (file no. 333-103149) filed on March 27, 2003).
10.14	Plains Exploration & Production Company 2004 Stock Incentive Plan (incorporated by reference to Annex D to the Company’s Amendment No. 1 to Form S-4 (file no. 333-113536) filed on April 12, 2004).
10.15*	Form of Restricted Stock Unit Agreement under the 2004 Incentive Plan.
10.16*	Amended and Restated Executives’ Long-Term Retention and Deferred Compensation effective as of February 10, 2006.
10.17	Long-Term Retention and Deferral Agreement for James C. Flores (incorporated by reference to Exhibit 10.3 to the June 30, 2005 10-Q).
10.18	Long-Term Retention and Deferral Agreement for Executive Vice Presidents (incorporated by reference to Exhibit 10.4 to the June 30, 2005 10-Q).
10.19*	First Amendment to Long-Term Retention and Deferral Agreement for James C. Flores.
10.20*	First Amendment to Long-Term Retention and Deferral Agreement for Executive Vice Presidents.
10.21	Employment Agreement, dated as of June 9, 2004, between Plains Exploration & Production Company and James C. Flores (incorporated by reference to Exhibit 10.20 to the 2004 10-K).
10.22	Employment Agreement, dated as of June 9, 2004, between Plains Exploration & Production Company and Stephen A. Thorington (incorporated by reference to Exhibit 10.21 to the 2004 10-K).
10.23	Employment Agreement, dated as of June 9, 2004, between Plains Exploration & Production Company and John F. Wombwell (incorporated by reference to Exhibit 10.22 to the 2004 10-K).
10.24	Employment Agreement dated as of June 9, 2004, between Plains Exploration & Production Company and Thomas M. Gladney (incorporated by reference to Exhibit 10.23 to the 2004 10-K).
10.25*	First Amendment to Employment Agreement, dated as of February 10, 2006, between Plains Exploration & Production Company and James C. Flores.
10.26*	First Amendment to Employment Agreement, dated as of February 10, 2006, between Plains Exploration & Production Company and Stephen A. Thorington.

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Exhibit Number	Description
10.27*	First Amendment to Employment Agreement, dated as of February 10, 2006, between Plains Exploration & Production Company and John F. Wombwell.
10.28*	First Amendment to Employment Agreement, dated as of February 10, 2006, between Plains Exploration & Production Company and Thomas M. Gladney.
10.29	Form of Election for Director Deferral of Restricted Stock Awards (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed January 4, 2005).
21.1*	List of Subsidiaries of Plains Exploration & Production Company.
23.1*	Consent of PricewaterhouseCoopers LLP.
23.2*	Consent of Netherland, Sewell & Associates, Inc.
23.3*	Consent of Ryder Scott Company.
31.1*	Rule 13(a)-14(a)/15d-14(a) Certificate of the Chief Executive Officer.
31.2*	Rule 13(a)-14(a)/15d-14(a) Certificate of the Chief Financial Officer.
32.1**	Section 1350 Certificate of the Chief Executive Officer.
32.2**	Section 1350 Certificate of the Chief Financial Officer.

* Filed herewith.

** Furnished herewith.

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SIGNATURES

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

	PLAINS EXPLORATION & PRODUCTION COMPANY
Date: March 9, 2006		/s/    JAMES C. FLORES
		James C. Flores, Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date: March 9, 2006	/s/    JAMES C. FLORES
	James C. Flores, Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer)
Date: March 9, 2006	/s/    ISAAC ARNOLD, JR.
	Isaac Arnold, Jr., Director
Date: March 9, 2006	/s/    ALAN R. BUCKWALTER, III
	Alan R. Buckwalter, III, Director
Date: March 9, 2006	/s/    JERRY L. DEES
	Jerry L. Dees, Director
Date: March 9, 2006	/s/    TOM H. DELIMITROS
	Tom H. Delimitros, Director
Date: March 9, 2006	/s/    ROBERT L. GERRY, III
	Robert L. Gerry, III, Director
Date: March 9, 2006	/s/    JOHN H. LOLLAR
	John H. Lollar, Director
Date: March 9, 2006	/s/    STEPHEN A. THORINGTON
	Stephen A. Thorington, Executive Vice President and Chief Financial Officer (Principal Financial Officer)
Date: March 9, 2006	/s/    CYNTHIA A. FEEBACK
	Cynthia A. Feeback, Vice President / Controller and Chief Accounting Officer (Principal Accounting Officer)

62

PLAINS EXPLORATION & PRODUCTION COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Financial Statements
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets As of December 31, 2005 and 2004	F-4
Consolidated Statements of Income For the years ended December 31, 2005, 2004 and 2003	F-5
Consolidated Statements of Cash Flows For the years ended December 31, 2005, 2004 and 2003	F-6
Consolidated Statements of Comprehensive Income For the years ended December 31, 2005, 2004, and 2003	F-7
Consolidated Statements of Stockholders’ Equity For the years ended December 31, 2005, 2004, and 2003	F-8
Notes to Consolidated Financial Statements	F-9

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

F-1

Report of Independent Registered Public Accounting Firm

To The Board of Directors and Shareholders

of Plains Exploration & Production Company:

We have completed integrated audits of Plains Exploration & Production Company’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Plains Exploration & Production Company and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 4 to the consolidated financial statements, on January 1, 2003, the Company changed its method of accounting for its asset retirement obligations in connection with its adoption of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established inInternal Control—Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

F-2

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLP

Houston, Texas

March 9, 2006

F-3

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS

(in thousands of dollars)

	December 31,
	2005			2004
ASSETS
Current Assets
Cash and cash equivalents	$	1,552		$	1,545
Accounts receivable		148,691			122,288
Inventories		10,325			8,505
Deferred income taxes		128,816			76,823
Assets held for sale		—			44,222
Other current assets		3,948			4,784
		293,332			258,167
Property and Equipment, at cost
Oil and natural gas properties—full cost method
Subject to amortization		2,604,892			2,402,179
Not subject to amortization		112,204			79,405
Other property and equipment		16,282			12,546
		2,733,378			2,494,130
Less allowance for depreciation, depletion and amortization		(498,075	)		(323,041	)
		2,235,303			2,171,089
Goodwill		173,858			170,467
Other Assets		39,449			33,522
	$	2,741,942		$	2,633,245
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	122,996		$	90,469
Commodity derivative contracts		85,596			175,473
Royalties payable		43,279			39,174
Stock appreciation rights		55,170			34,589
Interest payable		13,000			13,070
Deposit on assets held for sale		—			40,711
Other current liabilities		43,957			32,909
		363,998			426,395
Long-Term Debt
Revolving credit facility		272,000			110,000
8.75% Senior Subordinated Notes		276,538			276,727
7.125% Senior Notes		248,837			248,741
		797,375			635,468
Other Long-Term Liabilities
Asset retirement obligation		155,865			126,850
Commodity derivative contracts		440,543			244,140
Other		7,014			10,534
		603,422			381,524
Deferred Income Taxes		258,810			319,483
Commitments and Contingencies (Note 10)
Stockholders’ Equity
Common stock, $0.01 par value, 150.0 million shares authorized, 78.4 million and 77.2 million issued and outstanding at December 31, 2005 and December 31, 2004, respectively		784			772
Additional paid-in capital		940,988			913,466
Retained earnings (deficit)		(133,664	)		80,406
Accumulated other comprehensive income		(89,566	)		(123,874	)
Treasury stock, at cost		(205	)		(395	)
		718,337			870,375
	$	2,741,942		$	2,633,245

See notes to consolidated financial statements.

F-4

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per share data)

	Year Ended December 31,
	2005			2004			2003
Revenues
Oil sales	$	873,121		$	593,809		$	249,500
Oil hedging		(139,089	)		(145,753	)		(51,352	)
Gas sales
Sales related to buy/sell contracts		36,940			23,245			—
Other		172,853			204,223			91,267
Gas hedging		(3,057	)		(6,108	)		13,787
Other operating revenues		3,652			2,290			888
		944,420			671,706			304,090
Costs and Expenses
Production costs
Lease operating expenses		140,595			122,540			66,858
Steam gas costs
Costs related to buy/sell contracts		38,975			23,453			—
Other		39,302			17,068			2,841
Electricity		31,817			30,137			22,385
Production and ad valorem taxes		24,478			22,332			10,125
Gathering and transportation expenses		10,125			7,550			2,610
General and administrative		127,513			85,197			43,158
Provision for legal and regulatory settlements		—			6,845			—
Depreciation, depletion and amortization		180,337			139,422			49,847
Accretion		7,578			8,563			2,637
		600,720			463,107			200,461
Income from Operations		343,700			208,599			103,629
Other Income (Expense)
Interest expense		(55,421	)		(37,294	)		(23,778	)
Debt extinguishment costs		—			(19,691	)		—
Gain (loss) on mark-to-market derivative contracts		(636,473	)		(150,314	)		847
Interest and other income (expense)		3,324			723			(159	)
Income (Loss) Before Income Taxes and Cumulative Effect of Accounting Change		(344,870	)		2,023			80,539
Income tax (expense) benefit
Current		229			(375	)		(1,224	)
Deferred		130,629			7,192			(32,228	)
Income (Loss) Before Cumulative Effect of Accounting Change		(214,012	)		8,840			47,087
Cumulative effect of accounting change, net of tax expense		—			—			12,324
Net Income (Loss)	$	(214,012	)	$	8,840		$	59,411
Earnings (loss) per share, basic and diluted
Income (loss) before cumulative effect of accounting change	$	(2.75	)	$	0.14		$	1.41
Cumulative effect of accounting change		—			—			0.37
Net income (loss)	$	(2.75	)	$	0.14		$	1.78
Weighted Average Shares Outstanding
Basic		77,726			63,542			33,321
Diluted		77,726			64,014			33,469

See notes to consolidated financial statements.

F-5

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands of dollars)

	Year Ended December 31,
	2005			2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(214,012	)	$	8,840		$	59,411
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion		187,915			147,985			52,484
Deferred income taxes		(130,629	)		(7,192	)		32,228
Debt extinguishment costs		—			(4,453	)		—
Cumulative effect of adoption of accounting change		—			—			(12,324	)
Commodity derivative contracts
Loss (gain) on derivatives		300,152			49,841			(847	)
Reclassify financing derivative settlements		459,450			103,521			—
Noncash compensation
Stock appreciation rights		17,354			20,268			15,895
Other		37,917			8,092			1,190
Other noncash items		(93	)		(144	)		123
Change in assets and liabilities from operating activities, net of effect of acquisitions
Accounts receivable and other assets		(29,651	)		(15,982	)		(3,548	)
Inventories		(1,762	)		(1,947	)		91
Accounts payable and other liabilities		(24,269	)		34,722			(28,317	)
Commodity derivative contracts		(139,038	)		19,668			1,892
Net cash provided by operating activities		463,334			363,219			118,278
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(509,127	)		(211,387	)		(122,070	)
Acquisition of Nuevo Energy Company, net of cash acquired		—			(14,156	)		—
Acquisition of 3TEC Energy Corporation, net of cash acquired		—			—			(267,546	)
Proceeds from sales of properties		346,450			238,989			23,420
Other property and equipment		(5,743	)		(8,032	)		(2,514	)
Net cash (used in) provided by investing activities		(168,420	)		5,414			(368,710	)
CASH FLOWS FROM FINANCING ACTIVITIES
Revolving credit facilities
Borrowings		1,504,200			1,044,850			471,600
Repayments		(1,342,200	)		(1,145,850	)		(296,400	)
Proceeds from issuance of 7.125% Senior Notes		—			248,695			—
Proceeds from issuance of 8.75% Senior Subordinated Notes		—			—			80,061
Retirement of debt assumed in acquisition of Nuevo Energy Company		—			(405,000	)		—
Costs incurred in connection with financing arrangements		(1,600	)		(9,325	)		(4,349	)
Derivative settlements		(459,450	)		(103,521	)		—
Other		4,143			1,686			(131	)
Net cash (used in) provided by financing activities		(294,907	)		(368,465	)		250,781
Net increase in cash and cash equivalents		7			168			349
Cash and cash equivalents, beginning of period		1,545			1,377			1,028
Cash and cash equivalents, end of period	$	1,552		$	1,545		$	1,377

See notes to consolidated financial statements.

F-6

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands of dollars)

	Year Ended December 31,
	2005			2004			2003
Net Income (Loss)	$	(214,012	)	$	8,840		$	59,411
Other Comprehensive Income (Loss)
Commodity hedging contracts
Change in fair value		(82,942	)		(287,186	)		(83,288	)
Reclassification adjustment for settled contracts		31,884			152,983			37,565
Reclassification adjustment for terminated contracts		106,165			—			—
Related tax benefit (expense)		(20,799	)		50,617			17,999
Other
Interest rate swap and minimum pension liability		—			250			239
Related tax benefit (expense)		—			(99	)		(96	)
		34,308			(83,435	)		(27,581	)
Comprehensive Income (Loss)	$	(179,704	)	$	(74,595	)	$	31,830

See notes to consolidated financial statements.

F-7

PLAINS EXPLORATION AND PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(share and dollar amounts in thousands)

	Common Stock			Additional Paid-in Capital			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income			Treasury Stock						Total
	Shares	Amount											Shares			Amount
Balance at December 31, 2002	24,224	$	244	$	174,279		$	12,155		$	(12,858	)	$	—		$	—		$	173,820
Net income	—		—		—			59,411			—			—			—			59,411
Cash contribution by
Plains Resources Inc.	—		—		510			—			—			—			—			510
Acquisition of 3TEC Energy Corporation	16,071		159		152,027			—			—			—			—			152,186
Issuance of common stock	5		—		62			—			—			—			—			62
Restricted stock awards
Issuance of restricted stock	16		—		—			—			—			(17	)		(130	)		(130	)
Deferred compensation	—		—		2,887			—			—			—			—			2,887
Spin-off by Plains Resources Inc.	—		—		(6,909	)		—			—			—			—			(6,909	)
Other comprehensive income	—		—		—			—			(27,581	)		—			—			(27,581	)
Balance at December 31, 2003	40,316		403		322,856			71,566			(40,439	)		(17	)		(130	)		354,256
Net income	—		—		—			8,840			—			—			—			8,840
Acquisition of Nuevo Energy Company
Issuance of common stock	36,486		365		574,658			—			—			—			—			575,023
Other	—		—		4,389			—			—			—			—			4,389
Restricted stock awards	—				—			—			—			—			—			—
Issuance of restricted stock	235		3		—			—			—			—			—			3
Deferred compensation	—		—		8,082			—			—			—			—			8,082
Treasury stock transactions	—		—		—			—			—			(15	)		(265	)		(265	)
Other comprehensive income	—		—		—			—			(83,435	)		—			—			(83,435	)
Exercise of stock options and other	142		1		3,481			—			—			—			—			3,482
Balance at December 31, 2004	77,179		772		913,466			80,406			(123,874	)		(32	)		(395	)		870,375
Net loss	—		—		—			(214,012	)		—			—			—			(214,012	)
Restricted stock awards	—				—			—			—			—			—			—
Issuance of restricted stock	1,010		10		—			—			—			—			—			10
Deferred compensation	—		—		21,882			—			—			—			—			21,882
Treasury stock transactions	—		—		(337	)		(58	)		—			27			190			(205	)
Other comprehensive income	—		—		—			—			34,308			—			—			34,308
Exercise of stock options and other	227		2		5,977			—			—			—			—			5,979
Balance at December 31, 2005	78,416	$	784	$	940,988		$	(133,664	)	$	(89,566	)		(5	)	$	(205	)	$	718,337

See notes to consolidated financial statements.

F-8

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization and Significant Accounting Policies

Organization

The consolidated financial statements of Plains Exploration & Production Company, a Delaware corporation, (“PXP”, “us”, “our”, or “we”) include the accounts of all its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to prior year statements to conform to the current year presentation.

We are an independent energy company that is engaged in the “upstream” oil and gas business. The upstream business acquires, exploits, develops, explores for and produces oil and gas. Our upstream activities are all located in the United States.

On December 18, 2002 Plains Resources Inc. (“Plains Resources”, now known as Vulcan Energy Corporation) distributed 100% of the issued and outstanding shares of our common stock to the holders of record of Plains Resources’ common stock (the “spin-off”).

Significant Accounting Policies

Oil and Gas Properties.    We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration, exploitation and development activities are capitalized. Such costs include internal general and administrative costs such as payroll and related benefits and costs directly attributable to employees engaged in acquisition, exploration, exploitation and development activities. General and administrative costs associated with production, operations, marketing and general corporate activities are expensed as incurred. These capitalized costs along with our estimated asset retirement obligations recorded in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), are amortized to expense by the unit-of-production method using engineers’ estimates of proved oil and natural gas reserves. The costs of unproved properties are excluded from amortization until the properties are evaluated. Interest is capitalized on oil and natural gas properties not subject to amortization and in the process of development. Proceeds from the sale of oil and natural gas properties are accounted for as reductions to capitalized costs unless such sales involve a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized. Unamortized costs of proved properties are subject to a ceiling which limits such costs to the present value of estimated future cash flows from proved oil and natural gas reserves of such properties (including the effect of any related hedging activities) reduced by future operating expenses, development expenditures and abandonment costs (net of salvage values), and estimated future income taxes thereon.

Asset Retirement Obligations.    We account for our asset retirement obligations in accordance with SFAS 143 which requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred. A legal obligation is a liability that a party is required to settle as a result of an existing or enacted law, statute, ordinance or contract. When the liability is initially recorded, the entity is required to capitalize the retirement cost of the related long-lived asset. Each period the liability is accreted to its then present value, and the capitalized cost is depreciated over the useful life of the related asset.

Other Property and Equipment.    Other property and equipment is recorded at cost and consists primarily of aircraft, office furniture and fixtures and computer hardware and software. Acquisitions,

F-9

renewals, and betterments are capitalized; maintenance and repairs are expensed. Depreciation is provided using the straight-line method over estimated useful lives of three to ten years. Net gains or losses on property and equipment disposed of are included in operating income in the period in which the transaction occurs.

Use of Estimates.    The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates made by management include (1) oil and natural gas reserves; (2) depreciation, depletion and amortization, including future abandonment costs; (3) assigning fair value and allocating purchase price in connection with business combinations, including goodwill; (4) income taxes; (5) accrued liabilities; and (6) valuation of derivative instruments. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Cash and Cash Equivalents.    Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. At December 31, 2005 and 2004, the majority of cash and cash equivalents was concentrated in one institution and at times may exceed federally insured limits. We periodically assess the financial condition of the institution and believe that any possible credit risk is minimal. Accounts payable at December 31, 2005 and 2004 includes $15.0 million and $14.4 million, respectively, representing outstanding checks that had not been presented for payment.

Inventory.    Oil inventories are carried at the lower of the cost to produce or market value and materials and supplies inventories are stated at the lower of cost or market with cost determined on an average cost method. Inventory consists of the following (in thousands):

	December 31,
	2005		2004
Oil	$	2,099	$	1,526
Materials and supplies		8,226		6,979
	$	10,325	$	8,505

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

	December 31,
	2005		2004
Land	$	16,584	$	13,873
Debt issue costs, net		13,584		15,131
Other		9,281		4,518
	$	39,449	$	33,522

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

Federal and State Income Taxes.    Income taxes are accounted for in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (“SFAS 109”). SFAS 109 requires recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred

F-10

tax liabilities and assets are determined based on the difference between the financial statement and tax bases of assets and liabilities using tax rates in effect for the year in which the differences are expected to reverse. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

Revenue Recognition.    Oil and gas revenue from our interests in producing wells is recognized when the production is delivered and the title transfers.

General and Administrative Expense.    Our general and administrative (“G&A”) expense consists of (in thousands):

	Year Ended December 31,
	2005		2004		2003
G&A excluding items below	$	50,321	$	35,394	$	18,694
Stock appreciation rights		39,856		35,464		18,010
Other stock-based compensation		37,336		8,092		1,190
Merger related costs		—		6,247		5,264
	$	127,513	$	85,197	$	43,158

Derivative Financial Instruments.    We use various derivative instruments to manage our exposure to commodity price risk on sales of oil and gas production. The derivative instruments currently consist of oil and gas swaps, collars and option contracts entered into with financial institutions. We do not enter into derivative instruments for speculative trading purposes. Derivative instruments utilized to manage commodity price risk are accounted for in accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”, as amended (“SFAS 133”). See Note 3.

Earnings Per Share.    Weighted average shares outstanding for computing basic and diluted earnings for the years ended December 31, 2005, 2004 and 2003 were (in thousands):

	Year Ended December 31,
	2005	2004	2003
Common shares outstanding—basic	77,726	63,542	33,321
Unvested restricted stock, restricted stock units and stock options	—	472	148
Common shares outstanding—diluted	77,726	64,014	33,469

Due to our net loss in 2005 our unvested restricted stock, restricted stock units and stock options (796,000 equivalent shares) were not included in computing earnings per share because the effect was antidilutive. In computing earnings per share, no adjustments were made to reported net income.

Goodwill.    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 transaction, over the fair value of the net assets acquired. Goodwill is not amortized, but instead must be tested annually for impairment by applying a fair-value based test. We perform our goodwill impairment test annually on December 31. 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 estimated reserve volumes which would result in a decline in the fair value of our oil and gas properties. We follow the full cost method of accounting and all of our operations are located in the United States. We have determined that for the purpose of performing an impairment test, the Company is the reporting unit.

F-11

In 2005 we completed our evaluation of the assets acquired and liabilities assumed at the time of our 2004 acquisition of Nuevo Energy Company (“Nuevo”, see Note 2) and during 2005 goodwill related to the acquisition was increased by $1.0 million. Goodwill at December 31, 2005 includes $2.4 million that was included in Oil and Natural Gas Properties—Subject to Amortization at December 31, 2004.

Business Segment Information.    SFAS 131, “Disclosures about Segments of an Enterprise and Related Information” (“SFAS 131”) establishes standards for reporting information about operating segments. We acquire, exploit, develop, explore for and produce oil and gas and all of our operations are located in the United States. Our corporate management team that administers all properties as a whole rather than as discrete operating segments. We track basic operational data by area, however, we measure financial performance as a single enterprise and not on an area-by-area basis. We allocate capital resources on a project-by-project basis across our entire asset base to maximize profitability without regard to individual areas or segments. Accordingly, we have one operating segment, our oil and gas operations in the United States.

Stock Based Compensation.    We account for stock based compensation using the intrinsic value method pursuant to Accounting Principles Bulletin No. 25 “Accounting for Stock Issued to Employees”. No adjustments to our net income or earnings per share would be required under SFAS No. 123 “Accounting for Stock Based Compensation” (“SFAS 123”). See Note 7.

In December 2004 the FASB issued SFAS No.123R “Share-Based Payment” (“SFAS 123R”) that requires that the compensation cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the fair value of the equity or liability instruments issued. SFAS 123R covers a wide range of share-based compensation arrangements including stock options, restricted stock plans, performance-based awards, stock appreciation rights, and employee stock purchase plans. SFAS 123R replaces SFAS 123 and supersedes APB 25. Public entities (other than those filing as small business issuers) were originally required to apply SFAS 123R as of the first interim or annual reporting period that begins after June 15, 2005. On April 14, 2005 the SEC announced the adoption of a new rule that amends the compliance dates for SFAS 123R. The Commission’s new rule allows registrants to implement SFAS 123R at the beginning of their next fiscal year.

We will adopt SFAS 123R effective January 1, 2006 using the “modified prospective approach” as allowed under SFAS 123R. Under this approach, the valuation of equity instruments (i.e., restricted stock and restricted stock units) granted prior to the adoption of 123R will not be affected, however, the valuation of liability instruments (i.e., stock appreciation rights, or “SARs”) granted prior to the adoption of 123R will be revalued under a fair value approach instead of the previously applied intrinsic valuation. In addition, SFAS 123R requires us to begin estimating expected future forfeitures under each stock compensation plan. We are completing our assessment of SFAS 123R and the effect it will have on our financial statements.

Recent Accounting Pronouncements.    In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”). FIN 47 clarifies the definition and treatment of conditional asset retirement obligations as discussed in SFAS 143.” A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the company. FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. FIN 47 is intended to provide more information about long-lived assets and future cash outflows for these obligations and

F-12

more consistent recognition of these liabilities. Our financial position, results of operations or cash flows were not impacted by the implementation of FIN 47.

In June 2005 the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections” (“SFAS 154”), which changes the requirements for the accounting for and reporting of a change in accounting principle by requiring voluntary changes in accounting principles to be reported using retrospective application, unless impracticable to do so. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. Application is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. We will adopt SFAS 154 on January 1, 2006 and we do not believe that our financial position, results of operations or cash flows will be impacted.

Buy/Sell Contracts.    Steam generators utilized in our thermal recovery operations in California are fueled by natural gas. In certain instances we have entered into buy/sell contracts that allow us to exchange gas we produce elsewhere for gas delivered to and used in thermal recovery operations. We did not enter into buy/sell contracts in periods prior to our acquisition of Nuevo Energy Company in May 2004.

In September 2005 in Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” the EITF reached a consensus that two or more inventory transactions with the same counterparty should be viewed as a single nonmonetary transaction if the transactions were entered into in contemplation of one another (as determined in accordance with Issue No. 04-13). We have determined that transactions under certain of our buy/sell contracts should be presented net in accordance with Issue No. 04-13. We will apply Issue No. 04-13 effective January 1, 2006 and, accordingly, certain costs included in operating costs in 2005 and 2004 will be included as a reduction of revenues in 2006 and subsequent periods. Our financial position, results of operations and cash flows will not be impacted by the implementation of Issue No. 04-13.

Note 2—Acquisitions

Nuevo Energy Company

On May 14, 2004 we acquired Nuevo in a stock-for-stock transaction (the “Nuevo acquisition”). In the Nuevo 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. The Nuevo acquisition required the issuance of 36.5 million additional PXP common shares, plus the assumption of $254 million in net debt and $115 million of $2.875 Term Convertible Securities, Series A, or TECONS. We have accounted for the Nuevo acquisition as a purchase effective May 14, 2004.

F-13

The calculation of the Nuevo acquisition purchase price and the allocation to assets and liabilities as of May 14, 2004 are shown below. The average PXP common stock price is based on the average closing price of PXP common stock during the five business days commencing two business days before the merger was announced.

	(in thousands, except share price)
Shares of PXP common stock issued	$	36,486
Average PXP stock price		15.76
Fair value of PXP common stock issued	$	575,023
Fair value of Nuevo stock options assumed by Plains		4,389
Tender offer for Nuevo stock options		17,056
Estimated merger expenses		36,652
Total estimated purchase price before liabilities assumed		633,120
Fair value of liabilities :
Senior Subordinated Notes		162,945
Bank Credit Facility		140,000
TECONS		103,815
Current liabilities (1)		207,957
Other noncurrent liabilities		33,583
Deferred income tax liabilities		221,803
Asset retirement obligation		128,053
Total estimated purchase price plus liabilities assumed	$	1,631,276
Fair value of assets acquired:
Current assets (including deferred income taxes of $42,367)	$	250,821
Oil and gas properties
Subject to amortization		1,208,020
Not subject to amortization		137,457
Other noncurrent assets		8,599
Goodwill		26,379
Total estimated fair value of assets acquired	$	1,631,276

(1) $47,776,000 of accrued liabilities are included under the captions tender offer for Nuevo stock options and estimated merger expenses.

We acquired Nuevo to allow us to take advantage of the synergies resulting in significant cost savings and because of the complementary nature of Nuevo’s assets and operations onshore and offshore California to our existing asset base. The allocation of purchase price includes $26.4 million of goodwill. The goodwill is related to deferred income tax liabilities recorded due to purchase accounting rules that require that deferred taxes be recorded at undiscounted amounts. The allocation of purchase price to oil and gas properties is based on our estimate of the fair value of such properties on a discounted, after-tax basis. The goodwill is not deductible for income tax purposes.

Under Section 43 of the Internal Revenue Code of 1986 (as amended) and similar California tax rules, taxpayers may claim enhanced oil recovery (“EOR”) tax credits based on capital spending and lease operating expense of qualified projects. We have evaluated certain projects that were operated by Nuevo to determine if they qualify for such credits. Based on our evaluation, we have or will amend certain federal and state income tax returns previously filed by Nuevo to claim EOR tax credits not previously claimed by Nuevo. The credits are subject to various risks, including possible future legislative changes, possible phase out of the credit as a result of high crude oil prices, and audit positions that may be taken by taxing authorities. Our purchase price allocation reflects $43.5 million with respect to these credits.

F-14

3TEC Energy Corporation

On June 4, 2003, we acquired 3TEC (the “3TEC acquisition”), for approximately $312.9 million in cash and common stock plus $90.0 million to retire 3TEC’s outstanding debt. 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 3TEC acquisition, we paid cash consideration to the common shareholders of approximately $152.4 million and issued 15.3 million common 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 3TEC acquisition as a purchase effective June 1, 2003.

The calculation of the purchase price and the allocation to assets and liabilities as of June 4, 2003 are shown below. The average PXP common stock price is based on the average closing price of PXP common stock during the five business days commencing two business days before the merger was announced.

	(in thousands, except share price)
Shares of PXP common stock issued		16,071
Average PXP stock price	$	9.47
Fair value of PXP common stock issued	$	152,186
Cash to 3TEC stockholders and warrantholders		160,720
Estimated merger expenses		5,041
Total estimated purchase price before liabilities assumed		317,947
Fair value of liabilities :
3TEC debt (including accrued interest)		90,065
Current liabilities		73,570
Other noncurrent liabilities		254
Deferred income tax liabilities		40,281
Asset retirement obligation		4,577
Total estimated purchase price plus liabilities assumed	$	526,694
Fair value of assets acquired:
Current assets	$	23,525
Oil and gas properties
Subject to amortization		294,356
Not subject to amortization		61,116
Other noncurrent assets		218
Goodwill		147,479
Total estimated fair value of assets acquired	$	526,694

Prior to the acquisition, 3TEC redeemed all outstanding shares of its Series D preferred stock for $14.7 million and incurred $11.1 million of merger related costs. Current liabilities assumed in the merger include $14.7 million related to the preferred stock redemption and $1.7 million of merger related costs.

The significant factors contributing to the recognition of goodwill include, but are not limited to, providing a presence in East Texas and the Gulf Coast regions that can be used to pursue other opportunities in these areas, improving financial flexibility with more efficient access to lower cost capital and higher returns from synergies in having a broader and more diversified reserve base and the ability to acquire an established business with an assembled workforce. In addition, additional

F-15

goodwill has been recorded due to the application of purchase accounting rules that require that deferred taxes be recorded at undiscounted amounts. The goodwill is not deductible for income tax purposes.

Pro Forma Information

The following unaudited pro forma information shows the proforma effect of the Nuevo acquisition, the issuance by PXP of $250 million of 7.125% Senior Notes due 2014 and the retirement of Nuevo’s 9 ³/8% Senior Subordinated Notes and TECONS as discussed in Note 5, the sale of Nuevo’s Congo operations as discussed in Note 9, the 3TEC acquisition, and PXP’s issuance of $75 million of 8.75% senior subordinated notes on May 30, 2003. This unaudited pro forma information assumes the Nuevo acquisition, the issuance of the 7.125% Senior Notes and the sale of Nuevo’s Congo operations occurred on January 1 of the year presented. The 3TEC acquisition and the issuance of the $75 million of 8.75% senior subordinated notes are assumed to have occurred on January 1, 2003.

This unaudited pro forma information has been prepared based on our historical consolidated statements of income and the historical consolidated statements of income of Nuevo and 3TEC. We believe the assumptions used provide a reasonable basis for presenting the significant effects directly attributable to the pro forma transactions. This pro forma financial information does not purport to represent what our results of operations would have been if such transactions had occurred on such dates.

	Year Ended December 31,
(in thousands, except per share data)	2004		2003
Revenues	$	806,637	$	706,250
Income from operations		228,152		189,115
Income from continuing operations		1,053		51,037
Discontinued operations and cumulative effect of accounting changes		—		26,575
Net income		1,053		77,612
Basic earnings per share
Income from continuing operations	$	0.01	$	0.67
Discontinued operations and cumulative effect of accounting changes		—		0.35
Net income		0.01		1.02
Diluted earnings per share
Income from continuing operations	$	0.01	$	0.66
Discontinued operations and cumulative effect of accounting changes		—		0.34
Net income		0.01		1.00
Weighted average shares outstanding
Basic		76,902		76,686
Diluted		77,374		77,240

Income from continuing operations has been reduced by debt extinguishment costs of $14.0 million and $7.5 million in year December 31, 2004 and 2003, respectively.

Note 3—Derivative Instruments and Hedging Activities

General

We use various derivative instruments to manage our exposure to commodity price risk on sales of oil and gas production. All derivative instruments are recorded on the balance sheet at fair value. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value, both

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realized and unrealized, are recognized currently in our income statement as gain (loss) on mark-to-market derivative contracts. Cash flow is only impacted to the extent the actual settlements under the contracts result in making or receiving a payment from the counterparty. If a derivative is designated as a cash flow hedge and qualifies for hedge accounting, any unrealized gain or loss is deferred in accumulated Other Comprehensive Income (“OCI”), a component of Stockholders’ Equity, until the hedged oil and gas production is sold. Realized gains and losses on derivative instruments that are designated as a hedge and qualify for hedge accounting are generally included in oil and gas revenues in the period the hedged volumes are sold. Gains and losses deferred in OCI related to cash flow hedges for which hedge accounting has been discontinued remain in OCI until the related product has been delivered.

Elimination of 2006 Swap & Collar Positions

In May 2005 we completed a series of transactions that eliminated all of our 2006 oil price swaps and collars at a pre-tax cost of $292.7 million. Approximately $145.4 million of this amount is attributable to 2006 collars for 22,000 barrels of oil per day with a floor price of $25.00 and an average ceiling price of $34.76. The collars were not accounted for as hedges, therefore, the $145.4 million loss in the fair value of these instruments is recognized in our income statement and there will be no income statement effect in 2006. Approximately $147.3 million of the cost is attributable to 2006 swaps for 15,000 barrels of oil per day at an average price of $25.28. We used hedge accounting for the swaps through March 2005 and as a result the $145.8 million loss in fair value attributable to the swaps has been deferred in OCI and will be recognized as a noncash reduction to oil revenues in 2006 when the hedged production is sold.

Under SFAS 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”, the collars were deemed to contain a significant financing element because they included off-market terms. Accordingly, the $145.4 million cash payment for the collars is reflected as a financing cash outflow in our 2005 statement of cash flows. The $147.3 million cash payment for the swaps is reflected as an operating cash outflow in our 2005 statement of cash flows. These payments reduced derivative liabilities on our balance sheet.

Floors for 2006 and 2007 Oil Production

In 2005 we entered into a series of transactions that resulted in us now holding NYMEX put options with a strike price of $55.00 per barrel on 50,000 barrels of oil per day in 2006 and 2007. These put options cost an average of $4.91 per barrel for 2006 and $5.57 per barrel for 2007, which will be paid when the options are settled. We have elected not to use hedge accounting for the puts, consequently, the puts will be marked-to-market with fair value gains and losses recognized as a gain or loss on mark-to-market derivative contracts on the income statement.

Ceilings for 2006 Natural Gas Purchases

We purchase natural gas that is utilized in our steam flood operations. In 2005 we acquired NYMEX call options with a strike price of $12.00 per MMBtu on 30,000 MMBtu of natural gas per day in 2006. These call options cost an average of $1.04 per MMBtu, which will be paid when the options are settled. We have elected not to use hedge accounting for the calls, consequently, the calls will be marked-to-market with fair value gains and losses recognized as a gain or loss on mark-to-market derivative contracts on the income statement.

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At December 31, 2005 we had the following open commodity derivative positions, none of which were designated as hedging instruments:

Period	Instrument Type	Daily Volumes	Average Price	Index
Sales of Crude Oil Production
2006
Jan - Dec	Put options	50,000 Bbls	$55.00 Strike price	WTI
2007
Jan - Dec	Collar	22,000 Bbls	$25.00 Floor - $34.76 Ceiling	WTI
Jan - Dec	Put options	50,000 Bbls	$55.00 Strike price	WTI
2008
Jan - Dec	Collar	22,000 Bbls	$34.76 Ceiling	WTI
Purchases of Natural Gas
2006
Jan - Dec	Call options	30,000 MMBtu	$12.00 Strike price	Socal

The average strike price for the put options and call options do not reflect the cost to purchase such options.

During the years ended December 31, 2005 and 2004 we recognized pre-tax losses of $636.5 million and $150.3 million, respectively, from derivatives that do not qualify for hedge accounting. During such periods we made cash payments of $280.0 million and $32.2 million, respectively, on derivatives that do not qualify for hedge accounting that settled during the periods. In addition, in 2005 we made a $145.4 million cash payment to eliminate our 2006 oil price collars.

Other Comprehensive Income

During the years ended December 31, 2005, 2004 and 2003, net deferred losses of $138.0 million (including $0.1 million for ineffectiveness), $153.0 million (including $1.3 million for ineffectiveness) and $37.6 million, respectively, were reclassified from OCI and charged to oil and gas revenues and steam gas costs. At December 31, 2005 OCI consisted of $145.8 million ($89.6 million, net of tax) of deferred losses attributable to the cancelled 2006 swaps that will be reclassified to oil revenue in 2006. At December 31, 2004, OCI consisted of $200.9 million ($123.9 million after tax) of unrealized losses on our open hedging instruments, including $106.2 million ($65.5 million, net of tax) of deferred losses attributable to the cancelled 2005 swaps.

Note 4—Asset Retirement Obligations

Effective January 1, 2003, we adopted SFAS 143 which requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred. A legal obligation is a liability that a party is required to settle as a result of an existing or enacted law, statute, ordinance or contract. When the liability is initially recorded, the entity is required to capitalize the retirement cost of the related long-lived asset. Each period the liability is accreted to its then present value, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. Prior to the adoption of SFAS 143 we included estimated future costs of abandonment and dismantlement in our full cost amortization base and these costs were amortized as a component of our depletion expense.

At January 1, 2003, the present value of our future asset retirement obligation for oil and gas properties and equipment was $26.5 million. The cumulative effect of our adoption of SFAS 143 and the change in accounting principle resulted in an increase in net income during the first quarter of 2003 of $12.3 million (reflecting a $30.8 million decrease in accumulated depreciation, depletion and

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amortization, partially offset by $10.6 million in accretion expense, and $7.9 million in income taxes). We recorded a liability of $26.5 million and an asset of $15.9 million in connection with the adoption of SFAS 143. Adopting SFAS No. 143 did not impact our cash flows.

The following table reflects the changes in our asset retirement obligation during the period (in thousands):

	Year Ended December 31,
	2005			2004			2003
Asset retirement obligation—beginning of period	$	130,469		$	33,735		$	26,540
Liabilities incurred
Nuevo acquisition		—			128,053			—
Other acquisitions		12,613			—			4,577
Property dispositions and other		(2,848	)		(38,717	)		(469	)
Settlements		(1,735	)		(218	)		(415	)
Change in estimate		11,443			(2,184	)		—
Accretion expense		7,541			8,563			2,637
Asset retirement additions		3,472			1,237			865
Asset retirement obligation—end of period (1)	$	160,955		$	130,469		$	33,735

(1) $5.1 million and $3.6 million included in current liabilities at December 31, 2005 and 2004, respectively.

Note 5—Long-Term Debt

At December 31, 2005 and 2004, long-term debt consisted of (in thousands):

	December 31,
	2005		2004
Senior revolving credit facility	$	272,000	$	110,000
8.75% senior subordinated notes, including unamortized premium of $1.5 million in 2005 and $1.7 million in 2004		276,538		276,727
7.125% senior notes, including unamortized discount of $1.2 million in 2005 and $1.3 million in 2004		248,837		248,741
	$	797,375	$	635,468

Aggregate total maturities of long-term debt in the next five years are as follows: 2006—$0.0 million; 2007—$0.0 million; 2008—$0.0 million; 2009—$0.0 million; 2010—$272.0 million.

Senior Revolving Credit Facility.    On May 16, 2005, we entered into an Amended and Restated Credit Agreement (the “Amended Credit Agreement”) which established the facility size at $750 million. The borrowing base is redetermined on a semi-annual basis, with PXP and the lenders each having the right to one annual interim unscheduled redetermination, and may be adjusted based on PXP’s oil and gas properties, reserves, other indebtedness and other relevant factors. Our borrowing base was redetermined to be $1.2 billion in November 2005. We have not elected to seek an increase in the size of our credit facility. Additionally, the Amended Credit Agreement contains a $75 million sub-limit for letters of credit. The Amended Credit Agreement matures on May 16, 2010. Collateral consists of 100% of the shares of stock of all our domestic subsidiaries and mortgages covering at least 80% of the total present value of our domestic oil and gas properties.

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Amounts borrowed under the Amended Credit Agreement bear an annual interest rate, at our election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus a margin ranging from 1.00% to 1.75%; or (ii) the greatest of (1) the prime rate, as determined by JPMorgan Chase Bank, (2) the certificate of deposit rate, plus 1.0%, or (3) the federal funds rate, plus 0.5%; plus an additional variable amount ranging from 0% to 0.5% for each of (1)-(3). The additional variable amount of interest payable on outstanding borrowings is based on (1) the utilization rate as a percentage of the total amount of funds borrowed under the Amended Credit Agreement to the borrowing base and (2) our long-term debt rating. Commitment fees and letter of credit fees under the Amended Credit Agreement are based on the utilization rate and our long-term debt rating. Commitment fees range from 0.25% to 0.5% of the amount available for borrowing. Letter of credit fees range from 1.00% to 1.75%. The issuer of any letter of credit receives an issuing fee of 0.125% of the undrawn amount. The effective interest rate on our borrowings under the Amended Credit Agreement was 5.4% at December 31, 2005.

The Amended Credit Agreement contains negative covenants that limit our ability, as well as the ability of our restricted subsidiaries, among other things, to incur additional debt, pay dividends on stock, make distributions of cash or property, change the nature of our business or operations, redeem stock or redeem subordinated debt, make investments, create liens, enter into leases, sell assets, sell capital stock of subsidiaries, guarantee other indebtedness, enter into agreements that restrict dividends from subsidiaries, enter into certain types of swap agreements, enter into gas imbalance or take-or-pay arrangements, merge or consolidate and enter into transactions with affiliates. a current ratio, which includes availability under the Amended Credit Agreement, of at least 1.0 to 1.0 and a ratio of debt to EBITDAX (as defined) of no greater than 4.25 to 1.00.

At December 31, 2005, we had $272.0 million in borrowings and $6.9 million in letters of credit outstanding under the Amended Credit Agreement. At that date we were in compliance with the covenants contained in the Amended Credit Agreement and could have borrowed the full amount available under the Amended Credit Agreement.

7.125% Senior Notes.    On December 31, 2005 we had $250.0 million principal amount of ten year senior unsecured notes due 2014 (the “7.125% Notes”) outstanding. The 7.125% Notes were issued at 99.478% and bear interest at 7.125% with a yield to maturity of 7.2%. During the period from June 15, 2009 to June 14, 2012, we may redeem all or part of the 7.125% Notes at our option, at rates varying from 103.563% to 101.188% of the principal amount and at 100% of the principal amount thereafter. In addition, before June 15, 2009, we may redeem all or part of the 7.125% Notes at the make-whole price set forth under the indenture. At any time prior to June 15, 2007, we may redeem up to 35% of the 7.125% Notes with the net cash proceeds of certain equity offerings at the redemption price set forth under the indenture. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the 7.125% Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase.

The 7.125% Notes are our unsecured general obligations and are jointly and severally guaranteed on a full, unconditional basis by all of our existing and future domestic restricted subsidiaries.

8.75% Senior Subordinated Notes.    At December 31, 2005, we had $275.0 million principal amount of 8.75% Senior Subordinated Notes due 2012 (the “8.75% Notes”) outstanding. The 8.75% Notes are not redeemable until July 1, 2007. During the period from July 1, 2007 to June 30, 2010 they are redeemable, at our option, at rates varying from 104.375% to 101.458% of the principal amount and at 100% of the principal amount thereafter. In the event of a change of control, as defined in the indenture, we will be required to make an offer to repurchase the 8.75% Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase.

The 8.75% Notes are our unsecured general obligations, are subordinated in right of payment to all of our existing and future senior indebtedness and are jointly and severally guaranteed on a full, unconditional basis by all of our existing and future domestic restricted subsidiaries.

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The indentures governing the 8.75% Notes and the 7.125% Notes contain covenants that limit our ability, as well as the ability of our subsidiaries, among other things, to incur additional indebtedness, make certain investments, pay dividends, or make other distributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness, sell assets, incur dividends or other payment restrictions affecting subsidiaries, enter into transactions with affiliates, create liens, merge, consolidate and transfer assets and enter into different lines of business.

Short-term Credit Facility.    In May 2005 we amended our uncommitted short-term credit facility to extend its term and increase the facility size. We may make borrowings from time to time until May 27, 2006, not to exceed at any time the maximum principal amount of $25.0 million. No advance under the short-term facility may have a term exceeding fourteen days and all amounts outstanding are due and payable no later than May 27, 2006. Each advance under the short-term facility shall bear interest at a rate per annum mutually agreed on by the bank and the Company. No amounts were outstanding under the short-term credit facility at December 31, 2005.

Debt Extinguishment Costs.    In connection with the retirement of the debt assumed in the acquisition of Nuevo we recorded $19.7 million of debt extinguishment costs related to the repurchase of all $150 million of Nuevo’s outstanding 9 ³/8% Senior Subordinated Notes and all $118 million aggregate principal amount of Nuevo’s 5.75% Convertible Subordinated Debentures due December 15, 2026.

Note 6—Related Party Transactions

Our Chief Executive Officer is a director of Vulcan Energy Corporation (“Vulcan Energy”, formerly known as Plains Resources) and until August 2005 held an interest in the general partner of Plains All American Pipeline, L.P. (“PAA”), a publicly traded master limited partnership. PAA is also an affiliate of Vulcan Energy. PAA is the marketer/purchaser for a portion of our oil production, including the royalty share of production, under a marketing agreement that provides that PAA will purchase for resale at market prices certain of our oil production. PAA charges a marketing fee of either $0.20 or $0.15 per barrel based upon the contract the barrels are resold under. During the years ended December 31, 2005, 2004 and 2003, the following amounts were recorded with respect to such transactions (in thousands of dollars):

	Year Ended December 31,
	2005		2004		2003
Sales of oil to PAA
PXP’s share	$	357,174	$	274,447	$	238,663
Royalty owners’ share		65,782		54,208		45,703
	$	422,956	$	328,655	$	284,366
Charges for PAA marketing fees	$	1,233	$	1,427	$	1,728

At December 31, 2005 and 2004 accounts receivable from PAA totaled $36.9 million and $26.2 million, respectively.

In connection with the the spin-off we entered into certain agreements with Plains Resources, including a master separation agreement; the Plains Exploration & Production transition services agreement that expired June 16, 2004; the Plains Resources transition services agreement that expired June 8, 2004; and a technical services agreement that expired June 30, 2004. For the year ended December 31, 2004 we billed Plains Resources $0.4 million for services provided by us under these agreements and Plains Resources billed us $0.1 million for services they provided to us under

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these agreements. In addition, for the year ended December 31, 2004 we billed Plains Resources $0.2 million for administrative costs associated with certain special projects performed on their behalf. For the year ended December 31, 2003 we billed Plains Resources $0.5 million for services provided by us under these agreements and Plains Resources billed us $0.1 million for services they provided to us under these agreements.

In June 2004, based on third party valuations the Company acquired two aircraft from Cypress Aviation LLC (“Cypress”), for $4.5 million. Our Chief Executive Officer is a member of Cypress. Prior to acquiring the aircraft, we chartered private aircraft from Gulf Coast Aviation Inc. (“Gulf Coast”), a corporation that from time-to-time leased aircraft owned by Cypress. In 2004 and 2003, we paid Gulf Coast $0.5 million and $0.8 million, respectively, in connection with such services. The charter services were arranged with market-based rates.

Note 7—Stock and Other Compensation Plans

We have two stock incentive plans, the 2002 Stock Incentive Plan (the “2002 Plan”) which provides for a maximum of 1.5 million shares available for options and awards and the 2004 Stock Incentive Plan (the “2004 Plan”) which provides for a maximum of 5.0 million shares available for options and awards.

The 2002 Plan and the 2004 Plan provide for the grant of stock options, and other awards (including performance units, performance shares, share awards, restricted stock, restricted stock units, and stock appreciation rights, or SARs) to our directors, officers, employees, consultants and advisors. Our compensation committee may grant options and SARs on such terms, including vesting and payment forms, as it deems appropriate in its discretion, however, no option or SAR may be exercised more than 10 years after its grant, and the purchase price for incentive stock options and non-qualified stock options may not be less than 100% of the fair market value of our common stock on the date of grant. The compensation committee may grant restricted stock awards, restricted stock units, share awards, performance units and performance shares on such terms and conditions as it may in its discretion decide.

At the time of the spin-off all individuals holding outstanding options to acquire Plains Resources common stock were granted an equal number of SARs. The exercise price of the SARs was based on the exercise price of the Plains Resources options, as adjusted. The SARs had the same amount of vesting as the related Plains Resources stock options and vesting terms remained unchanged. Generally, the SARs had a pro rata vesting period of two to five years and an exercise period of five to ten years.

SARs are subject to variable accounting treatment. Accordingly, at the end of each quarter, we compare the closing price of our common stock on the last day of the quarter to the exercise price of each SAR. To the extent the closing price exceeds the exercise price of each SAR, we recognize such excess as an accounting charge for the SAR’s deemed vested at the end of the quarter to the extent such excess had not been recognized in previous quarters. If such excess were to be less than the extent to which accounting charges had been recognized in previous quarters, we would recognize the difference as income in the quarter. In 2005, 2004 and 2003 we recognized charges of $39.9 million, $35.5 million and $18.0 million, respectively, as compensation expense with respect to SARs vested or deemed vested during the periods. In 2005, 2004 and 2003 cash payments with respect to SARs exercised were $22.5 million, $15.2 million and $2.1 million, respectively.

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A summary of the status of our SARs as of December 31, 2005, 2004 and 2003 and changes during the years ending on those dates are presented below (shares in thousands):

	2005				2004				2003
	SARs		Weighted Average Exercise Price		SARs		Weighted Average Exercise Price		SARs		Weighted Average Exercise Price
Outstanding at beginning of year	2,766		$	10.10	3,933		$	9.25	4,047		$	8.68
Granted	677			36.45	352			16.32	489			11.27
Exercised	(762	)		9.17	(1,440	)		9.22	(404	)		6.05
Forfeited	(66	)		24.27	(79	)		11.57	(199	)		9.13
Outstanding at end of year	2,615		$	16.82	2,766		$	10.10	3,933		$	9.25
SARs exercisable at year-end	1,538		$	9.58	1,794		$	8.90	1,992		$	8.76

The following table reflects the SARs outstanding at December 31, 2005 (share amounts in thousands):

Range of Exercise Price	Number Outstanding   at 12/31/05	Weighted Average Remaining Contractual Life	Weighted Average Exercise     Price	Number Exercisable at 12/31/05	Weighted Average Exercise     Price
$  9.08-$  9.08	1,000	5.35 years	$  9.08	1,000	$  9.08
9.36-    9.37	300	0.91 years	9.36	225	9.36
9.45-  10.59	312	1.77 years	10.27	229	10.26
10.60-  15.63	319	2.97 years	14.37	75	13.48
17.20-  31.17	300	4.05 years	29.54	9	20.00
32.20-  42.82	384	4.59 years	40.23	—	—
$  9.08-$42.82	2,615	3.86 years	16.82	1,538	9.58

Our stock compensation plans also allow grants of restricted stock and restricted stock units. Restricted stock is issued on the grant date but restricted as to transferability. Restricted stock unit awards represent the right to receive common stock when vesting occurs.

A summary of the status of our restricted stock and restricted stock units as of December 31, 2005, 2004 and 2003 and changes during the years ending on those dates are presented below (shares in thousands):

	December 31,
	2005			2004			2003
Outstanding at beginning of year		1,782			523			210
Granted		3,857			1,600			455
Vested		(1,546	)		(328	)		(107	)
Cancelled		(3	)		(13	)		(35	)
Outstanding at end of year		4,090			1,782			523
Weighted average grant date fair value per share	$	38.17		$	17.31		$	10.74

During 2005, 2004 and 2003 we recognized total compensation expense of $41.0 million, $9.1 million and $2.9 million, respectively, a portion of which was capitalized, related to our restricted stock and restricted stock unit grants.

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As a result of the Nuevo acquisition, we converted certain of Nuevo’s outstanding stock options to options on our common stock. At December 31, 2005 there were 156,256 options outstanding with an average exercise price of $15.53 per share and an average remaining life of 3.2 years.

We also have a 401(k) defined contribution plan whereby we match 100% of an employee’s contribution (subject to certain limitations in the plan). Matching contributions are made 100% in cash. In 2005, 2004 and 2003 we made contributions totaling $4.4 million, $3.5 million and $2.0 million, respectively, to the 401(k) plan.

Note 8—Income Taxes

For the years ended December 31, 2005, 2004 and 2003 our income tax expense (benefit) consisted of (in thousands):

	Year Ended December 31,
	2005			2004			2003
Current
U.S. Federal	$	(872	)	$	(1,215	)	$	(1,186	)
State		643			1,590			2,410
		(229	)		375			1,224
Deferred
U.S. Federal		(119,606	)		(3,612	)		29,660
State		(11,023	)		(3,580	)		2,568
		(130,629	)		(7,192	)		32,228
	$	(130,858	)	$	(6,817	)	$	33,452

Our deferred income tax assets and liabilities at December 31, 2005 and 2004 consist of the tax effect of income tax carryforwards and differences related to the timing of recognition of certain types of costs as follows (in thousands):

	December 31,
	2005			2004
U.S. Federal
Deferred tax assets:
Net operating loss	$	66,199		$	38,301
Tax credits		70,057			53,718
Commodity hedging contracts and other		164,068			130,424
		300,324			222,443
Deferred tax liabilities:
Net oil & gas acquisition, exploration and development costs		414,027			(434,513	)
Net U.S. Federal deferred tax asset (liability)		(113,703	)		(212,070	)
States
Deferred tax assets:
Net operating loss		7,148			178
Tax credits		27,670			20,921
Commodity hedging contracts and other		27,363			20,506
		62,181			41,605
Deferred tax liabilities:
Net oil & gas acquisition, exploration and development costs		(78,472	)		(72,195	)
Net state deferred tax liability		(16,291	)		(30,590	)
Net deferred tax liability	$	(129,994	)	$	(242,660	)
Current asset	$	128,816		$	76,823
Long-term liability		(258,810	)		(319,483	)
	$	(129,994	)	$	(242,660	)

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Tax carryforwards at December 31, 2005, which are available for future utilization on income tax returns, are as follows (in thousands):

FEDERAL	Amount		Expiration
Alternative minimum tax (AMT) credit	$	4,032
Enhanced Oil Recovery credit		75,710	2020-2025
Net Operating Loss—regular Tax		196,287	2018-2024
Net Operating Loss—AMT Tax		171,874	2018-2024
STATE
Alternative minimum tax (AMT) credit	$	303
Enhanced Oil Recovery credit		27,366	2014-2020
Net Operating Loss—regular Tax		80,857	2010-2014
Net Operating Loss—AMT Tax		79,473	2010-2014

The tax attributes related to the purchase of Nuevo are subject to statutory limitation under Internal Revenue Code Section 382 on the amount that can be used each year. We do not expect the limitation to materially impact our ability to use such attributes.

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

	Year Ended December 31,
	2005			2004			2003
U.S. federal income tax provision at statutory rate	$	(120,704	)	$	708		$	35,253
State income taxes, net of federal benefit		(13,201	)		788			5,512
EOR credits		(19,637	)		(9,547	)		(828	)
Non-deductible expenses		18,981			4,012			290
Other		3,703			(2,778	)		1,085
Income tax expense (benefit) on income before income taxes and cumulative effect of accounting change		(130,858	)		(6,817	)		41,312
Income tax benefit allocated to cumulative effect of accounting change		—			—			(7,860	)
Income tax provision	$	(130,858	)	$	(6,817	)	$	33,452

A deferred tax benefit related to non-cash employee compensation of $2.7 million, $1.2 million and $0.2 million was allocated directly to goodwill and/or additional paid-in capital in 2005, 2004 and 2003, respectively.

F-25

Until the date of the spin-off on December 18, 2002, our taxable income or loss was included in the consolidated income tax returns filed by Plains Resources. Income tax obligations reflected in these financial statements with respect to such returns are based on the tax sharing agreement that provides that income taxes are calculated assuming we filed a separate combined income tax return.

Under the terms of a tax allocation agreement, we have agreed to indemnify Plains Resources if the spin-off is not tax-free to Plains Resources as a result of various actions taken by us or with respect to our failure to take various actions. We may not be able to control some of the events that could trigger this indemnification obligation.

To reflect differences between the amounts included in our financial statements at December 31, 2002 and the final 2002 tax returns filed by us and Plains Resources, income tax expense for the year ended December 31, 2003 includes a $1.7 million charge (a $3.8 million deferred tax expense that includes a $1.7 million adjustment to reflect an increase in our effective state income tax rate, partially offset by a $2.1 million current tax benefit). Such adjustments resulted in a $6.9 million decrease in our Additional Paid-in Capital.

The Company has determined that EOR tax credits are available for 2004 and certain prior tax years of Nuevo Energy Company. EOR tax credits reduce the Company’s tax liability down to its alternative minimum tax liability. EOR tax credits are subject to a phase-out according to the level of average domestic crude prices. No phase-out occurred in 2005. However, as a result of the increase in oil prices in 2005, based on current rules, the Company will not earn EOR credits in 2006.

Note 9—Property Divestments

We periodically evaluate and from time to time have elected to sell certain of our mature producing properties that we consider to be nonstrategic. In May 2005 we closed the sale of interests in certain producing properties located in east Texas and Oklahoma for net proceeds of approximately $341 million. The proceeds were primarily used to fund the transactions to eliminate all of our 2006 oil price swaps and collars as discussed in Note 3.

In December 2004, we completed the sale of certain properties located offshore California and onshore south Texas, New Mexico, and south Louisiana. These unrelated divestments were conducted via negotiated and auction transactions and we received net proceeds of approximately $152 million. 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.

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.

Prior to our acquisition of Nuevo, Nuevo sold its Tonner Hills real estate property and received $40.7 million of the purchase price with the remainder due upon completion of certain habitat restoration activities. We completed the required restoration and in the second quarter of 2005 we received the $6.5 million due under the terms of the agreement. The fair value of our investment in the property at December 31, 2004 is reflected on the balance sheet in current assets under the caption assets held for sale and the $40.7 million that had been received as of that date is reflected on the balance sheet in current liabilities, as such amounts were accounted for as deposits until the completion of the habitat restoration activities.

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

F-26

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 in July 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.

Note 10—Commitments, Contingencies and Industry Concentration

Commitments and Contingencies

Operating leases.    We lease certain real property, equipment and operating facilities under various operating leases. Future noncancellable commitments related to these leases are as follows (in thousands):

2006	$	3,828
2007		3,267
2008		3,125
2009		2,411
2010		1,972
Thereafter		5,568

Total expenses related to such leases were $3.4 million, $3.7 million and $2.2 million in 2005, 2004 and 2003, respectively.

Environmental matters.    As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state, and local laws and regulations relating to discharge of materials into, and protection of, the environment. Often these regulations are more burdensome on older properties that were operated before the regulations came into effect such as some of our properties in California that have operated for over 90 years. We have established policies for continuing compliance with environmental laws and regulations. We also maintain insurance coverage for environmental matters, which we believe is customary in the industry, but we are not fully insured against all environmental risks. There can be no assurance that current or future local, state or federal rules and regulations will not require us to spend material amounts to comply with such rules and regulations.

In January 2005 we discovered and self-reported a violation related to flared gas emissions in excess of permitted levels on properties acquired in the Nuevo acquisition. Estimated excess emissions from the San Joaquin Valley casing vent recovery system located on the Gamble Lease were approximately 881 tons over a 745 day period. We brought the facility into compliance within 10 days of discovering the violation. We settled this matter in 2005 for $750,000.

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 the purchaser 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. We cannot assure you that we will be able to collect on these indemnities.

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

F-27

existing offshore platforms. The present value of such abandonment costs, $38 million ($78 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). The fair value of our obligation, $0.5 million, is included in Other Long-Term Liabilities in the Consolidated Balance Sheet.

Operating risks and insurance coverage.    Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and gas, including well blowouts, cratering, explosions, oil spills, releases of gas or well fluids, fires, pollution and releases of toxic gas, each of which could result in damage to or destruction of oil and gas wells, production facilities or other property, or injury to persons. Our operations in California, including transportation of oil by pipelines within the city and county of Los Angeles, are especially susceptible to damage from earthquakes and involve increased risks of personal injury, property damage and marketing interruptions because of the population density of southern California. Although we maintain insurance coverage considered to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of high premium costs. We maintain coverage for earthquake damages in California but this coverage may not provide for the full effect of damages that could occur and we may be subject to additional liabilities. The occurrence of a significant event that is not fully insured against could have a material adverse effect on our financial position. Our insurance does not cover every potential risk associated with operating our pipelines, including the potential loss of significant revenues. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences.

Sale of Nuevo’s Congo operations.    Upon our acquisition of Nuevo, we became a party to an existing agreement between Nuevo, CMS NOMECO Oil & Gas Co. (CMS) and a third party. Under the agreement, Nuevo and CMS may be liable to the third party for the recapture of dual consolidated losses (DCLs) in connection with each company’s 1995 acquisition of Congolese properties. Nuevo and CMS agreed to indemnify each other for any act that would cause the third party to experience a liability from the recapture of DCLs as a result of a triggering event.

CMS sold its interest in the Congolese properties to a subsidiary of Perenco, S.A. (Perenco) in 2002. Both CMS and Perenco, have received from the Internal Revenue Service (IRS), in accordance with the U.S. consolidated return regulations, a closing agreement confirming that the transaction will not trigger recapture. We and Perenco have finalized closing agreements with the IRS confirming that neither our merger with Nuevo, nor the sale of our interest in the Congolese properties to Perenco will trigger recapture. The estimated remaining contingent liabilities are $15.2 million relative to Nuevo’s former interest, and $21.4 million relative to CMS’ former interest, for which we would be jointly liable. We believe the occurrence of a triggering event in the future is remote and we do not believe the agreements will have a material adverse affect upon us.

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

On November 15, 2005, the United States Court of Federal Claims issued a ruling granting the plaintiffs’ motion for summary judgment as to liability and partial summary judgment as to damages in the breach of contract lawsuitAmber Resources Company et al. v. United States, Case No. 02-30c. The Court’s ruling also denied the United States’ motion to dismiss and motion for summary judgment.

F-28

The United States Court of Federal Claims ruled that the federal government’s imposition of new and onerous requirements that stood as a significant obstacle to oil and gas development breached agreements that it made when it sold 36 federal leases offshore California. The Court further ruled that the Government must give back to the current lessees the more than $1.1 billion in lease bonuses it had received at the time of sale. The final ruling in the case will not be made until the Court addresses the plaintiffs’ additional claims regarding the hundreds of millions of dollars that have been spent in the successful efforts to find oil and gas in the disputed lease area, and other matters. The final ruling, including the rulings made on November 15, 2005 will be subject to appeal, and no payments will be made until all appeals have either been waived or exhausted. We are among the current lessees of the 36 leases. Our share of the $1.1 billion award is in excess of $80 million.

We are a defendant in various other 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.

Industry Concentration

Financial instruments which potentially subject us to concentrations of credit risk consist principally of accounts receivable with respect to our oil and gas operations and derivative instruments related to our hedging activities. During 2005, 2004 and 2003 sales to PAA accounted for approximately 38%, 33% and 70%, respectively, of our total revenues and during 2005 and 2004 sales to ConocoPhillips accounted for approximately 44% and 33%, respectively, 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. We generally do not require letters of credit or other collateral from PAA or from ConocoPhillips to support 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.

The seven financial institutions that are contract counterparties for our derivative commodity contracts all have Standard & Poor’s ratings of A or better and all seven of the financial institutions are participating lenders in our revolving credit facility. At December 31, 2005 we were in a net liability position with all such counterparties.

There are a limited number of alternative 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 which could have a negative impact on future results of operations or cash flows.

Note 11—Financial instruments

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standards No. 107, Disclosures About Fair

F-29

Value of Financial Instruments (“SFAS 107”). The estimated fair value amounts have been determined using available market information and valuation methodologies described below. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

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

	December 31, 2005
	Carrying Amount		Fair Value
Long-Term Debt
Senior revolving credit facility	$	272,000	$	272,000
7.125% Notes		248,837		258,800
8.75% Notes		276,538		296,300

The carrying value of bank debt approximates its fair value, as interest rates are variable, based on prevailing market rates. The fair value of the 7.125% Notes and the 8.75% Notes is based on quoted market prices based on trades of such debt.

Note 12—Supplemental Cash Flow Information

Cash payments for interest and income taxes were (in thousands of dollars):

	Year Ended December 31,
	2005		2004		2003
Cash payments for interest	$	54,574	$	29,515	$	32,364
Cash payments for income taxes	$	2,141	$	2,305	$	5,534

Common stock issued for no cash payment in connection with compensation plans (amounts in thousands):

	Year Ended December 31,
	2005		2004		2003
Shares		969		328		107
Amount	$	17,098	$	3,855	$	1,071

The Nuevo acquisition involved non-cash consideration as follows (in thousands of dollars):

Common stock issued	$	575,023
Stock options assumed		4,389
Senior Subordinated Notes		162,945
Bank Credit Facility		140,000
TECONS		103,815
Current liabilities		255,733
Other noncurrent liabilities		33,583
Deferred income tax liabilities		221,803
Asset retirement obligation		128,053
	$	1,625,344

F-30

The 3TEC acquisition involved non-cash consideration as follows (in thousands of dollars):

Fair value of common stock issued	$	152,186
Current liabilities assumed		73,570
Other long-term liabilities assumed		4,831
Deferred income tax liability		40,281
	$	270,868

Note 13—Oil and natural gas activities

Costs incurred

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

	Year Ended December 31,
	2005		2004		2003
Property acquisitions costs
Unproved properties
Nuevo acquisition	$	—	$	137,457	$	—
3TEC acquisition		—		—		61,116
Other		16,682		7,437		19,025
Proved properties
Nuevo acquisition
Asset retirement cost		—		128,053		—
Other		—		1,079,967		—
3TEC acquisition
Asset retirement cost		—		—		4,577
Other		—		—		289,779
Other		134,696		2,738		1,197
Exploration costs		129,066		57,530		8,947
Exploitation and development costs (1)		300,439		141,198		101,334
	$	580,883	$	1,554,380	$	485,975

(1) Amounts presented for 2003 do not include the cumulative effect adjustment for the January 1, 2003 adoption of SFAS 143 of $15.9 million.

Amounts presented include capitalized general and administrative expense of $24.5 million, $16.2 million and $11.0 million in 2005, 2004 and 2003, respectively, and capitalized interest expense of $3.5 million, $7.0 million and $3.2 million in 2005, 2004 and 2003, respectively.

F-31

Capitalized costs

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

	December 31,
	2005			2004
Proved properties	$	2,604,892		$	2,402,179
Accumulated DD&A		(493,835	)		(319,745	)
	$	2,111,057		$	2,082,434

The average DD&A rate per equivalent unit of production was $7.39, $5.93 and $3.86 in 2005, 2004 and 2003, respectively.

Costs not subject to amortization

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

	December 31,
	2005		2004		2003
Acquisition costs	$	80,989	$	67,380	$	44,135
Exploration costs		23,367		6,725		12,489
Capitalized interest		7,848		5,300		7,034
	$	112,204	$	79,405	$	63,658

Unproved property costs not subject to amortization consist of acquisition costs related to unproved areas, exploration costs and capitalized interest. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves established or impairment determined. We will continue to evaluate these properties and costs will be transferred into the amortization base as the undeveloped areas are tested. Due to the nature of the reserves, the ultimate evaluation of the properties will occur over a period of several years. We expect that 71% of the costs not subject to amortization at December 31, 2005 will be transferred to the amortization base over the next three years and the remainder within the next seven years. The majority of the leases covering the properties are held by production and will not limit the time period for evaluation. Approximately 39%, 41%, 13% and 7% of the balance in unproved properties at December 31, 2005, related to additions made in 2005, 2004, 2003 and prior periods, respectively.

Results of operations for oil and gas producing activities

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

	Year Ended December 31,
	2005			2004			2003
Revenues from oil and gas producing activities	$	944,420		$	671,706		$	304,090
Production costs		(285,292	)		(223,080	)		(104,819	)
Depreciation, depletion, amortization and accretion		(181,609	)		(144,093	)		(50,142	)
Income tax expense		(187,210	)		(120,106	)		(58,996	)
Results of operations from producing activities (excluding general and administrative and interest costs)	$	290,309		$	184,427		$	90,133

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Supplemental reserve information (unaudited)

The following information summarizes our net proved reserves of oil (including condensate and natural gas liquids) and gas and the present values thereof for the three years ended December 31, 2005. The following reserve information is based upon reports of the independent petroleum consulting firms of Netherland, Sewell & Associates, Inc. in 2005 and 2004 and Netherland, Sewell & Associates, Inc. and Ryder Scott Company in 2003. The estimates are in accordance with SEC regulations.

Management believes the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation principles consistently applied, are reasonable. However, there are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree speculative, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the Standardized Measure shown below represents estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent exploitation and development activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices.

Decreases in the prices of oil and natural gas have had, and could have in the future, an adverse effect on the carrying value of our proved reserves, reserve volumes and our revenues, profitability and cash flow. A significant portion of our reserve base (approximately 89% of year-end 2005 reserve volumes) is comprised of oil properties that are sensitive to crude oil price volatility.

Estimated quantities of oil and natural gas reserves (unaudited)

The following table sets forth certain data pertaining to our proved and proved developed reserves for the three years ended December 31, 2005 (in thousands).

	As of or for the Year Ended December 31,
	2005				2004				2003
	Oil (MBbl)		Gas (MMcf)		Oil (MBbl)		Gas (MMcf)		Oil (MBbl)		Gas (MMcf)
Proved Reserves
Beginning balance	351,403		407,400		227,728		319,177		240,161		77,154
Revision of previous estimates	(13,002	)	3,518		(138	)	(27,773	)	(9,009	)	(12,844	)
Extensions, discoveries and other additions	747		21,530		20,980		47,677		2,749		31,529
Improved recovery	20,134		752		10,225		2,617		—		—
Purchase of reserves in-place	17,314		12,038		161,068		162,527		5,421		249,301
Sale of reserves in-place	(1,592	)	(147,958	)	(52,019	)	(58,235	)	(2,327	)	(7,768	)
Production	(18,671	)	(29,359	)	(16,441	)	(38,590	)	(9,267	)	(18,195	)
Ending balance	356,333		267,921		351,403		407,400		227,728		319,177
Proved Developed Reserves
Beginning balance	233,707		305,009		124,822		235,070		127,415		53,317
Ending balance	234,638		193,904		233,707		305,009		124,822		235,070

F-33

Standardized measure of discounted future net cash flows (unaudited)

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

	December 31,
	2005			2004			2003
Future cash inflows	$	20,133,050		$	13,106,450		$	8,190,872
Future development costs		(1,536,196	)		(1,205,386	)		(529,920	)
Future production expense		(8,314,665	)		(4,991,280	)		(3,041,607	)
Future income tax expense		(3,509,378	)		(2,258,064	)		(1,579,078	)
Future net cash flows		6,772,811			4,651,720			3,040,267
Discounted at 10% per year		(3,690,645	)		(2,415,001	)		(1,783,464	)
Standardized measure of discounted future net cash flows	$	3,082,166		$	2,236,719		$	1,256,803

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

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

2. In accordance with SEC guidelines, the engineers’ estimates of future net revenues from our proved properties and the present value thereof are made using oil and gas sales prices in effect at December 31 of the year presented and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. We have entered into various arrangements to fix or limit the prices for a portion of our oil and gas production. Arrangements in effect at December 31, 2005 are discussed in Note 3. Such arrangements are not reflected in the reserve reports. The overall average year-end prices used in the reserve reports as of December 31, 2005, 2004 and 2003 were $51.40, $30.91 and $28.22 per barrel of oil, respectively, and $6.99, $5.40 and $5.53 per Mcf of gas, respectively.

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

4. Future income taxes were calculated by applying the statutory federal and state income tax rate to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to oil and gas operations.

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The principal sources of changes in the Standardized Measure of the future net cash flows for the three years ended December 31, 2005, are as follows (in thousands):

	Year Ended December 31,
	2005			2004			2003
Balance, beginning of year	$	2,236,719		$	1,256,803		$	883,507
Sales, net of production expenses		(797,622	)		(598,197	)		(235,948	)
Net change in sales and transfer prices, net of production expenses		2,284,096			258,819			(1,657	)
Changes in estimated future development costs		(304,045	)		(39,759	)		(2,172	)
Extensions, discoveries and improved recovery, net of costs		283,222			414,055			107,922
Previously estimated development costs incurred during the year		224,338			49,823			46,957
Purchase of reserves in-place		240,725			1,481,958			635,604
Sale of reserves in-place		(276,255	)		(370,620	)		(42,022	)
Revision of quantity estimates		(558,470	)		(13,020	)		(205,829	)
Accretion of discount		266,113			189,590			151,403
Net change in income taxes		(516,655	)		(392,733	)		(80,962	)
Balance, end of year	$	3,082,166		$	2,236,719		$	1,256,803

Note 14—Quarterly Financial Data (Unaudited)

The following table shows summary financial data for 2005 and 2004 (in thousands, except per share data):

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter		Year
2005
Revenues	$	190,075		$	217,308		$	262,619		$	274,418	$	944,420
Operating profit		78,272			99,791			149,356			143,794		471,213
Net income (loss)		(205,618	)		(47,330	)		(31,849	)		70,785		(214,012	)
Basic earnings (loss) per share		(2.66	)		(0.61	)		(0.41	)		0.90		(2.75	)
Diluted earnings (loss) per share		(2.66	)		(0.61	)		(0.41	)		0.90		(2.75	)
2004
Revenues	$	92,961		$	152,770		$	210,361		$	215,614	$	671,706
Operating profit		45,545			71,823			87,391			95,882		300,641
Net income (loss)		10,398			18,893			(47,978	)		27,527		8,840
Basic earnings (loss) per share		0.26			0.32			(0.62	)		0.36		0.14
Diluted earnings (loss) per share		0.26			0.32			(0.62	)		0.35		0.14

Note 15—Consolidating Financial Statements

We are the issuer of the 8.75% Notes and 7.125% Notes discussed in Note 5. The 8.75% Notes and 7.125% Notes are jointly and severally guaranteed on a full and unconditional basis by our wholly-owned subsidiaries (referred to as “Guarantor Subsidiaries”).

The following financial information presents consolidating financial statements, which include:

• PXP (the “Issuer”);

• the guarantor subsidiaries on a combined basis (“Guarantor Subsidiaries”);

• elimination entries necessary to consolidate the Issuer and Guarantor Subsidiaries; and

• PXP on a consolidated basis.

F-35

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2005

(in thousands)

				Guarantor			Intercompany
	Issuer			Subsidiaries			Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	1,548		$	4		$	—		$	1,552
Accounts receivable and other current assets		247,721			44,059			—			291,780
		249,269			44,063			—			293,332
Property and Equipment, at cost
Oil and natural gas properties—full cost method
Subject to amortization		2,126,960			477,932			—			2,604,892
Not subject to amortization		73,987			38,217			—			112,204
Other property and equipment		15,375			907			—			16,282
		2,216,322			517,056			—			2,733,378
Less allowance for depreciation, depletion and amortization		(305,510	)		(192,565	)		—			(498,075	)
		1,910,812			324,491			—			2,235,303
Investment in and Advances to Subsidiaries		458,984			—			(458,984	)		—
Other Assets		50,412			162,895			—			213,307
	$	2,669,477		$	531,449		$	(458,984	)	$	2,741,942
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities	$	199,508		$	78,894		$	—		$	278,402
Commodity derivative contracts		85,596			—			—			85,596
		285,104			78,894			—			363,998
Long-Term Debt		797,375			—			—			797,375
Other Long-Term Liabilities		573,848			29,574			—			603,422
Payable to Parent		—			103,526			(103,526	)		—
Deferred Income Taxes		294,813			(36,003	)		—			258,810
Stockholders’ Equity
Stockholders’ equity		807,903			386,229			(386,229	)		807,903
Accumulated other comprehensive income		(89,566	)		(30,771	)		30,771			(89,566	)
		718,337			355,458			(355,458	)		718,337
	$	2,669,477		$	531,449		$	(458,984	)	$	2,741,942

F-36

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2004

(in thousands)

	Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	876		$	669		$	—		$	1,545
Accounts receivable and other current assets		215,668			40,954			—			256,622
		216,544			41,623			—			258,167
Property and Equipment, at cost
Oil and natural gas properties—full cost method
Subject to amortization		1,817,709			584,470			—			2,402,179
Not subject to amortization		39,707			39,698			—			79,405
Other property and equipment		11,963			583			—			12,546
		1,869,379			624,751			—			2,494,130
Less allowance for depreciation, depletion and amortization		(209,224	)		(113,817	)		—			(323,041	)
		1,660,155			510,934			—			2,171,089
Investment in and Advances to Subsidiaries		612,538			—			(612,538	)		—
Other Assets		54,227			149,762			—			203,989
	$	2,543,464		$	702,319		$	(612,538	)	$	2,633,245
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and other current liabilities	$	210,366		$	40,556		$	—		$	250,922
Commodity derivative contracts		172,800			2,673			—			175,473
		383,166			43,229			—			426,395
Long-Term Debt		635,468			—			—			635,468
Other Long-Term Liabilities		340,271			41,253			—			381,524
Payable to Parent		—			307,820			(307,820	)		—
Deferred Income Taxes		314,184			5,299			—			319,483
Stockholders’ Equity
Stockholders’ equity		994,249			353,629			(353,629	)		994,249
Accumulated other comprehensive income		(123,874	)		(48,911	)		48,911			(123,874	)
		870,375			304,718			(304,718	)		870,375
	$	2,543,464		$	702,319		$	(612,538	)	$	2,633,245

F-37

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME

YEAR ENDED DECEMBER 31, 2005

(in thousands)

				Guarantor			Intercompany
	Parent			Subsidiaries			Eliminations			Consolidated
Revenues
Oil sales	$	651,689		$	82,343		$	—		$	734,032
Gas sales		56,292			150,444			—			206,736
Other operating revenues		2,854			798			—			3,652
		710,835			233,585			—			944,420
Costs and Expenses
Production costs		213,594			71,698			—			285,292
General and administrative		121,586			5,927			—			127,513
Depreciation, depletion, amortization and accretion		107,789			80,126			—			187,915
		442,969			157,751			—			600,720
Income from Operations		267,866			75,834			—			343,700
Other Income (Expense)
Equity in earnings of subsidiaries		32,600			—			(32,600	)		—
Interest expense		(40,690	)		(14,731	)		—			(55,421	)
Gain (loss) on mark-to-market derivative contracts		(636,473	)		—			—			(636,473	)
Interest and other income (expense)		3,324			—			—			3,324
Income (Loss) Before Income Taxes		(373,373	)		61,103			(32,600	)		(344,870	)
Income tax benefit (expense)
Current		80,104			(79,875	)		—			229
Deferred		79,257			51,372			—			130,629
Net Income (Loss)	$	(214,012	)	$	32,600		$	(32,600	)	$	(214,012	)

F-38

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME

YEAR ENDED DECEMBER 31, 2004

(in thousands)

	Parent			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	386,060		$	61,996		$	—		$	448,056
Gas sales		41,908			179,452			—			221,360
Other operating revenues		1,211			1,079			—			2,290
		429,179			242,527			—			671,706
Costs and Expenses
Production costs		159,129			63,951			—			223,080
General and administrative		80,452			4,745			—			85,197
Provision for legal and regulatory settlements		1,520			5,325			—			6,845
Depreciation, depletion, amortization and accretion		74,951			73,034			—			147,985
		316,052			147,055			—			463,107
Income from Operations		113,127			95,472			—			208,599
Other Income (Expense)
Equity in earnings of subsidiaries		46,774			—			(46,774	)		—
Interest expense		(22,854	)		(14,440	)		—			(37,294	)
Gain (loss) on mark-to-market derivative contracts		(148,043	)		(2,271	)		—			(150,314	)
Debt extinguishment costs		(19,691	)		—			—			(19,691	)
Interest and other income (expense)		797			(74	)		—			723
Income (Loss) Before Income Taxes		(29,890	)		78,687			(46,774	)		2,023
Income tax benefit (expense)
Current		19,032			(19,407	)		—			(375	)
Deferred		19,698			(12,506	)		—			7,192
Net Income	$	8,840		$	46,774		$	(46,774	)	$	8,840

F-39

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME

YEAR ENDED DECEMBER 31, 2003

(in thousands)

				Guarantor			Intercompany
	Parent			Subsidiaries			Eliminations			Consolidated
Revenues
Oil sales	$	129,359		$	68,789		$	—		$	198,148
Gas sales		15,798			89,256			—			105,054
Other operating revenues		—			888			—			888
		145,157			158,933			—			304,090
Costs and Expenses
Production costs		52,677			52,142			—			104,819
General and administrative		38,628			4,530			—			43,158
Depreciation, depletion, amortization and accretion		19,960			32,524			—			52,484
		111,265			89,196			—			200,461
Income from Operations		33,892			69,737			—			103,629
Other Income (Expense)
Equity in earnings of subsidiaries		51,886			—			(51,886	)		—
Interest expense		(20,618	)		(3,160	)		—			(23,778	)
Gain (loss) on mark-to-market derivative contracts		—			847			—			847
Interest and other income (expense)		(168	)		9			—			(159	)
Income Before Income Taxes and Cumulative Effect of Accounting Change		64,992			67,433			(51,886	)		80,539
Income tax benefit (expense)
Current		9,111			(10,335	)		—			(1,224	)
Deferred		(27,016	)		(5,212	)		—			(32,228	)
Income Before Cumulative Effect of Accounting Change		47,087			51,886			(51,886	)		47,087
Cumulative effect of accounting change, net of tax		12,324			645			(645	)		12,324
Net Income	$	59,411		$	52,531		$	(52,531	)	$	59,411

F-40

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2005

(in thousands)

	Parent			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(214,012	)	$	32,600		$	(32,600	)	$	(214,012	)
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion		107,789			80,126			—			187,915
Equity in earnings of subsidiaries		(32,600	)		—			32,600			—
Deferred income taxes		(79,257	)		(51,372	)		—			(130,629	)
Commodity derivative contracts
Loss (gain) on derivatives		249,468			50,684			—			300,152
Reclassify financing derivative settlements		453,443			6,007			—			459,450
Noncash compensation											—
Stock appreciation rights		17,354			—			—			17,354
Other		37,917			—			—			37,917
Other noncash items		(93	)		—			—			(93	)
Change in assets and liabilities from operating activities, net of effect of acquisitions
Accounts receivable and other assets		(16,636	)		(14,777	)		—			(31,413	)
Accounts payable and other liabilities		(20,275	)		(3,994	)		—			(24,269	)
Commodity derivative contracts		(139,038	)		—			—			(139,038	)
Net cash provided by operating activities		364,060			99,274			—			463,334
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(295,730	)		(213,397	)		—			(509,127	)
Proceeds from sales of properties		9,345			337,105			—			346,450
Other property and equipment		(5,419	)		(324	)		—			(5,743	)
Net cash (used in) provided by investing activities		(291,804	)		123,384			—			(168,420	)
CASH FLOWS FROM FINANCING ACTIVITIES
Revolving credit facilities
Borrowings		1,504,200			—			—			1,504,200
Repayments		(1,342,200	)		—			—			(1,342,200	)
Costs incurred in connection with financing arrangements		(1,600	)		—			—			(1,600	)
Derivative settlements		(453,443	)		(6,007	)		—			(459,450	)
Investment in and advances to affiliates		217,316			(217,316	)		—			—
Other		4,143			—			—			4,143
Net cash used in financing activities		(71,584	)		(223,323	)		—			(294,907	)
Net increase (decrease) in cash and cash equivalents		672			(665	)		—			7
Cash and cash equivalents, beginning of period		876			669			—			1,545
Cash and cash equivalents, end of period	$	1,548		$	4		$	—		$	1,552

F-41

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2004

(in thousands)

	Parent			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	8,840		$	46,774		$	(46,774	)	$	8,840
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion		74,951			73,034			—			147,985
Equity in earnings of subsidiaries		(46,774	)		—			46,774			—
Deferred income taxes		(19,698	)		12,506			—			(7,192	)
Debt extinguishment costs		(4,453	)		—			—			(4,453	)
Commodity derivative contracts
Loss (gain) on derivatives		64,395			(14,554	)		—			49,841
Reclassify financing derivative settlements		103,521			—			—			103,521
Non-cash compensation
Stock appreciation rights		20,268			—			—			20,268
Other		8,092			—			—			8,092
Other noncash items		(144	)		—			—			(144	)
Change in assets and liabilities from operating activities, net of effect of acquisitions
Accounts receivable and other assets		804			(18,733	)		—			(17,929	)
Accounts payable and other liabilities		32,399			21,991			—			54,390
Net cash provided by operating activities		242,201			121,018			—			363,219
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(99,522	)		(111,865	)		—			(211,387	)
Acquisition of Nuevo Energy Company, net of cash acquired		(14,156	)		—			—			(14,156	)
Proceeds from sales of properties		211,173			27,816			—			238,989
Other property and equipment		(7,633	)		(399	)		—			(8,032	)
Net cash (used in) provided by investing activities		89,862			(84,448	)		—			5,414
CASH FLOWS FROM FINANCING ACTIVITIES
Revolving credit facilities
Borrowings		1,044,850			—			—			1,044,850
Repayments		(1,145,850	)		—			—			(1,145,850	)
Proceeds from issuance of 7.125% Senior Notes		248,695			—			—			248,695
Retirement of debt assumed in acquisition of Nuevo Energy Company		(405,000	)		—			—			(405,000	)
Costs incurred in connection with financing arrangements		(9,325	)		—			—			(9,325	)
Derivative settlements		(103,521	)		—			—			(103,521	)
Investment in and advances to affiliates		36,875			(36,875	)		—			—
Other		1,686			—			—			1,686
Net cash used in financing activities		(331,590	)		(36,875	)		—			(368,465	)
Net increase (decrease) in cash and cash equivalents		473			(305	)		—			168
Cash and cash equivalents, beginning of period		403			974			—			1,377
Cash and cash equivalents, end of period	$	876		$	669		$	—		$	1,545

F-42

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2003

(in thousands)

	Parent			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	59,411		$	52,531		$	(52,531	)	$	59,411
Items not affecting cash flows from operating activities:
Depreciation, depletion, amortization and accretion		19,960			32,524			—			52,484
Equity in earnings of subsidiaries		(51,886	)		—			51,886			—
Deferred income taxes		27,016			5,212			—			32,228
Loss (gain) on derivative contracts		—			(847	)		—			(847	)
Cumulative effect of adoption of accounting change		(12,324	)		(645	)		645			(12,324	)
Noncash compensation
Stock appreciation rights		15,895			—			—			15,895
Other		1,190			—			—			1,190
Other noncash items		123			—			—			123
Change in assets and liabilities from operating activities:
Accounts receivable and other assets		(10,509	)		7,052			—			(3,457	)
Accounts payable and other liabilities		11,488			(37,913	)		—			(26,425	)
Net cash provided by operating activities		60,364			57,914			—			118,278
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(49,057	)		(73,013	)		—			(122,070	)
Acquisition of 3TEC Energy Corporation, net of cash acquired		—			(267,546	)		—			(267,546	)
Proceeds from sales of properties		—			23,420			—			23,420
Other property and equipment		(2,322	)		(192	)		—			(2,514	)
Net cash (used in) provided by investing activities		(51,379	)		(317,331	)		—			(368,710	)
CASH FLOWS FROM FINANCING ACTIVITIES
Revolving credit facilities
Borrowings		471,600			—			—			471,600
Repayments		(296,400	)		—			—			(296,400	)
Proceeds from issuance of 8.75% Senior Subordinated Notes		80,061			—			—			80,061
Costs incurred in connection with financing arrangements		(4,349	)		—			—			(4,349	)
Investment in and advances to affiliates		(260,367	)		260,367			—			—
Other		(131	)		—			—			(131	)
Net cash (used in) provided by financing activities		(9,586	)		260,367			—			250,781
Net increase (decrease) in cash and cash equivalents		(601	)		950			—			349
Cash and cash equivalents, beginning of period		1,004			24			—			1,028
Cash and cash equivalents, end of period	$	403		$	974		$	—		$	1,377

F-43