10-K

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.  Yes þ    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 ¨    No þ

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

Indicate by check mark 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 ¨    No þ

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 at www.sec.gov. No information from the SEC’s website is incorporated by

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reference herein. Our website is www.plainsxp.com. You may also obtain copies of our annual, quarterly and current reports, proxy statements and certain other information filed with the SEC, as well as amendments 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 lawsuit Amber 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 risk management 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 in Internal 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 in Internal 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 lawsuit Amber 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

EX-10.3

Exhibit 10.3

CONSULTING AGREEMENT

This Consulting Agreement (the “Agreement”) is entered into as of January 19, 2006 by and between by and between Montebello Land Company LLC (the “Company”), a wholly owned subsidiary of Plains Exploration & Production Company (“PXP”), and Cook Hill Properties LLC (“Consultant”).

BACKGROUND:

A. PXP will contribute to the Company that certain surface estate of three tracts of land comprising approximately 480 acres located in the City of Montebello, Los Angeles County, California as more fully described on Exhibit A (the “Montebello Surface Estate”), and PXP will retain all right, title and interest in and to any Mineral Rights (as defined below).

B. Consultant has a management team with expertise in the entitlement and development of residential communities in Southern California and the Company desires that Consultant assist the Company with the entitlement and development of the Montebello Surface Estate and Consultant desires to do so.

AGREEMENT:

NOW, THEREFORE, in consideration of the foregoing and the respective representations, warranties, covenants and agreements set forth in this Agreement, the parties hereto agree as follows:

ARTICLE I

DEFINITIONS

“Costs” means the following: all costs, expenses, fees, charges and losses related to and applicable to the Montebello Surface Estate which are, or are to be, or have been, paid, delivered and/or incurred by the Company, by DevelopmentCo or by PXP, whether before or after any Entitlements are obtained (without duplication), including, without limitation: (i) all costs, fees and expenses relating to Entitlements, (ii) all salaries and other general and administrative and operating expenses of the Company and DevelopmentCo (including expense reimbursements paid under this Agreement with respect to the Consultant Services), but not including any salaries or other expenses of PXP personnel, (iii) expenses, fees and costs relating to the ownership, development, entitlement, improvement, subdivision, management and land preparation of the Montebello Surface Estate, including costs, expenses, fines or other liabilities arising out of any suits, claims, administrative or other proceedings against Company or its affiliates and equity holders relating to the Montebello Surface Estate imposed or initiated by a governmental authority or any other person or entity; provided, that this clause (iii) shall not include any costs, expenses, fines or other liabilities arising out of any suits, claims, administrative or other proceedings relating to (a) PXP’s exploitation of the Mineral

1

Rights or (b) Excluded Mineral Rights Costs, (iv) all property taxes (excluding those applicable to the Mineral Rights), (v) all costs, fines and expenses of any environmental clean-up or remediation of the Montebello Surface Estate (other than Excluded Mineral Rights Costs), including liabilities arising out of any suits, claims, administrative or other proceedings relating thereto, (vi) expenses incurred in connection with the collection of any amounts owed to the Company by any person, (vii) all professional fees, including attorneys, accountants, agents, appraisers, consultants, environmental experts and other consultants, incurred in connection with the ownership, development, entitlement, improvement, subdivision, management, or land preparation of the Montebello Surface Estate, (viii) all financing costs and fees, including interest, points and loan fees, and amounts payable by the Company to any third party in connection with any form of equity financing or investment by third party in connection with the development and maintenance of the Montebello Surface Estate; provided, that this clause (viii) shall not include any such financing that is non-recourse to PXP, (ix) a consulting fee to Lodwrick Cook of $29,166.67 per month; and (x) all costs associated with any sale, disposition or transfer (or any proposed sale, disposition or transfer) of any portion of the Montebello Surface Estate, including marketing, legal and accounting fees, brokerage fees, sale commissions, bank charges, transfer fees, custodial fees, costs, closing costs, escrow fees, and other related costs and expenses. Notwithstanding the foregoing, it is agreed that (a) costs incurred to the date hereof shall not exceed $2.5 million in the aggregate, (b) the Entitlement Fee (as defined in Section 4.1) shall not be included in the definition of Costs and (c) Costs shall not include any costs, expenses, fees, charges and losses incurred by DevelopmentCo or PXP relating to the ownership, development and entitlement of PXP’s real property located in Santa Barbara County, California and in San Luis Obispo County, California which are included in “Costs” under either of the respective Consulting Agreements entered into as of even date herewith.

“DevelopmentCo” means Cane River Development LLC, a Delaware limited liability company.

“Entitlement” means that the Company has obtained all of the Entitlements.

“Entitlements” means all permits, licenses, approvals and other administrative certifications and satisfaction of other requirements (federal, state and local) as may be reasonably necessary to commence and carry out the development of the Montebello Surface Estate as a residential project, in accordance with such development plans and development budgets as may be, from time to time, proposed by the Consultant and approved by the Company in the Company’s reasonable discretion as evidenced by formal written resolutions of the Company. Without limiting the scope of the forgoing, Entitlements shall include the following permits, licenses, approvals and other administrative certifications: (i) the Final Environmental Assessment/§404 Permit to be issued by the U. S. Army Corps of Engineers; (ii) final permits from the Regional Water Quality Control Board and the California Department of Fish & Game; (iii) a final Environmental Impact Report to be issued by the City of Montebello, California; (iv) the final Development Agreement (including A level and final B Level maps); and (v) Redevelopment Agreement with the City of Montebello.

“Entitlement Date” means the date, if any, on which the Company has actually obtained all the Entitlements.

2

“Excluded Mineral Rights Costs” means all costs, expenses and liabilities (i) relating to environmental liabilities or conditions of the Montebello Surface Estate and Mineral Rights which PXP has actual knowledge as of the date hereof, and (ii) resulting from PXP’s exploitation of the Mineral Rights during the period subsequent to the date hereof, provided, however, costs associated with plugging oil wells which have previously been plugged and abandoned by PXP shall not constitute Excluded Mineral Rights Costs.

“Hazardous Materials” means petroleum and petroleum products and compounds containing them, including gasoline, diesel fuel and oil; explosives; flammable materials; radioactive materials; polychlorinated biphenyls (“PCBs”) and compounds containing them; lead and lead-based paint; asbestos or asbestos-containing materials in any form that is or could become friable; underground or above-ground storage tanks, whether empty or containing any substance; radon; Mold; toxic or mycotoxin spores; any substance the presence of which on the property is prohibited by any federal, state or local authority; any substance that requires special handling under any Hazardous Materials Law; and any other material or substance (whether or not naturally occurring) now or in the future that (i) is defined as a “hazardous substance,” “hazardous material,” “hazardous waste,” “toxic substance,” “toxic pollutant,” “solid waste,” “pesticide,” “contaminant, “ or “pollutant” or otherwise classified as hazardous or toxic by or within the meaning of any Hazardous Materials Law, or (ii) is regulated in any way by or within the meaning of any Hazardous Materials Law.

“Hazardous Materials Law” means all federal, state, and local laws, ordinances and regulations and standards, rules, policies and other governmental requirements, rules of common law (including without limitation nuisance and trespass), consent order, administrative rulings and court judgments and decrees or other government directive in effect now or in the future and including all amendments, that relate to Hazardous Materials or to the protection or conservation of the environment or human health, including without limitation those relating to industrial hygiene, or the use, analysis, generation, manufacture, storage, discharge, release, disposal, transportation, treatment, investigation or remediation of Hazardous Materials. Hazardous Materials Laws include, but are not limited to, the Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. Section 9601, et seq., the Resource Conservation and Recovery Act, 42 U.S.C. Section 6901, et seq., the Toxic Substance Control Act, 15 U.S.C. Section 2601, et seq., the Clean Water Act, 33 U.S.C. Section 1251, et seq., and the Hazardous Materials Transportation Act, 49 U.S.C. Section 5101, et seq., the Superfund Amendments and Reauthorization act, the Solid Waste Disposal Act, the Clean Water Act, the Clean Air Act, the Toxic Substances Control Act, the Occupational Safety and Health Act, and their state analogs

“Laws” means any law (statutory, common, or otherwise), constitution, treaty, convention, ordinance, equitable principle, code, rule, regulation, executive order, or other similar authority enacted, adopted, promulgated, or applied by any governmental authority, each as amended and now and hereinafter in effect.

“Mineral Rights” means all surface and subsurface rights to and ownership of (along with the rights of surface entry to extract) all minerals, oil and gas in, on under and around the land constituting the Montebello Surface Estate as more fully described in Exhibit B hereto.

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“Net Profits” means, at any time, the (a) the sum of all gross cash proceeds received by the Company from the sale(s) of the Montebello Surface Estate or any portion thereof (including non-refundable amounts irrevocably received for granting options to a buyer), minus (b) all Costs and minus (c) an amount equal to 20% of the aggregate Costs, provided that “Costs” for purposes of this clause (c) only shall not include any consulting fees paid to Lodwrick Cook. For purposes of determining Net Profits, no Net Profits will be deemed received with respect to any promissory note until and only to the extent that cash payments are actually received by the Company on such promissory note.

“Senior Management of Consultant” shall mean Lodwrick Cook, John Markley or any other senior management individuals of Consultant that are reasonably acceptable to the Company.

ARTICLE II

ENGAGEMENT; TERM

SECTION 2.1. Engagement as Independent Contractor. The Company hereby retains Consultant and Consultant hereby accepts such retention, as an independent contractor to provide the Consultant Services (as defined below). Consultant shall be and at all times relevant hereto remain an independent contractor of the Company.

SECTION 2.2. Term. This Agreement shall remain in effect from the date hereof until the earlier to occur of (the “Termination Date”): (i) termination by the Company in accordance with ARTICLE V or (ii) sale, transfer or other disposition of all of the Company’s right, title and interest in the Montebello Surface Estate, the collection of all sales proceeds in connection therewith (including any that are deferred) and the making of any payment which may be due under Article IV in connection therewith. Subject to the Company’s obligations pursuant to Section 5.1 in connection with a termination without Cause, upon termination, the Company shall thereafter have no further obligations to Consultant and Consultant shall have no further obligations to the Company under ARTICLE III for future Consultant Services.

ARTICLE III

CONSULTANT SERVICES

SECTION 3.1. Consultant Services. Consultant hereby agrees to provide the following services to the Company and DevelopmentCo from and after the date hereof until the Termination Date (the “Consultant Services”), all subject to the direction, oversight and approval of the Company in its reasonable discretion:

(a) expertise, advice, guidance, management, recommendations and other assistance in obtaining the Entitlements and plans for development of the Montebello Surface Estate;

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(b) coordinate, meet, negotiate and interact with local, state and federal regulatory authorities regarding the Entitlements and development, including preparation and filing of all necessary applications, filings, permit requests and other documentation as may be required in connection with obtaining the Entitlements;

(c) regularly report to the Company and DevelopmentCo regarding the status of the Entitlement process, and provide such information and progress updates regarding the Entitlements as may be requested by the Company, including weekly progress reports and monthly reports to PXP management, critical path schedules, cost estimates and budget refinements;

(d) preparation of budgets, financial models and forecasts regarding the Entitlements process and development (provided that no budget shall be deemed approved by the Company unless formally adopted in writing by the Company in accordance with this Agreement in its reasonable discretion);

(e) assist the Company and DevelopmentCo in identifying sources of third party financing for development after the Entitlement Date, and, subject to formal written approval of the Company, negotiate the terms of any financings with such sources;

(f) infrastructure planning;

(g) manage community and public affairs relating to obtaining the Entitlements and development;

(h) negotiate and arrange for the services of third party contractors;

(i) development of a post-Entitlement Date plan of development, including budgets, financing and marketing plans;

(j) prepare, or cause to be prepared such environmental and neighborhood impact studies or reports, engineering surveys, hazardous substance reports, preliminary plans and specifications, as may be requested by the Company or DevelopmentCo in connection with the Entitlement process and development;

(k) perform, or cause to be performed, an analysis of the market and demographic environment to determine the feasibility of development plans under consideration by the Company;

(l) the services of Lodwrick Cook to serve as CEO of DevelopmentCo, except in the case of death or legal disability, and such other individuals who are approved by DevelopmentCo and are reasonably qualified for the services to be performed;

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(m) provide ongoing access to the management services of the Senior Management of Consultant; and

(n) such other management and consulting services as the Company and/or DevelopmentCo may reasonably request in connection with the Entitlement and development of the Montebello Surface Estate.

SECTION 3.2. Nature of Services. The Consultant Services will be provided at the direction and control of the Company, and shall be directly supervised by the senior management of Consultant, including, without limitation, Lodwrick Cook. The Consultant Services will be provided directly or through third parties approved by the Company in its reasonable discretion. The Consultant Services shall be performed in a diligent and timely manner, and shall be of a type and at a service level substantially equivalent to services provided by other real estate and development companies in the marketplace in connection with real estate development and entitlement transactions of a similar size. Consultant shall use commercially reasonable efforts to ensure that each employee, officer, and consultant of Consultant who performs any Consultant Services shall be reasonably qualified to perform the Consultant Services that such individual is performing.

SECTION 3.3. Budgets; Expenses. The Company hereby agrees that it shall fund 100% of the costs and expenses of Entitlement that are specifically authorized in any entitlement budget that is prepared under the direction of the Consultant and approved by DevelopmentCo and the Company in its reasonable discretion (each an “Approved Entitlement Budget”). To the extent that the Company requests Consultant Services that include the services of the support staff of Consultant (including insurance, personnel, accountants, paralegals, attorneys and regulatory staff) such Approved Entitlement Budget will include reimbursement for any out-of-pocket expenses incurred in connection therewith. Budgets will be prepared on an annual basis and may include salaries and other general and administrative expenses anticipated for the next calendar year, estimated costs and expenses of the dedicated project manager. Except as otherwise agreed to herein or in writing, Consultant and the Company agree that the services of Lodwrick Cook and other senior managers of Consultant will be provided without compensation from PXP, the Company or DevelopmentCo. For purposes of clarification, the Company shall have no obligation to fund any Consultant, DevelopmentCo or third party expenses unless such amounts are budgeted and approved in advance by DevelopmentCo and the Company. Consultant shall provide the board of directors of DevelopmentCo and the Company with quarterly comparisons of budgeted to actual expenses. The Consultant or the Company may propose an amendment to any Approved Entitlement Budget at any time and from time to time as changing circumstances may dictate. Any such amendment must be approved by DevelopmentCo, the Consultant and the Company in their reasonable discretion. For purposes of this Agreement, all approvals. consents or authorizations of DevelopmentCo required or permitted by this Agreement shall require the approval of a majority of board of directors of DevelopmentCo.

SECTION 3.4. Management Power Reserved to the Company. This Agreement shall not constitute a delegation by the Company of authority with respect to the Entitlement and development of the Montebello Surface Estate or otherwise. Consultant specifically understands and agrees that this Agreement shall not be deemed to grant or imply that Consultant is

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authorized to sign, contract, deal or otherwise act in the name or on behalf of the Company except as may be expressly authorized for any specific purpose by the Company in writing hereafter in the Company’s reasonable discretion. Without limiting the foregoing and subject to the Company’s obligations set forth in Section 3.5, Consultant acknowledges that the Company shall have sole and absolute discretion to make all decisions with respect to the Montebello Surface Estate, including decisions with respect to: (i) the timing, type and amount of costs and expenses to be incurred on behalf of or invested in the Company or the Montebello Surface Estate, including costs of Entitlement, scope of development and whether to modify, continue with, or delay pursuit of development or Entitlements, and sources and uses of additional debt or equity financing, and (ii) timing, terms and conditions of any sale, transfer or other disposition of any right title or interest in the Montebello Surface Estate.

SECTION 3.5. Obligations of the Company. The Company agrees to use its reasonable efforts to work with the Consultant toward receipt of the Entitlements and the development and/or sale of the Montebello Surface Estate; provided, however, the parties hereto agree and acknowledge that PXP intends to maximize the value of the Mineral Rights and to develop such Mineral Rights and further agree that the development and/or sale of the Montebello Surface Estate shall be subject to the rights of PXP set forth in Section 8.14.

SECTION 3.6. (a) Limitation On Consultant’s Liability. The Company acknowledges that the Consultant is not acting as a general contractor, architect or real estate broker for the Company and shall not be required to perform, nor shall it perform, services for which a general contractor’s, architect or broker’s license is required. In addition, and except in the event of any gross negligence or willful misconduct by Consultant which directly and materially contributes to such defect or deficiency, the Company acknowledges and agrees that the Consultant shall have no liability to the Company whatsoever for (i) any defects or deficiencies in any plans, permits, entitlements, drawings, specifications, blueprints or other documents, items or work-product of any kind or nature prepared or generated by any third-party in connection with the development of the Montebello Surface Estate (it being agreed that the Company shall look solely to the preparer of such item or others for such defect, and not to the Consultant), or (ii) any defects or deficiencies in any materials, work, workmanship or improvements of any kind or nature constructed, made a part of, incorporated into, undertaken, utilized or otherwise involved with any Montebello Surface Estate, whether or not such work, materials, improvements or items were inspected by the Company (it being agreed that the Company shall look solely to the supplier or installer of such item, the party undertaking such work and/or others for such defect, and not to the Consultant). Further, the Consultant makes no assurance that it will be able to obtain the Entitlements and the Consultant shall have no liability whatsoever to the Company should the Consultant be unable to obtain any of the Entitlements.

(b) Limitation On the Company’s Liability. Consultant acknowledges that the Company is not acting as a general contractor, architect or real estate broker and shall not be required to perform, nor shall it perform, services for which a general contractor’s, architect or broker’s license is required. In addition, and except in the event of any gross negligence or willful misconduct by the Company which directly and materially contributes to such defect or deficiency, Consultant acknowledges and agrees that the Company shall have no liability to Consultant whatsoever for (i) any defects or deficiencies in any plans, permits, entitlements,

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drawings, specifications, blueprints or other documents, items or work-product of any kind or nature prepared or generated by any third-party in connection with the development of the Montebello Surface Estate (it being agreed that Consultant shall look solely to the preparer of such item or others for such defect, and not to the Company), or (ii) any defects or deficiencies in any materials, work, workmanship or improvements of any kind or nature constructed, made a part of, incorporated into, undertaken, utilized or otherwise involved with any Montebello Surface Estate, whether or not such work, materials, improvements or items were inspected by the Company (it being agreed that Consultant shall look solely to the supplier or installer of such item, the party undertaking such work and/or others for such defect, and not to the Company). Further, the Company makes no assurance that it will be able to obtain the Entitlements and the Company shall have no liability whatsoever to the Consultant should any of the Entitlements not be obtained and the subsequent sale of the Montebello Surface Estate not be completed, except as specifically provided herein.

SECTION 3.7. Cooperation. The Company and the Consultant shall reasonably cooperate with each other in order to accomplish the purposes stated herein. The Company further agrees that it shall execute and deliver all applications, maps, plans, drawings, contracts, and other documents and instruments reasonably necessary to the development process and the Entitlements, as reasonably requested by Consultant and approved by the Company.

ARTICLE IV

CONSIDERATION

SECTION 4.1. Consideration. Subject to the terms and conditions set forth herein, as consideration for the Consultant Services, from and after the Entitlement Date, the Company shall pay to Consultant an amount (the “Entitlement Fee”) equal to 15% of the Net Profits less $10 million; provided, however, that in the event that the Net Profits received exceed $450 million, the Entitlement Fee shall be equal to 20% of the Net Profits received less $15 million. In no event, however, shall the Entitlement Fee be less than $1.00. The Entitlement Fee (if any) shall be the sole and exclusive consideration and/or compensation of any kind to Consultant; provided, however, that the Company shall reimburse Consultant for costs and expenses incurred by Consultant that are included in an Approved Entitlement Budget. Notwithstanding anything to the contrary herein or elsewhere, subject to Section 4.2, no Entitlement Fee shall be due or payable to Consultant unless the closing of a sale of all or a portion of the Montebello Surface Estate generating Net Profits shall have actually taken place (whether or not any failure to enter into a sale transaction or any failure to actually close a sale transaction is due to any action or inaction by the Company or any other person or entity or for any other reason).

SECTION 4.2. Payments. To the extent the Company receives funds from the sale(s) of the Montebello Surface Estate, prior to making any payments to Consultant the Company shall reimburse itself, DevelopmentCo and/or PXP for all Costs funded by the Company, DevelopmentCo and/or PXP plus an amount equal to 20% of such Costs. Amounts payable by the Company to Consultant pursuant to Section 4.1 will be paid to Consultant periodically if and

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when Net Profits are received by the Company within 30 days after the Company receives any funds that constitute Net Profits, by wire transfer of immediately available funds, provided however that in the event of a sale of all or any portion of the Montebello Surface Estate prior to the Entitlement Date any amounts payable to Consultant pursuant to Section 4.1 and this Section 4.2 shall be retained by the Company in an escrow account until the Entitlement Date; provided, further, that the Company may, in its good faith reasonable discretion, withhold from any payments a portion of Net Profits representing a reserve against future commitments, expenses and contingent liabilities relating to the Entitlement or development of the Montebello Surface Estate as are set forth in any Approved Entitlement Budget; provided, however, when such reserves are no longer needed by the Company in its reasonable discretion, they shall be deemed cash proceeds for the purpose of calculating Net Profits.

SECTION 4.3. Adjustment. (a) Upon the actual date which the last portion of the proceeds from the sale of the Montebello Surface Estate is received by the Company, the Company shall calculate the Net Profits. In the event that the aggregate sum of all amounts paid by the Company to Consultant pursuant to Sections 4.1 and 4.2 of this Agreement (other than the reimbursement of Costs) exceed (i) in the event that Net Profits are less than or equal to $450 million, 15% of Net Profits as of such date less $10 million, or (ii) in the event that aggregate Net Profits exceed $450 million, 20% of Net Profits as of such date less $15 million, then Consultant shall pay to the Company an amount equal to such excess by wire transfer of immediately available funds to an account designated by the Company within 15 days of the Company’s notification of its determination of Net Profits; provided, however, that in no event shall amounts payable by Consultant pursuant to this Section 4.3 exceed the aggregate amount of payments previously paid to Consultant pursuant to this Agreement.

(b) In the event that the aggregate amount of Entitlement Fees paid to Consultant pursuant to Sections 4.1 and 4.2 hereof (other than the reimbursement of Costs) is less than (i) in the event that Net Profits are less than or equal to $450 million, 15% of Net Profits as of such date less $10 million, or (ii) in the event that aggregate Net Profits exceed $450 million, 20% of Net Profits less $15 million, then the Company shall pay to Consultant an amount equal to such deficiency by wire transfer of immediately available funds to an account designated by Consultant within 15 days of the Company’s determination of Net Profits.

ARTICLE V

TERMINATION

SECTION 5.1. Termination by the Company. At any time prior to the Entitlement Date, the Company shall have the right to terminate this Agreement upon written notice to Consultant. In the event that the Company terminates this Agreement for Cause (as defined in Section 5.2) all of the Company’s obligations under this Agreement shall terminate effective as of the date of such notice, including the Company’s obligation to make any payments to Consultant pursuant to Sections 4.1 and 4.2. In the event that the Company terminates this Agreement other than termination for Cause, the Company’s obligations pursuant to Sections 4.1 and 4.2 shall survive such termination.

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SECTION 5.2. Definition of Cause. As used in this Agreement “Cause” shall mean:

(a) Any failure, refusal or neglect by Consultant at any time to perform fully any of Consultant’s material obligations hereunder, if such failure is not cured and continues for thirty (30) calendar days subsequent to Consultant’s receipt of written notice thereof from the Company;

(b) Willful misconduct or gross negligence of any employees or management of Consultant that is not cured and continues for twenty (20) days after Consultant receives written notice from the Company that identifies the misconduct, negligence or actions taken in bad faith in connection with Consultant’s responsibilities under this Agreement;

(c) If at any time Lodwrick Cook (other than in the case of the death or legal disability) shall (i) cease to materially participate in the provision of the Consultant Services or (ii) cease to make himself generally available to management of the Company at reasonable times upon the Company’s reasonable notice; or

(d) Failure to achieve Entitlement prior to January 1, 2013, provided, however, that such deadline shall be extended by the number of days (if any) that Entitlement was actually delayed as a direct or indirect result of any failure of the Company to fund any costs or expenses necessary to obtain the Entitlements that were included in a budget approved by the Company.

SECTION 5.3. Termination by Consultant. In the event that (i) Entitlement has been achieved, (ii) the Company has received a bona fide offer from a third party ready, willing and able to purchase, fund and close on all or a portion of the Montebello Surface Estate within 90 days at a price that exceeds the then-current value of the Mineral Rights as determined by PXP’s independent reserve engineers in accordance with Securities and Exchange Commission regulations, and (iii) the Company rejects such offer, then Consultant may terminate this Agreement and shall be entitled to receive 50% of the Entitlement Fee calculated as if such sale had occurred and any then incurred but unpaid reimbursable costs. In such event, upon any sale of the Montebello Surface Estate the Company shall pay to Consultant the Entitlement Fee less the portion paid pursuant to the previous sentence.

ARTICLE VI

REPRESENTATIONS AND WARRANTIES

OF THE COMPANY

The Company hereby represents and warrants to Consultant (except as otherwise disclosed in writing on the date hereof and prior to the execution and delivery hereof) as follows:

SECTION 6.1. Organization; Authority. The Company is a limited liability company duly organized, validly existing and in good standing under the laws of the State of Delaware. The Company has the requisite power and authority necessary to execute and deliver this Agreement and to perform and consummate the transactions contemplated hereunder. The execution, delivery and performance by the Company of this Agreement and the consummation

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of the transactions contemplated hereby have been duly authorized by the Company and no other action on the part of the Company is necessary to authorize the execution, delivery and performance by the Company of this Agreement or the consummation of such transactions. This Agreement has been has been duly authorized, executed and delivered by, and assuming due authorization by Consultant, is enforceable against the Company, subject to bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium and similar laws of general applicability relating to or affecting creditor rights and for general equitable principles.

SECTION 6.2. No Conflict; Required Filings and Consents. The execution and delivery of this Agreement by the Company does not, and the performance by the Company of its obligations hereunder and the consummation of the transactions contemplated hereby will not, (i) conflict with or violate the Company’s charter documents, (ii) conflict with or violate any Law applicable to the Company or by which any property or asset of the Company is bound or (iii) violate any note, bond, mortgage, indenture, contract, agreement, lease, license, permit or other instrument or obligation to which the Company is a party or by which the Company or its properties may be bound, except in the case of (ii) and (iii) for any conflict or violation that does not materially adversely affect the performance of the Company’s obligations hereunder or the consummation of the transactions contemplated hereby.

SECTION 6.3. Condition of the Montebello Surface Estate.

(a) Neither Company nor PXP has received any notice of, or has knowledge of, any pending or threatened taking or condemnation of the Montebello Surface Estate or any portion thereof.

(b) The Montebello Surface Estate is free of any right of possession or claim of right of possession of any party other than the Company, and there are no leases or occupancy agreements currently affecting any portion of the Montebello Surface Estate, except for easements and for any such rights, claims, leases or agreements relating to the Mineral Rights.

(c) Neither the Company nor PXP has received a notice of, or has knowledge of, any material violations of law, municipal or county ordinances, or other legal requirements with respect to the Montebello Surface Estate or with respect to the use, occupancy or construction thereon.

(d) There are no purchase contracts or option agreements affecting the Montebello Surface Estate.

(e) PXP will transfer to the Company fee title to the Montebello Surface Estate as soon as practicable after the date hereof, but in any event no later than the Entitlement Date.

(f) Neither the Company nor PXP is a party to any litigation, arbitration, or administrative proceeding affecting the Montebello Surface Estate or the Company’s ability to perform its obligations hereunder and to the knowledge of Company, no such litigation, arbitration or administrative proceeding is threatened.

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(g) The Company has provided Consultant with the Phase I environmental report prepared on the Montebello Surface Estate and other than related to PXP’s oil and gas operations, to the Company’s knowledge there are no Hazardous Materials situated on, under or about the Montebello Surface Estate in violation of applicable law.

ARTICLE VII

REPRESENTATIONS AND WARRANTIES

OF CONSULTANT

Consultant hereby represents and warrants to the Company (except as otherwise disclosed in writing on the date hereof and prior to the execution and delivery hereof) as follows:

SECTION 7.1. Organization; Authority. Consultant is a limited liability company duly organized, validly existing and in good standing under the laws of the State of California. Consultant has the requisite power and authority necessary to execute and deliver this Agreement and to perform and consummate the transactions contemplated hereunder. The execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby by Consultant have been duly authorized by Consultant, and no other action on the part of Consultant is necessary to authorize the execution, delivery and performance of this Agreement or the consummation of such transactions by Consultant. This Agreement has been duly authorized, executed and delivered by, and assuming due authorization by the Company, is enforceable against Consultant, subject to bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium and similar laws of general applicability relating to or affecting creditor rights, and for general equitable principles whether applied in a proceeding at law or in equity.

SECTION 7.2. No Conflict; Required Filings and Consents. The execution and delivery of this Agreement by Consultant does not, and the performance by Consultant of its obligations hereunder and the consummation of the transactions contemplated hereby will not, (i) conflict with or violate the organizational or governing documents of Consultant, (ii) conflict with or violate any Law applicable to Consultant or by which any property or asset of Consultant is bound or (iii) result in any violation pursuant to, any note, bond, mortgage, indenture, contract, agreement, lease, license, permit, franchise or other instrument or obligation to which Consultant is a party or by which Consultant or any of its properties may be bound, except in the case of (ii) and (iii) for any conflict or violation that does not materially adversely affect the performance of Consultant’s obligations hereunder or the consummation of the transactions contemplated hereby.

SECTION 7.3. Montebello Surface Estate. Consultant agrees that (i) it has had the opportunity to perform any inspections, tests and/or studies that it desired or deemed necessary or appropriate in order to determine the suitability of the Montebello Surface Estate for the Company’s intended use thereof, and (ii) it has had the opportunity to review all instruments, records, documents, and studies concerning the Montebello Surface Estate (including zoning,

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ordinances and regulations and any other laws, ordinances or governmental regulations restricting or regulating the use, occupancy or enjoyment of the Montebello Surface Estate) which it deemed appropriate or advisable to review. Consultant also acknowledges that it has relied and will be relying on the advice of its own consultants and advisors that in its sole discretion it has deemed appropriate concerning its execution of this Agreement, the development of the Montebello Surface Estate and the viability and suitability of the Montebello Surface Estate for the Company’s intended uses.

SECTION 7.4. Other Agreements. All arrangements and agreements between Consultant and any non-affiliated third party relating to the Montebello Surface Estate and/or any amounts which may become payable pursuant to this Agreement have been disclosed to the Company and are set forth on Schedule 7.4 hereto, and Consultant hereby agrees to disclose to the Company any such arrangements or agreements upon entering into such arrangements or agreements.

SECTION 7.5. “AS-IS” CONSULTANT ACKNOWLEDGES AND AGREES THAT, NONE OF PXP, DEVELOPMENTCO OR THE COMPANY HAS MADE, DOES MAKE OR WILL MAKE (AND EACH OF PXP, DEVELOPMENTCO AND THE COMPANY HEREBY SPECIFICALLY NEGATES AND DISCLAIMS) ANY REPRESENTATIONS, WARRANTIES, OR GUARANTIES OF ANY KIND OR CHARACTER WHATSOEVER, WHETHER EXPRESS OR IMPLIED, ORAL OR WRITTEN, PAST, PRESENT OR FUTURE, OF, AS TO, CONCERNING OR WITH RESPECT TO ANY MATTER (EXCEPT FOR EXPRESS REPRESENTATIONS AND WARRANTIES IN THIS AGREEMENT), INCLUDING, WITHOUT LIMITATION, WITH RESPECT TO ANY OF THE FOLLOWING MATTERS CONCERNING THE MONTEBELLO SURFACE ESTATE: (I) VALUE OR ANY ANTICIPATED SALE PRICES OF LOTS OR OTHER PORTIONS THEREOF; (II) REVENUE TO BE DERIVED; (III) SUITABILITY FOR ANY AND ALL ACTIVITIES AND USES, INCLUDING THE POSSIBILITIES FOR FUTURE DEVELOPMENT; (IV) HABITABILITY, MERCHANTABILITY, MARKETABILITY, PROFITABILITY OR FITNESS FOR A PARTICULAR PURPOSE; (V) NATURE, QUALITY OR CONDITION, INCLUDING WATER, SOIL AND GEOLOGY; (VI) COMPLIANCE WITH ANY LAWS, RULES, ORDINANCES OR REGULATIONS; (VII) MANNER OR QUALITY OF THE CONSTRUCTION OR MATERIALS, IF ANY; (VIII) COMPLIANCE WITH ANY ENVIRONMENTAL PROTECTION, POLLUTION, ENDANGERED SPECIES OR LAND USE LAWS, RULES, REGULATIONS, ORDERS OR REQUIREMENTS, INCLUDING BUT NOT LIMITED TO, THE AMERICANS WITH DISABILITIES ACT OF 1990, HEALTH & SAFETY CODE, WATER POLLUTION CONTROL ACT, RESOURCE CONSERVATION AND RECOVERY ACT, ENVIRONMENTAL PROTECTION AGENCY REGULATIONS, THE COMPREHENSIVE ENVIRONMENTAL RESPONSE, COMPENSATION AND LIABILITY ACT OF 1980, AS AMENDED, THE RESOURCE CONSERVATION AND RECOVERY ACT OF 1976, THE CLEAN WATER ACT, THE SAFE DRINKING WATER ACT, THE HAZARDOUS MATERIALS TRANSPORTATION ACT, THE TOXIC SUBSTANCE CONTROL ACT; (IX) PRESENCE OR ABSENCE OF HAZARDOUS MATERIALS AT, ON, UNDER, OR ADJACENT TO THE MONTEBELLO SURFACE ESTATE, (X) CONTENT, COMPLETENESS OR ACCURACY OF ANY DOCUMENTS PROVIDED TO CONSULTANT BY PXP, DEVELOPMENTCO OR THE COMPANY OR

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OTHERS OR ANY TITLE REPORT, TITLE COMMITMENT OR SURVEY; (XI) CONFORMITY OF ANY IMPROVEMENTS TO ANY PLANS OR SPECIFICATIONS; (XII) CONFORMITY TO PAST, CURRENT OR FUTURE APPLICABLE ZONING OR BUILDING REQUIREMENTS; (XIII) DEFICIENCY OF ANY UNDERSHORING; (XIV) DEFICIENCY OF ANY DRAINAGE; (XV) POSSIBLE LOCATION IN, ON OR NEAR AN EARTHQUAKE FAULT LINE, LIQUEFACTION AREA, FLOOD AREA, FIRE HAZARD OR OTHER HAZARDOUS AREA; OR (XVI) EXISTENCE OF LAND USE, ZONING OR BUILDING ENTITLEMENTS OR (XVII) ANY MATTER RELATING TO THE SUBSURFACE RIGHTS, OIL OPERATIONS OR OTHER RIGHTS RETAINED BY PXP. CONSULTANT FURTHER ACKNOWLEDGES AND AGREES THAT TO THE MAXIMUM EXTENT PERMITTED BY LAW (EXCEPT FOR EXPRESS REPRESENTATIONS AND WARRANTIES SET FORTH IN THIS AGREEMENT), THE CONDITION OF THE MONTEBELLO SURFACE ESTATE AND ANY OTHER RELATED MATTERS HAS BEEN MADE IN/ON AN “AS IS” CONDITION AND BASIS WITH ALL FAULTS, AND THAT NONE OF PXP, DEVELOPMENTCO OR THE COMPANY HAS ANY OBLIGATIONS TO MAKE REPAIRS, REPLACEMENTS OR IMPROVEMENTS.

ARTICLE VIII

MISCELLANEOUS

SECTION 8.1. Entire Agreement. This Agreement, together with the exhibits and schedules hereto and the certificates, documents, instruments and writings that are delivered pursuant hereto constitutes the entire agreement and understanding of the parties in respect of its subject matter and supersedes all prior understandings, agreements, or representations by or among the parties, written or oral, to the extent they relate in any way to the subject matter hereof. There are no third party beneficiaries having rights under or with respect to this Agreement except that PXP and DevelopmentCo, and Lodwrick Cook with respect to the consulting fee to be paid to him pursuant to clause (ix) of the definition of “Costs” herein, are express intended third party beneficiaries of this Agreement and shall be entitled to the benefits of and to enforce the terms of this Agreement.

SECTION 8.2. Successors; Etc. All of the terms, agreements, covenants, representations, warranties, and conditions of this Agreement are binding upon, and inure to the benefit of and are enforceable by, the parties and their respective successors. Consultant shall not, and hereby expressly waives any right to, assign, directly or indirectly, any of its rights under this Agreement or to file or record this Agreement or any notice hereof or any notice of any action hereon in any public records or give any notice to or make any claim or demand with respect to this Agreement to, in or against any third party or any escrow.

SECTION 8.3. Notices. All notices, requests, demands, claims and other communications hereunder will be in writing. Any notice, request, demand, claim or other communication hereunder will be deemed duly given if (and then three (3) business days after) it is sent by registered or certified mail, return receipt requested, postage prepaid, and addressed to

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the intended recipient as set forth the signature pages hereto. Any party may send any notice, request, demand, claim, or other communication hereunder to the intended recipient at the address set forth above using any other means (including personal delivery, expedited courier, messenger service, telecopy, telex, ordinary mail, or electronic mail), but no such notice, request, demand, claim, or other communication will be deemed to have been duly given unless and until it actually is received by the intended recipient. Any party may change the address to which notices, requests, demands, claims, and other communications hereunder are to be delivered by giving the other parties notice in the manner herein set forth, or may require the delivery of up to one additional copy.

SECTION 8.4. Specific Performance. Each party acknowledges and agrees that the other party would be irreparably damaged if any provision of this Agreement is not performed in accordance with its specific terms or is otherwise breached. Accordingly, each party agrees that the other parties will be entitled to an injunction or injunctions to prevent breaches of the provisions of this Agreement and to specifically enforce this Agreement and its terms and provisions in any action instituted in any court of the United States or any state thereof having jurisdiction over the parties in the matter, subject to this Section 8.4 and Section 8.7, in addition to any other remedy to which such party may be entitled, at law or equity. .

SECTION 8.5. Counterparts. This Agreement may be executed in two or more counterparts, each of which will be deemed an original but all of which together will constitute one and the same instrument.

SECTION 8.6. Headings. The section headings contained in this Agreement are inserted for convenience only and will not affect in any way the meaning or interpretation of this Agreement.

SECTION 8.7. Governing Law and Dispute Resolution.

(a) This Agreement and the performance of the transactions contemplated hereby and the obligations of the parties hereunder will be governed by and construed in accordance with the laws of the State of California, without giving effect to any choice of law principles.

(b) The parties agree that any and all disputes, claims or controversies arising out of or relating to this Agreement shall be first submitted to JAMS or its successor, for mediation, and if the matter is not resolved through mediation, then it shall be submitted to JAMS, or its successor, for final and binding arbitration pursuant to the arbitration clause set forth below. Either party may commence mediation by providing to JAMS and the other party a written request for mediation, setting forth the subject of the dispute and the relief requested. The parties will cooperate with JAMS and with one another in selecting a mediator from JAMS panel of neutrals, and in scheduling the mediation proceedings. The parties covenant that they will participate in the mediation in good faith, and that they will share equally in its costs. All offers, promises, conduct and statements, whether oral or written, made in the course of the mediation by any of the parties, their agents, employees, experts and attorneys, and by the mediator or any JAMS employees, are confidential, privileged and inadmissible for any purpose, including impeachment, in any arbitration or other proceeding involving the

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parties, provided that evidence that is otherwise admissible or discoverable shall not be rendered inadmissible or non-discoverable as a result of its use in the mediation. Either party may initiate arbitration with respect to the matters submitted to mediation by filing a written demand for arbitration at any time following the initial mediation session or 45 days after the date of filing the written request for mediation, whichever occurs first. The mediation may continue after the commencement of arbitration if the parties so desire. Unless otherwise agreed by the parties, the mediator shall be disqualified from serving as arbitrator in the case. The provisions of this clause (b) may be enforced by any Court of competent jurisdiction, and the party seeking enforcement shall be entitled to an award of all costs, fees and expenses, including attorneys’ fees, to be paid by the party against whom enforcement is ordered.

(c) Any dispute, claim or controversy arising out of or relating to this Agreement or the breach, termination, enforcement, interpretation or validity thereof, including the determination of the scope or applicability of this agreement to arbitrate, which has failed to be resolved during the mediation process above shall be determined by arbitration before a panel of three (3) arbitrators. The arbitration shall be administered by JAMS pursuant to its Comprehensive Arbitration Rules and Procedures (Streamlined Arbitration Rules and Procedures). Unless the parties agree otherwise, the place of arbitration shall be Los Angeles, California. The arbitrators shall not be empowered to award any form of exemplary or punitive damages. As part of any arbitral award pursuant to this paragraph, the arbitrators shall render a reasoned award. The parties consent to judgment on such award being entered in any court having jurisdiction.

(d) Each party is required to continue to perform its obligations under this Agreement pending final resolution of any dispute.

(e) Should any party hereto institute any arbitration proceedings permitted under this Section 8.7, the prevailing party (as determined by the arbitral panel) shall be entitled to recover costs of the arbitration proceeding and reasonable attorneys’ fees to be fixed by the arbitral panel.

(f) Any judicial proceedings permitted to be brought with respect to this Agreement shall be brought in any state or federal court of competent jurisdiction in the State of California, and the parties generally and unconditionally accept the exclusive jurisdiction of such courts. The parties waive, to the fullest extent permitted by applicable Law, any objection which they may now or hereafter have to the bringing of any such action or proceeding in such jurisdiction.

SECTION 8.8. Amendments and Waivers. No amendment, modification, replacement, termination or cancellation of any provision of this Agreement will be valid, unless the same will be in writing and signed by each party hereto. Neither any failure nor any delay by any party in exercising any right, power or privilege under this Agreement will operate as a waiver of such right, power or privilege, and no single or partial exercise of any such right, power or privilege will preclude any other or further exercise of such right, power or privilege or the exercise of any other right, power or privilege. To the maximum extent permitted by applicable law, (a) no claim or right arising out of this Agreement can be discharged by one party, in whole or in part, by a waiver or renunciation of the claim or right unless in writing signed by the other party; (b) no waiver that may be given by a party will be applicable except in the specific instance for

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which it is given; and (c) no notice to or demand on one party will be deemed to be a waiver of any obligation of that party or of the right of the party giving such notice or demand to take further action without notice or demand as provided in this Agreement.

SECTION 8.9. Severability. The provisions of this Agreement are severable, and the invalidity of any provision shall not affect the validity of any other provision.

SECTION 8.10. Expenses. Except as otherwise expressly provided in this Agreement, each party will bear its own costs and expenses incurred in connection with the negotiation and preparation of this Agreement.

SECTION 8.11. Construction. This Agreement will be deemed to have been drafted by both parties thereto and will not be construed against either party as the draftsperson hereof. “Including” or “include” or “includes” or “including without limitation” means “including without limitation”.

SECTION 8.12. Incorporation of Exhibits, Annexes and Schedules. The exhibits, annexes, schedules, and other attachments identified in this Agreement are incorporated herein by reference and made a part hereof.

SECTION 8.13. Remedies. Except as expressly provided herein, the rights, obligations and remedies created by this Agreement are cumulative and in addition to any other rights, obligations, or remedies otherwise available at law or in equity. Except as expressly provided herein, nothing herein will be considered an election of remedies.

SECTION 8.14. Other Business Interests/No Fiduciary Duty. The parties and their respective members and affiliates may engage, directly or indirectly, without consent of the other parties, in other business opportunities or arrangements, independently or with others, including those competitive with the Company, regardless of geographic location, and without any duty or obligation to offer or account to the other parties. Without limitation, PXP owns the Mineral Rights which now and may hereafter burden the Montebello Surface Estate and Consultant acknowledges its understanding that PXP shall be free to exploit the same in any manner even if it would be harmful to the Company’s interests in the Montebello Surface Estate or hinder, delay or prevent the Entitlement or development thereof and/or Consultant’s ability to earn any (or the amount, if any) Entitlement Fee. Consultant acknowledges its understanding that PXP will have conflicts of interests arising from its other business interests, including the Mineral Rights. Further, PXP and the Company are free to act in their own best interests and in accordance with their respective sole and absolute discretion as to all aspects of the Montebello Surface Estate, including the Entitlement, development, budgeting, scheduling, financing and/or sale thereof, notwithstanding any adverse impact on Net Profits. Without limiting the foregoing or any other provision of this Agreement, Consultant specifically acknowledges its understanding that the Company and PXP may elect to delay providing funding for the Entitlement and development process at any time and/or elect to delay the development of the Montebello Surface Estate for residential purposes despite whether any such delay or abandonment could impact the timing and amount of Entitlement Fees (if any) payable hereunder. Further, nothing herein is intended to create a partnership, joint venture, agency, or other relationship creating fiduciary or quasi-

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fiduciary duties and obligations or to impose any duty, obligation, or liability that would arise therefrom with respect to any or all of the parties or their Affiliates or any permitted assigns. Neither party shall be deemed to be a fiduciary to the other party. To the full extent permitted by law, the parties waive any such fiduciary obligations as might have otherwise applied.

[Signature page follows]

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IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their respective officers thereunto duly authorized, all as of the date first written above.

COOK HILL PROPERTIES LLC
By:	/s/ Lodwrick M. Cook
Name:	Lodwrick M. Cook
Title:	Managing Member
Copy of any notices, requests, demands, claims and other communications to be sent to:
9355 Wilshire Boulevard, 4th Floor
Beverly Hills, CA 90210
Attn: Gerry Ginsberg
MONTEBELLO LAND COMPANY LLC
By its Sole Member:
Plains Exploration and Production Company
By:	/s/ John F. Wombwell
Name:	John F. Wombwell
Title:	Executive Vice President, General Counsel and Secretary
Copy of any notices, requests, demands, claims and other communications to be sent to:
Plains Exploration & Production Company
700 Milam, Suite 3100
Houston, TX 77002
Attn: John Wombwell

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EXHIBIT A

LEGAL DESCRIPTION OF MONTEBELLO SURFACE ESTATE

The following real property in the City of Montebello, County of Los Angeles, State of California, described as follows:

Parcel 1: Baldwin Fee

Lots 1, 2, 3, 4 and 5 of Tract 4104, in the City of Montebello, as per map recorded in Book 46 Page 33 of Maps, in the Office of the County Recorder of said county, except therefrom that portion of said Lots 1, 2 and 3, lying Northerly of the following described line:

Beginning at the Southeasterly corner of Parcel 7 of Parcel Map 16793 as per map filed in Book 187 Pages 36 to 39 inclusive of Parcel Maps, thence South 77º 22’ 16” West 48.19 feet to a point; thence South 65º 05’ 45” West 1694.29 feet to a point, described as the Southerly Corner of Parcel 5 of Parcel Map 14770 as per map filed in Book 167 Pages 92 to 94 of Parcel Maps; thence North 80º 11’ 24” West 2010.03 feet to a point; thence North 51º 47’ 37” West 543.31 feet to a point on the Easterly Corner of Parcel 3 of Parcel Map 11141 as per map filed in Book 133 Pages 1 to 3 inclusive of Parcel Maps; thence South 52º 21’14” West 71.44 feet to a point; thence South 48º 40’ 22” West , 155.76 feet to a point; thence South 52º 21’14” West, 767.27 feet to a point; thence North 37º 38’ 46” West, 8 feet to a point on the Southeasterly line of Montebello Boulevard, 84 feet Wide, as described on a deed to City of Montebello by Instrument No. 3460, recorded on June 8, 1971 in Book D5082 Page 431, of Official Records, thence Southwesterly and Southerly along the Southeasterly boundary of said boulevard as described on said document to a point on the Southeasterly line of Lot 3 of Tract 4104.

APN: 5271-001-030, 047, 048, Portion 048

Parcel 2: Warren Fee

Lot 125 of Tract No. 25072, as shown on the map of said Tract, recorded June 3, 1960 in Book 657 of Maps, at Pages 28 and 29, Records of said Los Angeles County.

APN: 5278-003-015

Parcel 3: California Bank Fee (Temple)

That portion of Lot Seventy-two (72) of Tract Number Seven Hundred One (701), as per map recorded in Book 16 Pages 110 and 111 of Maps in the office of the County Recorder of said County, described as follows:

Beginning at the most Southeasterly corner of said Lot Seventy-two (72); thence along the Southwesterly line of said Lot, North 73º 31’ West 1131.40 feet; thence North 62º 32’ East 510.70 feet; thence North 48 º 12’ East 100 feet, more or less, to the Southwesterly line of San Gabriel Boulevard; thence along said Southwesterly line South 41º 48’ East 836 feet, more or less, to the beginning.

A-1

Also that portion of the Rancho La Merced, partly within and partly without the City of Montebello, as per map recorded in Book 13 Page 16 of Patents, described as follows:

Beginning at the most Southeasterly corner of Lot 72 of Tract No 701, as per map recorded in Book 16 Pages 110 and 111 of Maps; thence South 41º 48’ East 89.86 feet; thence South 28º 07’ 15” East 787.35 feet to the beginning of a curve concave to the Northeast and having a radius of 230 feet; thence along said curve 217.22 feet to the end of same; thence South 7º 46’ West 150 feet; thence North 84º 38’ 10” West 1767.9 feet; thence South 76º 17’ West 740 feet; thence North 10º 43’ East 1225 feet; thence North 74º 55’ 50” East 604.52 feet, more or less, to the Southwesterly line of Tract No. 701; thence South 73º 31’ East 1131.4 feet to the point of beginning.

Excepting therefrom a strip of land 60 feet wide conveyed to the County of Los Angeles for public road and highway purposes by a deed dated April 8, 1915 and recorded in Book 6123 Page 178 of Deeds, and lying 30 feet on each side of the following described centerline:

Beginning at a point on the Southerly line of the property herein described, distant North 84º 36’ 15” West 585.20 feet from the Southeast corner of said property; thence North 38º 24’ 30” East 82.41 feet; thence North 19º 28’ 30” East 190.77 feet; thence North 21º 26’ 45” East 127.28 feet; thence North 41º 03’ 30” East 179.37 feet to the Southwesterly line of San Gabriel Boulevard and bearing South 28º 05’ East 431.89 feet from an angle point in the Westerly line of said Boulevard.

APN: 5271-001-Portion 048, 5271-010-031

Parcel 4: Huntington Beach Fee

Parcels 6 and 7 of Parcel Map No. 16793, in the City of Montebello, as shown on a map filed in Book 187 Pages 36 through 39 inclusive of Parcel Maps in the office of the Los Angeles County Recorder. Parcels 3 and 5 of Parcel Map No. 14770, in the City of Montebello, as shown on a map filed in Book 167 Pages 92 to 94 inclusive of Parcel Maps, in the office of the Los Angeles County Recorder.

APN: 5271-020-028, 029, 070. 073, 074, 075, 079

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EXHIBIT B

LEGAL DESCRIPTION OF MINERAL RIGHTS

The “Mineral Rights” means

(1) all oil, gas and other hydrocarbon substances, and all other mineral and otherwise valuable substances, in the Montebello Surface Estate or under the Montebello Surface Estate or which may be produced therefrom; and the sole and exclusive right to the possession, use, development and improvement of the surface and all subsurface depths thereof as may be necessary or convenient to surveying, prospecting and exploring for, producing, storing, treating, and transporting any and all such substances; including operations (and such possession, use, development and improvement of the surface and all subsurface depths thereof as may be necessary or convenient to operations) by means and in a manner now known or unknown; and, further, including the exclusive right to mine or drill from the surface of, or into or through the subsurface of, any part of the Montebello Surface Estate in connection with operations incidental to surveying, prospecting and exploring for, producing, storing, treating, and transporting any and all such substances within and from any and all other lands; and, further, including the exclusive right to the possession, use, development and improvement of the surface and all subsurface depths thereof as may be necessary or convenient to surveying, prospecting and exploring for, producing, storing, treating, and transporting any and all such substances within and from any and all lands other than and in addition to the Montebello Surface Estate (all of which are hereinafter referred to and included within the “Mineral Interest” in the Montebello Surface Estate); and

(2) all of PXP’s existing right, title and interest in, to and under any and all oil and gas leases affecting all or any part of the Montebello Surface Estate (which, if any, are hereinafter referred to collectively as the “Leases”);

(3) all right, title and interest of PXP in, to and under easements, tangible and intangible personal property, facilities, fixtures, equipment, rights and benefits incidental and appurtenant to the ownership, use or operation of any part of the Mineral Interest, under the Leases or otherwise, within all or any part of the Montebello Surface Estate or other lands, or both, including, without limitation:

(a) all contracts and agreements whether recorded or unrecorded in existence at the Effective Date, which affect any part of the Mineral Interest in the Montebello Surface Estate, or other lands, or any of the Leases; and

(b) all facilities and equipment (whether active or inactive) customarily used directly in the production of crude oil, natural gas, casinghead gas, condensate, sulphur, natural gas liquids, plant products and other liquid or gaseous hydrocarbon substances (including CO₂), and all other minerals of every kind and character attributable to PXP’s interest in any part of the Montebello Surface Estate, or other lands, or any of the Leases (collectively,

B-1

“Hydrocarbons”), including but not limited to wells (whether plugged or unplugged), injection facilities, disposal facilities, equipment, fixtures, incidentals and appurtenances, facilities and personal property of any kind (including, but not limited to, tubing, casing, wellheads, pumping units, production units, compressors, valves, meters, flowlines, pipelines and other lesser piping, tanks, heaters, separators, dehydrators, pumps, injection units, gates and fences, field separators, liquid extractors, compressors, LACT units; plants, tanks and the like); and

(c) presently existing pooling, unitization and communitization agreements or other operating agreements and the right, title and interest of PXP in and to the units created thereby (including without limitation all units formed under orders, regulations, rules or other official acts of any governmental entity, agency or officer) related, incidental or appurtenant to the Mineral Interest in any part of the Montebello Surface Estate, or other lands, or any of the Leases; and

(d) exclusive and non-exclusive rights to the use and occupancy of land, including, without limitation, tenements, appurtenances, surface leases, easements, permits, licenses, franchises, servitudes and rights-of-way appertaining, belonging, affixed or incidental to or used in connection with the ownership of the Mineral Interest, or operations incidental to the enjoyment of the Mineral Interest, in any part of the Montebello Surface Estate, or other lands, or any of the Leases, whether recorded or unrecorded; and

(e) licenses, authorizations, permits, variances and similar rights and interests, and other rights, privileges, benefits and powers conferred upon the owner of the Mineral Interest, or operations incidental to the enjoyment of the Mineral Interest, in any part of the Montebello Surface Estate, or other lands, or upon the holder of any of the Leases, including, without limitation, all claims causes of action, insurance policies or proceeds therefrom, appertaining, belonging, affixed or incidental to or held or exercised in connection with the Mineral Interest in any part of the Montebello Surface Estate, or other lands, or any of the Leases; and

(f) general operating records, well files (including applicable well logs and production data), lease files, land files, environmental compliance files, regulatory reports and certificates, abstracts and title work appertaining, belonging or incidental to the Mineral Interest in any part of the Montebello Surface Estate, or other lands, or any of the Leases; and

(4) all easements and rights-of-way of any kind or nature standing in the name of, reserved by or granted by PXP, PXP’s predecessors, subsidiaries or affiliates or any predecessor, subsidiary or affiliate, related to the Montebello Surface Estate, whether or not such rights appear of record and whether or not identifiable by inspection of the real property, and all equipment, pipelines, powerlines and other facilities used in association with such easements and rights-of-way.

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SCHEDULE 7.4

THIRD PARTY AGREEMENTS

Consultant is in discussions with the Ezralow Company and John Markley pursuant to which it expects to enter into an agreement to engage both parties to assist the Consultant in performing the services contemplated herein.

7.4-1

EX-10.4

Exhibit 10.4

CONSULTING AGREEMENT

This Consulting Agreement (the “Agreement”) is entered into as of January 19, 2006 by and between by and between Lompoc Land Company LLC (the “Company”), a wholly owned subsidiary of Plains Exploration & Production Company (“PXP”), and Cook Hill Properties LLC (“Consultant”).

BACKGROUND:

A. PXP will contribute to the Company that certain surface estate of land not to exceed 405 acres comprised of all of parcels 14 and 15 and those portions of parcels 3 and 16 lying west of Harris Grade Road as reflected in the parcel map attached as Exhibit A, being a portion of the property described more fully in Exhibit A.1, located in Santa Barbara County, California (the “Lompoc Surface Estate”), and PXP will retain all right, title and interest in and to any Mineral Rights (as defined below).

B. Consultant has a management team with expertise in the entitlement and development of residential communities in Southern California and the Company desires that Consultant assist the Company with the entitlement and development of the Lompoc Surface Estate and Consultant desires to do so.

AGREEMENT:

NOW, THEREFORE, in consideration of the foregoing and the respective representations, warranties, covenants and agreements set forth in this Agreement, the parties hereto agree as follows:

ARTICLE I

DEFINITIONS

“Costs” means the following: all costs, expenses, fees, charges and losses related to and applicable to the Lompoc Surface Estate which are, or are to be, or have been, paid, delivered and/or incurred by the Company, by DevelopmentCo or by PXP, whether before or after any Entitlements are obtained (without duplication), including, without limitation: (i) all costs, fees and expenses relating to Entitlements, (ii) all salaries and other general and administrative and operating expenses of the Company and DevelopmentCo (including expense reimbursements paid under this Agreement with respect to the Consultant Services), but not including any salaries or other expenses of PXP personnel, (iii) expenses, fees and costs relating to the ownership, development, entitlement, improvement, subdivision, management and land preparation of the Lompoc Surface Estate, including costs, expenses, fines or other liabilities arising out of any suits, claims, administrative or other proceedings against Company or its affiliates and equity holders relating to the Lompoc Surface Estate imposed or initiated by a governmental authority or any other person or entity; provided, that this clause (iii) shall not include any costs, expenses,

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fines or other liabilities arising out of any suits, claims, administrative or other proceedings relating to (a) PXP’s exploitation of the Mineral Rights or (b) Excluded Mineral Rights Costs, (iv) all property taxes (excluding those applicable to the Mineral Rights), (v) all costs, fines and expenses of any environmental clean-up or remediation of the Lompoc Surface Estate (other than Excluded Mineral Rights Costs), including liabilities arising out of any suits, claims, administrative or other proceedings relating thereto, (vi) expenses incurred in connection with the collection of any amounts owed to the Company by any person, (vii) all professional fees, including attorneys, accountants, agents, appraisers, consultants, environmental experts and other consultants, incurred in connection with the ownership, development, entitlement, improvement, subdivision, management, or land preparation of the Lompoc Surface Estate, (viii) all financing costs and fees, including interest, points and loan fees, and amounts payable by the Company to any third party in connection with any form of equity financing or investment by third party in connection with the development and maintenance of the Lompoc Surface Estate; provided, that this clause (viii) shall not include any such financing that is non-recourse to PXP, (ix) a consulting fee to Lodwrick Cook of $1 per month; and (x) all costs associated with any sale, disposition or transfer (or any proposed sale, disposition or transfer) of any portion of the Lompoc Surface Estate, including marketing, legal and accounting fees, brokerage fees, sale commissions, bank charges, transfer fees, custodial fees, costs, closing costs, escrow fees, and other related costs and expenses. Notwithstanding the foregoing, it is agreed that (a) costs incurred to the date hereof shall not exceed $2.5 million in the aggregate, (b) the Entitlement Fee (as defined in Section 4.1) shall not be included in the definition of Costs and (c) Costs shall not include any costs, expenses, fees, charges and losses incurred by DevelopmentCo or PXP relating to the ownership, development and entitlement of PXP’s real property located in the City of Montebello, California and in San Luis Obispo County, California which are included in “Costs” under either of the respective Consulting Agreements entered into as of even date herewith.

“DevelopmentCo” means Cane River Development LLC, a Delaware limited liability company.

“Entitlement” means that the Company has obtained all of the Entitlements.

“Entitlements” means all permits, licenses, approvals and other administrative certifications and satisfaction of other requirements (federal, state and local) as may be reasonably necessary to commence and carry out the development of the Lompoc Surface Estate as a residential project, in accordance with such development plans and development budgets as may be, from time to time, proposed by the Consultant and approved by the Company in the Company’s reasonable discretion as evidenced by formal written resolutions of the Company. Without limiting the scope of the forgoing, Entitlements shall include the following permits, licenses, approvals and other administrative certifications: (i) the Final Environmental Assessment/§404 Permit to be issued by the U. S. Army Corps of Engineers; (ii) final permits from the Regional Water Quality Control Board and the California Department of Fish & Game; (iii) a final Environmental Impact Report to be issued by Santa Barbara County, California; (iv) the final Development Agreement (including A level and final B Level maps); and (v) Redevelopment Agreement with Santa Barbara County.

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“Entitlement Date” means the date, if any, on which the Company has actually obtained all the Entitlements.

“Excluded Mineral Rights Costs” means all costs, expenses and liabilities (i) relating to environmental liabilities or conditions of the Lompoc Surface Estate and Mineral Rights which PXP has actual knowledge as of the date hereof, and (ii) resulting from PXP’s exploitation of the Mineral Rights during the period subsequent to the date hereof, provided, however, costs associated with plugging oil wells which have previously been plugged and abandoned by PXP shall not constitute Excluded Mineral Rights Costs.

“Hazardous Materials” means petroleum and petroleum products and compounds containing them, including gasoline, diesel fuel and oil; explosives; flammable materials; radioactive materials; polychlorinated biphenyls (“PCBs”) and compounds containing them; lead and lead-based paint; asbestos or asbestos-containing materials in any form that is or could become friable; underground or above-ground storage tanks, whether empty or containing any substance; radon; Mold; toxic or mycotoxin spores; any substance the presence of which on the property is prohibited by any federal, state or local authority; any substance that requires special handling under any Hazardous Materials Law; and any other material or substance (whether or not naturally occurring) now or in the future that (i) is defined as a “hazardous substance,” “hazardous material,” “hazardous waste,” “toxic substance,” “toxic pollutant,” “solid waste,” “pesticide,” “contaminant, “ or “pollutant” or otherwise classified as hazardous or toxic by or within the meaning of any Hazardous Materials Law, or (ii) is regulated in any way by or within the meaning of any Hazardous Materials Law.

“Hazardous Materials Law” means all federal, state, and local laws, ordinances and regulations and standards, rules, policies and other governmental requirements, rules of common law (including without limitation nuisance and trespass), consent order, administrative rulings and court judgments and decrees or other government directive in effect now or in the future and including all amendments, that relate to Hazardous Materials or to the protection or conservation of the environment or human health, including without limitation those relating to industrial hygiene, or the use, analysis, generation, manufacture, storage, discharge, release, disposal, transportation, treatment, investigation or remediation of Hazardous Materials. Hazardous Materials Laws include, but are not limited to, the Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. Section 9601, et seq., the Resource Conservation and Recovery Act, 42 U.S.C. Section 6901, et seq., the Toxic Substance Control Act, 15 U.S.C. Section 2601, et seq., the Clean Water Act, 33 U.S.C. Section 1251, et seq., and the Hazardous Materials Transportation Act, 49 U.S.C. Section 5101, et seq., the Superfund Amendments and Reauthorization act, the Solid Waste Disposal Act, the Clean Water Act, the Clean Air Act, the Toxic Substances Control Act, the Occupational Safety and Health Act, and their state analogs

“Laws” means any law (statutory, common, or otherwise), constitution, treaty, convention, ordinance, equitable principle, code, rule, regulation, executive order, or other similar authority enacted, adopted, promulgated, or applied by any governmental authority, each as amended and now and hereinafter in effect.

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“Mineral Rights” means all surface and subsurface rights to and ownership of (along with the rights of surface entry to extract) all minerals, oil and gas in, on under and around the land constituting the Lompoc Surface Estate as more fully described in Exhibit B hereto.

“Net Profits” means, at any time, the (a) the sum of all gross cash proceeds received by the Company from the sale(s) of the Lompoc Surface Estate or any portion thereof (including non-refundable amounts irrevocably received for granting options to a buyer), minus (b) all Costs and minus (c) an amount equal to 20% of the aggregate Costs, provided that “Costs” for purposes of this clause (c) only shall not include any consulting fees paid to Lodwrick Cook. For purposes of determining Net Profits, no Net Profits will be deemed received with respect to any promissory note until and only to the extent that cash payments are actually received by the Company on such promissory note.

“Senior Management of Consultant” shall mean Lodwrick Cook, John Markley or any other senior management individuals of Consultant that are reasonably acceptable to the Company.

ARTICLE II

ENGAGEMENT; TERM

SECTION 2.1. Engagement as Independent Contractor. The Company hereby retains Consultant and Consultant hereby accepts such retention, as an independent contractor to provide the Consultant Services (as defined below). Consultant shall be and at all times relevant hereto remain an independent contractor of the Company.

SECTION 2.2. Term. This Agreement shall remain in effect from the date hereof until the earlier to occur of (the “Termination Date”): (i) termination by the Company in accordance with ARTICLE V or (ii) sale, transfer or other disposition of all of the Company’s right, title and interest in the Lompoc Surface Estate, the collection of all sales proceeds in connection therewith (including any that are deferred) and the making of any payment which may be due under Article IV in connection therewith. Subject to the Company’s obligations pursuant to Section 5.1 in connection with a termination without Cause, upon termination, the Company shall thereafter have no further obligations to Consultant and Consultant shall have no further obligations to the Company under ARTICLE III for future Consultant Services.

ARTICLE III

CONSULTANT SERVICES

SECTION 3.1. Consultant Services. Consultant hereby agrees to provide the following services to the Company and DevelopmentCo from and after the date hereof until the Termination Date (the “Consultant Services”), all subject to the direction, oversight and approval of the Company in its reasonable discretion:

(a) expertise, advice, guidance, management, recommendations and other assistance in obtaining the Entitlements and plans for development of the Lompoc Surface Estate;

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(b) coordinate, meet, negotiate and interact with local, state and federal regulatory authorities regarding the Entitlements and development, including preparation and filing of all necessary applications, filings, permit requests and other documentation as may be required in connection with obtaining the Entitlements;

(c) regularly report to the Company and DevelopmentCo regarding the status of the Entitlement process, and provide such information and progress updates regarding the Entitlements as may be requested by the Company, including weekly progress reports and monthly reports to PXP management, critical path schedules, cost estimates and budget refinements;

(d) preparation of budgets, financial models and forecasts regarding the Entitlements process and development (provided that no budget shall be deemed approved by the Company unless formally adopted in writing by the Company in accordance with this Agreement in its reasonable discretion);

(e) assist the Company and DevelopmentCo in identifying sources of third party financing for development after the Entitlement Date, and, subject to formal written approval of the Company, negotiate the terms of any financings with such sources;

(f) infrastructure planning;

(g) manage community and public affairs relating to obtaining the Entitlements and development;

(h) negotiate and arrange for the services of third party contractors;

(i) development of a post-Entitlement Date plan of development, including budgets, financing and marketing plans;

(j) prepare, or cause to be prepared such environmental and neighborhood impact studies or reports, engineering surveys, hazardous substance reports, preliminary plans and specifications, as may be requested by the Company or DevelopmentCo in connection with the Entitlement process and development;

(k) perform, or cause to be performed, an analysis of the market and demographic environment to determine the feasibility of development plans under consideration by the Company;

(l) the services of Lodwrick Cook to serve as CEO of DevelopmentCo, except in the case of death or legal disability, and such other individuals who are approved by DevelopmentCo and are reasonably qualified for the services to be performed;

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(m) provide ongoing access to the management services of the Senior Management of Consultant; and

(n) such other management and consulting services as the Company and/or DevelopmentCo may reasonably request in connection with the Entitlement and development of the Lompoc Surface Estate.

SECTION 3.2. Nature of Services. The Consultant Services will be provided at the direction and control of the Company, and shall be directly supervised by the senior management of Consultant, including, without limitation, Lodwrick Cook. The Consultant Services will be provided directly or through third parties approved by the Company in its reasonable discretion. The Consultant Services shall be performed in a diligent and timely manner, and shall be of a type and at a service level substantially equivalent to services provided by other real estate and development companies in the marketplace in connection with real estate development and entitlement transactions of a similar size. Consultant shall use commercially reasonable efforts to ensure that each employee, officer, and consultant of Consultant who performs any Consultant Services shall be reasonably qualified to perform the Consultant Services that such individual is performing.

SECTION 3.3. Budgets; Expenses. The Company hereby agrees that it shall fund 100% of the costs and expenses of Entitlement that are specifically authorized in any entitlement budget that is prepared under the direction of the Consultant and approved by DevelopmentCo and the Company in its reasonable discretion (each an “Approved Entitlement Budget”). To the extent that the Company requests Consultant Services that include the services of the support staff of Consultant (including insurance, personnel, accountants, paralegals, attorneys and regulatory staff) such Approved Entitlement Budget will include reimbursement for any out-of-pocket expenses incurred in connection therewith. Budgets will be prepared on an annual basis and may include salaries and other general and administrative expenses anticipated for the next calendar year, estimated costs and expenses of the dedicated project manager. Except as otherwise agreed to herein or in writing, Consultant and the Company agree that the services of Lodwrick Cook and other senior managers of Consultant will be provided without compensation from PXP, the Company or DevelopmentCo. For purposes of clarification, the Company shall have no obligation to fund any Consultant, DevelopmentCo or third party expenses unless such amounts are budgeted and approved in advance by DevelopmentCo and the Company. Consultant shall provide the board of directors of DevelopmentCo and the Company with quarterly comparisons of budgeted to actual expenses. The Consultant or the Company may propose an amendment to any Approved Entitlement Budget at any time and from time to time as changing circumstances may dictate. Any such amendment must be approved by DevelopmentCo, the Consultant and the Company in their reasonable discretion. For purposes of this Agreement, all approvals. consents or authorizations of DevelopmentCo required or permitted by this Agreement shall require the approval of a majority of board of directors of DevelopmentCo.

SECTION 3.4. Management Power Reserved to the Company. This Agreement shall not constitute a delegation by the Company of authority with respect to the Entitlement and development of the Lompoc Surface Estate or otherwise. Consultant specifically understands and agrees that this Agreement shall not be deemed to grant or imply that Consultant is

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authorized to sign, contract, deal or otherwise act in the name or on behalf of the Company except as may be expressly authorized for any specific purpose by the Company in writing hereafter in the Company’s reasonable discretion. Without limiting the foregoing and subject to the Company’s obligations set forth in Section 3.5, Consultant acknowledges that the Company shall have sole and absolute discretion to make all decisions with respect to the Lompoc Surface Estate, including decisions with respect to: (i) the timing, type and amount of costs and expenses to be incurred on behalf of or invested in the Company or the Lompoc Surface Estate, including costs of Entitlement, scope of development and whether to modify, continue with, or delay pursuit of development or Entitlements, and sources and uses of additional debt or equity financing, and (ii) timing, terms and conditions of any sale, transfer or other disposition of any right title or interest in the Lompoc Surface Estate.

SECTION 3.5. Obligations of the Company. The Company agrees to use its reasonable efforts to work with the Consultant toward receipt of the Entitlements and the development and/or sale of the Lompoc Surface Estate; provided, however, the parties hereto agree and acknowledge that PXP intends to maximize the value of the Mineral Rights and to develop such Mineral Rights and further agree that the development and/or sale of the Lompoc Surface Estate shall be subject to the rights of PXP set forth in Section 8.14.

SECTION 3.6. (a) Limitation On Consultant’s Liability. The Company acknowledges that the Consultant is not acting as a general contractor, architect or real estate broker for the Company and shall not be required to perform, nor shall it perform, services for which a general contractor’s, architect or broker’s license is required. In addition, and except in the event of any gross negligence or willful misconduct by Consultant which directly and materially contributes to such defect or deficiency, the Company acknowledges and agrees that the Consultant shall have no liability to the Company whatsoever for (i) any defects or deficiencies in any plans, permits, entitlements, drawings, specifications, blueprints or other documents, items or work-product of any kind or nature prepared or generated by any third-party in connection with the development of the Lompoc Surface Estate (it being agreed that the Company shall look solely to the preparer of such item or others for such defect, and not to the Consultant), or (ii) any defects or deficiencies in any materials, work, workmanship or improvements of any kind or nature constructed, made a part of, incorporated into, undertaken, utilized or otherwise involved with any Lompoc Surface Estate, whether or not such work, materials, improvements or items were inspected by the Company (it being agreed that the Company shall look solely to the supplier or installer of such item, the party undertaking such work and/or others for such defect, and not to the Consultant). Further, the Consultant makes no assurance that it will be able to obtain the Entitlements and the Consultant shall have no liability whatsoever to the Company should the Consultant be unable to obtain any of the Entitlements.

(b) Limitation On the Company’s Liability. Consultant acknowledges that the Company is not acting as a general contractor, architect or real estate broker and shall not be required to perform, nor shall it perform, services for which a general contractor’s, architect or broker’s license is required. In addition, and except in the event of any gross negligence or willful misconduct by the Company which directly and materially contributes to such defect or deficiency, Consultant acknowledges and agrees that the Company shall have no liability to Consultant whatsoever for (i) any defects or deficiencies in any plans, permits, entitlements,

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drawings, specifications, blueprints or other documents, items or work-product of any kind or nature prepared or generated by any third-party in connection with the development of the Lompoc Surface Estate (it being agreed that Consultant shall look solely to the preparer of such item or others for such defect, and not to the Company), or (ii) any defects or deficiencies in any materials, work, workmanship or improvements of any kind or nature constructed, made a part of, incorporated into, undertaken, utilized or otherwise involved with any Lompoc Surface Estate, whether or not such work, materials, improvements or items were inspected by the Company (it being agreed that Consultant shall look solely to the supplier or installer of such item, the party undertaking such work and/or others for such defect, and not to the Company). Further, the Company makes no assurance that it will be able to obtain the Entitlements and the Company shall have no liability whatsoever to the Consultant should any of the Entitlements not be obtained and the subsequent sale of the Lompoc Surface Estate not be completed, except as specifically provided herein.

SECTION 3.7. Cooperation. The Company and the Consultant shall reasonably cooperate with each other in order to accomplish the purposes stated herein. The Company further agrees that it shall execute and deliver all applications, maps, plans, drawings, contracts, and other documents and instruments reasonably necessary to the development process and the Entitlements, as reasonably requested by Consultant and approved by the Company.

ARTICLE IV

CONSIDERATION

SECTION 4.1. Consideration. Subject to the terms and conditions set forth herein, as consideration for the Consultant Services, from and after the Entitlement Date, the Company shall pay to Consultant an amount (the “Entitlement Fee”) equal to 15% of the Net Profits less $5 million; provided, however, that in the event that the Net Profits received exceed $225 million, the Entitlement Fee shall be equal to 20% of the Net Profits received less $7.5 million. In no event, however, shall the Entitlement Fee be less than $1.00. The Entitlement Fee (if any) shall be the sole and exclusive consideration and/or compensation of any kind to Consultant; provided, however, that the Company shall reimburse Consultant for costs and expenses incurred by Consultant that are included in an Approved Entitlement Budget. Notwithstanding anything to the contrary herein or elsewhere, subject to Section 4.2, no Entitlement Fee shall be due or payable to Consultant unless the closing of a sale of all or a portion of the Lompoc Surface Estate generating Net Profits shall have actually taken place (whether or not any failure to enter into a sale transaction or any failure to actually close a sale transaction is due to any action or inaction by the Company or any other person or entity or for any other reason).

SECTION 4.2. Payments. To the extent the Company receives funds from the sale(s) of the Lompoc Surface Estate, prior to making any payments to Consultant the Company shall reimburse itself, DevelopmentCo and/or PXP for all Costs funded by the Company, DevelopmentCo and/or PXP plus an amount equal to 20% of such Costs. Amounts payable by the Company to Consultant pursuant to Section 4.1 will be paid to Consultant periodically if and

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when Net Profits are received by the Company within 30 days after the Company receives any funds that constitute Net Profits, by wire transfer of immediately available funds, provided however that in the event of a sale of all or any portion of the Lompoc Surface Estate prior to the Entitlement Date any amounts payable to Consultant pursuant to Section 4.1 and this Section 4.2 shall be retained by the Company in an escrow account until the Entitlement Date; provided, further, that the Company may, in its good faith reasonable discretion, withhold from any payments a portion of Net Profits representing a reserve against future commitments, expenses and contingent liabilities relating to the Entitlement or development of the Lompoc Surface Estate as are set forth in any Approved Entitlement Budget; provided, however, when such reserves are no longer needed by the Company in its reasonable discretion, they shall be deemed cash proceeds for the purpose of calculating Net Profits.

SECTION 4.3. Adjustment. (a) Upon the actual date which the last portion of the proceeds from the sale of the Lompoc Surface Estate is received by the Company, the Company shall calculate the Net Profits. In the event that the aggregate sum of all amounts paid by the Company to Consultant pursuant to Sections 4.1 and 4.2 of this Agreement (other than the reimbursement of Costs) exceed (i) in the event that Net Profits are less than $225 million, 15% of Net Profits as of such date less $5 million, or (ii) in the event that aggregate Net Profits exceed $225 million, 20% of Net Profits as of such date less $7.5 million, then Consultant shall pay to the Company an amount equal to such excess by wire transfer of immediately available funds to an account designated by the Company within 15 days of the Company’s notification of its determination of Net Profits; provided, however, that in no event shall amounts payable by Consultant pursuant to this Section 4.3 exceed the aggregate amount of payments previously paid to Consultant pursuant to this Agreement.

(b) In the event that the aggregate amount of Entitlement Fees paid to Consultant pursuant to Sections 4.1 and 4.2 hereof (other than the reimbursement of Costs) is less than (i) in the event that Net Profits are less than $225 million, 15% of Net Profits as of such date less $5 million, or (ii) in the event that aggregate Net Profits exceed $225 million, 20% of Net Profits less $7.5 million, then the Company shall pay to Consultant an amount equal to such deficiency by wire transfer of immediately available funds to an account designated by Consultant within 15 days of the Company’s determination of Net Profits.

ARTICLE V

TERMINATION

SECTION 5.1. Termination by the Company. At any time prior to the Entitlement Date, the Company shall have the right to terminate this Agreement upon written notice to Consultant. In the event that the Company terminates this Agreement for Cause (as defined in Section 5.2) all of the Company’s obligations under this Agreement shall terminate effective as of the date of such notice, including the Company’s obligation to make any payments to Consultant pursuant to Sections 4.1 and 4.2. In the event that the Company terminates this Agreement other than termination for Cause, the Company’s obligations pursuant to Sections 4.1 and 4.2 shall survive such termination.

SECTION 5.2. Definition of Cause. As used in this Agreement “Cause” shall mean:

(a) Any failure, refusal or neglect by Consultant at any time to perform fully any of Consultant’s material obligations hereunder, if such failure is not cured and continues for thirty (30) calendar days subsequent to Consultant’s receipt of written notice thereof from the Company;

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(b) Willful misconduct or gross negligence of any employees or management of Consultant that is not cured and continues for twenty (20) days after Consultant receives written notice from the Company that identifies the misconduct, negligence or actions taken in bad faith in connection with Consultant’s responsibilities under this Agreement;

(c) If at any time Lodwrick Cook (other than in the case of the death or legal disability) shall (i) cease to materially participate in the provision of the Consultant Services or (ii) cease to make himself generally available to management of the Company at reasonable times upon the Company’s reasonable notice; or

(d) Failure to achieve Entitlement prior to January 1, 2013, provided, however, that such deadline shall be extended by the number of days (if any) that Entitlement was actually delayed as a direct or indirect result of any failure of the Company to fund any costs or expenses necessary to obtain the Entitlements that were included in a budget approved by the Company.

SECTION 5.3. Termination by Consultant. In the event that (i) Entitlement has been achieved, (ii) the Company has received a bona fide offer from a third party ready, willing and able to purchase, fund and close on all or a portion of the Lompoc Surface Estate within 90 days at a price that exceeds the then-current value of the Mineral Rights as determined by PXP’s independent reserve engineers in accordance with Securities and Exchange Commission regulations, and (iii) the Company rejects such offer, then Consultant may terminate this Agreement and shall be entitled to receive 50% of the Entitlement Fee calculated as if such sale had occurred and any then incurred but unpaid reimbursable costs. In such event, upon any sale of the Lompoc Surface Estate the Company shall pay to Consultant the Entitlement Fee less the portion paid pursuant to the previous sentence.

ARTICLE VI

REPRESENTATIONS AND WARRANTIES

OF THE COMPANY

The Company hereby represents and warrants to Consultant (except as otherwise disclosed in writing on the date hereof and prior to the execution and delivery hereof) as follows:

SECTION 6.1. Organization; Authority. The Company is a limited liability company duly organized, validly existing and in good standing under the laws of the State of Delaware. The Company has the requisite power and authority necessary to execute and deliver this Agreement and to perform and consummate the transactions contemplated hereunder. The execution, delivery and performance by the Company of this Agreement and the consummation of the transactions contemplated hereby have been duly authorized by the Company and no other action on the part of the Company is necessary to authorize the execution, delivery and performance by the Company of this Agreement or the consummation of such transactions. This

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Agreement has been has been duly authorized, executed and delivered by, and assuming due authorization by Consultant, is enforceable against the Company, subject to bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium and similar laws of general applicability relating to or affecting creditor rights and for general equitable principles.

SECTION 6.2. No Conflict; Required Filings and Consents. The execution and delivery of this Agreement by the Company does not, and the performance by the Company of its obligations hereunder and the consummation of the transactions contemplated hereby will not, (i) conflict with or violate the Company’s charter documents, (ii) conflict with or violate any Law applicable to the Company or by which any property or asset of the Company is bound or (iii) violate any note, bond, mortgage, indenture, contract, agreement, lease, license, permit or other instrument or obligation to which the Company is a party or by which the Company or its properties may be bound, except in the case of (ii) and (iii) for any conflict or violation that does not materially adversely affect the performance of the Company’s obligations hereunder or the consummation of the transactions contemplated hereby.

SECTION 6.3. Condition of the Lompoc Surface Estate.

(a) Neither Company nor PXP has received any notice of, or has knowledge of, any pending or threatened taking or condemnation of the Lompoc Surface Estate or any portion thereof.

(b) The Lompoc Surface Estate is free of any right of possession or claim of right of possession of any party other than the Company, and there are no leases or occupancy agreements currently affecting any portion of the Lompoc Surface Estate, except for easements and for any such rights, claims, leases or agreements relating to the Mineral Rights.

(c) Neither the Company nor PXP has received a notice of, or has knowledge of, any material violations of law, municipal or county ordinances, or other legal requirements with respect to the Lompoc Surface Estate or with respect to the use, occupancy or construction thereon.

(d) There are no purchase contracts or option agreements affecting the Lompoc Surface Estate.

(e) PXP will transfer to the Company fee title to the Lompoc Surface Estate as soon as practicable after the date hereof, but in any event no later than the Entitlement Date.

(f) Neither the Company nor PXP is a party to any litigation, arbitration, or administrative proceeding affecting the Lompoc Surface Estate or the Company’s ability to perform its obligations hereunder and to the knowledge of Company, no such litigation, arbitration or administrative proceeding is threatened.

(g) The Company has provided Consultant with the Phase I environmental report prepared on the Lompoc Surface Estate and other than related to PXP’s oil and gas operations, to the Company’s knowledge there are no Hazardous Materials situated on, under or about the Lompoc Surface Estate in violation of applicable law.

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ARTICLE VII

REPRESENTATIONS AND WARRANTIES

OF CONSULTANT

Consultant hereby represents and warrants to the Company (except as otherwise disclosed in writing on the date hereof and prior to the execution and delivery hereof) as follows:

SECTION 7.1. Organization; Authority. Consultant is a limited liability company duly organized, validly existing and in good standing under the laws of the State of California. Consultant has the requisite power and authority necessary to execute and deliver this Agreement and to perform and consummate the transactions contemplated hereunder. The execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby by Consultant have been duly authorized by Consultant, and no other action on the part of Consultant is necessary to authorize the execution, delivery and performance of this Agreement or the consummation of such transactions by Consultant. This Agreement has been duly authorized, executed and delivered by, and assuming due authorization by the Company, is enforceable against Consultant, subject to bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium and similar laws of general applicability relating to or affecting creditor rights, and for general equitable principles whether applied in a proceeding at law or in equity.

SECTION 7.2. No Conflict; Required Filings and Consents. The execution and delivery of this Agreement by Consultant does not, and the performance by Consultant of its obligations hereunder and the consummation of the transactions contemplated hereby will not, (i) conflict with or violate the organizational or governing documents of Consultant, (ii) conflict with or violate any Law applicable to Consultant or by which any property or asset of Consultant is bound or (iii) result in any violation pursuant to, any note, bond, mortgage, indenture, contract, agreement, lease, license, permit, franchise or other instrument or obligation to which Consultant is a party or by which Consultant or any of its properties may be bound, except in the case of (ii) and (iii) for any conflict or violation that does not materially adversely affect the performance of Consultant’s obligations hereunder or the consummation of the transactions contemplated hereby.

SECTION 7.3. Lompoc Surface Estate. Consultant agrees that (i) it has had the opportunity to perform any inspections, tests and/or studies that it desired or deemed necessary or appropriate in order to determine the suitability of the Lompoc Surface Estate for the Company’s intended use thereof, and (ii) it has had the opportunity to review all instruments, records, documents, and studies concerning the Lompoc Surface Estate (including zoning, ordinances and regulations and any other laws, ordinances or governmental regulations restricting or regulating the use, occupancy or enjoyment of the Lompoc Surface Estate) which it deemed appropriate or advisable to review. Consultant also acknowledges that it has relied and will be relying on the advice of its own consultants and advisors that in its sole discretion it has deemed appropriate concerning its execution of this Agreement, the development of the Lompoc Surface Estate and the viability and suitability of the Lompoc Surface Estate for the Company’s intended uses.

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SECTION 7.4. Other Agreements. All arrangements and agreements between Consultant and and any non-affiliated third party relating to the Lompoc Surface Estate and/or any amounts which may become payable pursuant to this Agreement have been disclosed to the Company and are set forth on Schedule 7.4 hereto, and Consultant hereby agrees to disclose to the Company any such arrangements or agreements upon entering into such arrangements or agreements.

SECTION 7.5. “AS-IS” CONSULTANT ACKNOWLEDGES AND AGREES THAT, NONE OF PXP, DEVELOPMENTCO OR THE COMPANY HAS MADE, DOES MAKE OR WILL MAKE (AND EACH OF PXP, DEVELOPMENTCO AND THE COMPANY HEREBY SPECIFICALLY NEGATES AND DISCLAIMS) ANY REPRESENTATIONS, WARRANTIES, OR GUARANTIES OF ANY KIND OR CHARACTER WHATSOEVER, WHETHER EXPRESS OR IMPLIED, ORAL OR WRITTEN, PAST, PRESENT OR FUTURE, OF, AS TO, CONCERNING OR WITH RESPECT TO ANY MATTER (EXCEPT FOR EXPRESS REPRESENTATIONS AND WARRANTIES IN THIS AGREEMENT), INCLUDING, WITHOUT LIMITATION, WITH RESPECT TO ANY OF THE FOLLOWING MATTERS CONCERNING THE LOMPOC SURFACE ESTATE: (I) VALUE OR ANY ANTICIPATED SALE PRICES OF LOTS OR OTHER PORTIONS THEREOF; (II) REVENUE TO BE DERIVED; (III) SUITABILITY FOR ANY AND ALL ACTIVITIES AND USES, INCLUDING THE POSSIBILITIES FOR FUTURE DEVELOPMENT; (IV) HABITABILITY, MERCHANTABILITY, MARKETABILITY, PROFITABILITY OR FITNESS FOR A PARTICULAR PURPOSE; (V) NATURE, QUALITY OR CONDITION, INCLUDING WATER, SOIL AND GEOLOGY; (VI) COMPLIANCE WITH ANY LAWS, RULES, ORDINANCES OR REGULATIONS; (VII) MANNER OR QUALITY OF THE CONSTRUCTION OR MATERIALS, IF ANY; (VIII) COMPLIANCE WITH ANY ENVIRONMENTAL PROTECTION, POLLUTION, ENDANGERED SPECIES OR LAND USE LAWS, RULES, REGULATIONS, ORDERS OR REQUIREMENTS, INCLUDING BUT NOT LIMITED TO, THE AMERICANS WITH DISABILITIES ACT OF 1990, HEALTH & SAFETY CODE, WATER POLLUTION CONTROL ACT, RESOURCE CONSERVATION AND RECOVERY ACT, ENVIRONMENTAL PROTECTION AGENCY REGULATIONS, THE COMPREHENSIVE ENVIRONMENTAL RESPONSE, COMPENSATION AND LIABILITY ACT OF 1980, AS AMENDED, THE RESOURCE CONSERVATION AND RECOVERY ACT OF 1976, THE CLEAN WATER ACT, THE SAFE DRINKING WATER ACT, THE HAZARDOUS MATERIALS TRANSPORTATION ACT, THE TOXIC SUBSTANCE CONTROL ACT; (IX) PRESENCE OR ABSENCE OF HAZARDOUS MATERIALS AT, ON, UNDER, OR ADJACENT TO THE LOMPOC SURFACE ESTATE, (X) CONTENT, COMPLETENESS OR ACCURACY OF ANY DOCUMENTS PROVIDED TO CONSULTANT BY PXP, DEVELOPMENTCO OR THE COMPANY OR OTHERS OR ANY TITLE REPORT, TITLE COMMITMENT OR SURVEY; (XI) CONFORMITY OF ANY IMPROVEMENTS TO ANY PLANS OR SPECIFICATIONS; (XII) CONFORMITY TO PAST, CURRENT OR FUTURE APPLICABLE ZONING OR BUILDING REQUIREMENTS; (XIII) DEFICIENCY OF ANY UNDERSHORING; (XIV) DEFICIENCY OF ANY DRAINAGE; (XV) POSSIBLE LOCATION IN, ON OR NEAR AN EARTHQUAKE FAULT LINE,

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LIQUEFACTION AREA, FLOOD AREA, FIRE HAZARD OR OTHER HAZARDOUS AREA; OR (XVI) EXISTENCE OF LAND USE, ZONING OR BUILDING ENTITLEMENTS OR (XVII) ANY MATTER RELATING TO THE SUBSURFACE RIGHTS, OIL OPERATIONS OR OTHER RIGHTS RETAINED BY PXP. CONSULTANT FURTHER ACKNOWLEDGES AND AGREES THAT TO THE MAXIMUM EXTENT PERMITTED BY LAW (EXCEPT FOR EXPRESS REPRESENTATIONS AND WARRANTIES SET FORTH IN THIS AGREEMENT), THE CONDITION OF THE LOMPOC SURFACE ESTATE AND ANY OTHER RELATED MATTERS HAS BEEN MADE IN/ON AN “AS IS” CONDITION AND BASIS WITH ALL FAULTS, AND THAT NONE OF PXP, DEVELOPMENTCO OR THE COMPANY HAS ANY OBLIGATIONS TO MAKE REPAIRS, REPLACEMENTS OR IMPROVEMENTS.

ARTICLE VIII

MISCELLANEOUS

SECTION 8.1. Entire Agreement. This Agreement, together with the exhibits and schedules hereto and the certificates, documents, instruments and writings that are delivered pursuant hereto constitutes the entire agreement and understanding of the parties in respect of its subject matter and supersedes all prior understandings, agreements, or representations by or among the parties, written or oral, to the extent they relate in any way to the subject matter hereof. There are no third party beneficiaries having rights under or with respect to this Agreement except that PXP and DevelopmentCo, and Lodwrick Cook with respect to the consulting fee to be paid to him pursuant to (ix) of the definition of “Costs” herein, are express intended third party beneficiaries of this Agreement and shall be entitled to the benefits of and to enforce the terms of this Agreement.

SECTION 8.2. Successors; Etc. All of the terms, agreements, covenants, representations, warranties, and conditions of this Agreement are binding upon, and inure to the benefit of and are enforceable by, the parties and their respective successors. Consultant shall not, and hereby expressly waives any right to, assign, directly or indirectly, any of its rights under this Agreement or to file or record this Agreement or any notice hereof or any notice of any action hereon in any public records or give any notice to or make any claim or demand with respect to this Agreement to, in or against any third party or any escrow.

SECTION 8.3. Notices. All notices, requests, demands, claims and other communications hereunder will be in writing. Any notice, request, demand, claim or other communication hereunder will be deemed duly given if (and then three (3) business days after) it is sent by registered or certified mail, return receipt requested, postage prepaid, and addressed to the intended recipient as set forth the signature pages hereto. Any party may send any notice, request, demand, claim, or other communication hereunder to the intended recipient at the address set forth above using any other means (including personal delivery, expedited courier, messenger service, telecopy, telex, ordinary mail, or electronic mail), but no such notice, request, demand, claim, or other communication will be deemed to have been duly given unless and until it actually is received by the intended recipient. Any party may change the address to which notices, requests, demands, claims, and other communications hereunder are to be delivered by giving the other parties notice in the manner herein set forth, or may require the delivery of up to one additional copy.

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SECTION 8.4. Specific Performance. Each party acknowledges and agrees that the other party would be irreparably damaged if any provision of this Agreement is not performed in accordance with its specific terms or is otherwise breached. Accordingly, each party agrees that the other parties will be entitled to an injunction or injunctions to prevent breaches of the provisions of this Agreement and to specifically enforce this Agreement and its terms and provisions in any action instituted in any court of the United States or any state thereof having jurisdiction over the parties in the matter, subject to this Section 8.4 and Section 8.7, in addition to any other remedy to which such party may be entitled, at law or equity. .

SECTION 8.5. Counterparts. This Agreement may be executed in two or more counterparts, each of which will be deemed an original but all of which together will constitute one and the same instrument.

SECTION 8.6. Headings. The section headings contained in this Agreement are inserted for convenience only and will not affect in any way the meaning or interpretation of this Agreement.

SECTION 8.7. Governing Law and Dispute Resolution.

(a) This Agreement and the performance of the transactions contemplated hereby and the obligations of the parties hereunder will be governed by and construed in accordance with the laws of the State of California, without giving effect to any choice of law principles.

(b) The parties agree that any and all disputes, claims or controversies arising out of or relating to this Agreement shall be first submitted to JAMS or its successor, for mediation, and if the matter is not resolved through mediation, then it shall be submitted to JAMS, or its successor, for final and binding arbitration pursuant to the arbitration clause set forth below. Either party may commence mediation by providing to JAMS and the other party a written request for mediation, setting forth the subject of the dispute and the relief requested. The parties will cooperate with JAMS and with one another in selecting a mediator from JAMS panel of neutrals, and in scheduling the mediation proceedings. The parties covenant that they will participate in the mediation in good faith, and that they will share equally in its costs. All offers, promises, conduct and statements, whether oral or written, made in the course of the mediation by any of the parties, their agents, employees, experts and attorneys, and by the mediator or any JAMS employees, are confidential, privileged and inadmissible for any purpose, including impeachment, in any arbitration or other proceeding involving the parties, provided that evidence that is otherwise admissible or discoverable shall not be rendered inadmissible or non-discoverable as a result of its use in the mediation. Either party may initiate arbitration with respect to the matters submitted to mediation by filing a written demand for arbitration at any time following the initial mediation session or 45 days after the date of filing the written request for mediation, whichever occurs first. The mediation may continue after the commencement of arbitration if the parties so desire. Unless otherwise agreed by the parties, the mediator shall be disqualified from serving as arbitrator in the case.

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The provisions of this clause (b) may be enforced by any Court of competent jurisdiction, and the party seeking enforcement shall be entitled to an award of all costs, fees and expenses, including attorneys’ fees, to be paid by the party against whom enforcement is ordered.

(c) Any dispute, claim or controversy arising out of or relating to this Agreement or the breach, termination, enforcement, interpretation or validity thereof, including the determination of the scope or applicability of this agreement to arbitrate, which has failed to be resolved during the mediation process above shall be determined by arbitration before a panel of three (3) arbitrators. The arbitration shall be administered by JAMS pursuant to its Comprehensive Arbitration Rules and Procedures (Streamlined Arbitration Rules and Procedures). Unless the parties agree otherwise, the place of arbitration shall be Los Angeles, California. The arbitrators shall not be empowered to award any form of exemplary or punitive damages. As part of any arbitral award pursuant to this paragraph, the arbitrators shall render a reasoned award. The parties consent to judgment on such award being entered in any court having jurisdiction.

(d) Each party is required to continue to perform its obligations under this Agreement pending final resolution of any dispute.

(e) Should any party hereto institute any arbitration proceedings permitted under this Section 8.7, the prevailing party (as determined by the arbitral panel) shall be entitled to recover costs of the arbitration proceeding and reasonable attorneys’ fees to be fixed by the arbitral panel.

(f) Any judicial proceedings permitted to be brought with respect to this Agreement shall be brought in any state or federal court of competent jurisdiction in the State of California, and the parties generally and unconditionally accept the exclusive jurisdiction of such courts. The parties waive, to the fullest extent permitted by applicable Law, any objection which they may now or hereafter have to the bringing of any such action or proceeding in such jurisdiction.

SECTION 8.8. Amendments and Waivers. No amendment, modification, replacement, termination or cancellation of any provision of this Agreement will be valid, unless the same will be in writing and signed by each party hereto. Neither any failure nor any delay by any party in exercising any right, power or privilege under this Agreement will operate as a waiver of such right, power or privilege, and no single or partial exercise of any such right, power or privilege will preclude any other or further exercise of such right, power or privilege or the exercise of any other right, power or privilege. To the maximum extent permitted by applicable law, (a) no claim or right arising out of this Agreement can be discharged by one party, in whole or in part, by a waiver or renunciation of the claim or right unless in writing signed by the other party; (b) no waiver that may be given by a party will be applicable except in the specific instance for which it is given; and (c) no notice to or demand on one party will be deemed to be a waiver of any obligation of that party or of the right of the party giving such notice or demand to take further action without notice or demand as provided in this Agreement.

SECTION 8.9. Severability. The provisions of this Agreement are severable, and the invalidity of any provision shall not affect the validity of any other provision.

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SECTION 8.10. Expenses. Except as otherwise expressly provided in this Agreement, each party will bear its own costs and expenses incurred in connection with the negotiation and preparation of this Agreement.

SECTION 8.11. Construction. This Agreement will be deemed to have been drafted by both parties thereto and will not be construed against either party as the draftsperson hereof. “Including” or “include” or “includes” or “including without limitation” means “including without limitation”.

SECTION 8.12. Incorporation of Exhibits, Annexes and Schedules. The exhibits, annexes, schedules, and other attachments identified in this Agreement are incorporated herein by reference and made a part hereof.

SECTION 8.13. Remedies. Except as expressly provided herein, the rights, obligations and remedies created by this Agreement are cumulative and in addition to any other rights, obligations, or remedies otherwise available at law or in equity. Except as expressly provided herein, nothing herein will be considered an election of remedies.

SECTION 8.14. Other Business Interests/No Fiduciary Duty. The parties and their respective members and affiliates may engage, directly or indirectly, without consent of the other parties, in other business opportunities or arrangements, independently or with others, including those competitive with the Company, regardless of geographic location, and without any duty or obligation to offer or account to the other parties. Without limitation, PXP owns the Mineral Rights which now and may hereafter burden the Lompoc Surface Estate and Consultant acknowledges its understanding that PXP shall be free to exploit the same in any manner even if it would be harmful to the Company’s interests in the Lompoc Surface Estate or hinder, delay or prevent the Entitlement or development thereof and/or Consultant’s ability to earn any (or the amount, if any) Entitlement Fee. Consultant acknowledges its understanding that PXP will have conflicts of interests arising from its other business interests, including the Mineral Rights. Further, PXP and the Company are free to act in their own best interests and in accordance with their respective sole and absolute discretion as to all aspects of the Lompoc Surface Estate, including the Entitlement, development, budgeting, scheduling, financing and/or sale thereof, notwithstanding any adverse impact on Net Profits. Without limiting the foregoing or any other provision of this Agreement, Consultant specifically acknowledges its understanding that the Company and PXP may elect to delay providing funding for the Entitlement and development process at any time and/or elect to delay the development of the Lompoc Surface Estate for residential purposes despite whether any such delay or abandonment could impact the timing and amount of Entitlement Fees (if any) payable hereunder. Further, nothing herein is intended to create a partnership, joint venture, agency, or other relationship creating fiduciary or quasi-fiduciary duties and obligations or to impose any duty, obligation, or liability that would arise therefrom with respect to any or all of the parties or their Affiliates or any permitted assigns. Neither party shall be deemed to be a fiduciary to the other party. To the full extent permitted by law, the parties waive any such fiduciary obligations as might have otherwise applied.

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[Signature page follows]

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IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their respective officers thereunto duly authorized, all as of the date first written above.

COOK HILL PROPERTIES LLC
By:	/s/ Lodwrick M. Cook
Name:	Lodwrick M. Cook
Title:	Managing Member
Copy of any notices, requests, demands, claims and other communications to be sent to:
9355 Wilshire Boulevard, 4th Floor
Beverly Hills, CA 90210
Attn: Gerry Ginsberg
LOMPOC LAND COMPANY LLC
By its Sole Member:
Plains Exploration and Production Company
By:	/s/ John F. Wombwell
Name:	John F. Wombwell
Title:	Executive Vice President, General Counsel and Secretary
Copy of any notices, requests, demands, claims and other communications to be sent to:
Plains Exploration & Production Company
700 Milam, Suite 3100
Houston, TX 77002
Attn: John F. Wombwell

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EXHIBIT A

PARCEL MAP INCLUDING LOMPOC SURFACE ESTATE

A-1

EXHIBIT A.1

LEGAL DESCRIPTION OF REAL PROPERTY

WHICH INCLUDES LOMPOC SURFACE ESTATE

That portion of the Rancho Mission de La Purisima, in the County of Santa Barbara, State of California, being the First Parcel described in a deed granted to the Union Oil Company of California, recorded April 30, 1903 in Book 89, Page 200 of Deeds, Government Lots 1, 2 and 3 of Section 27, Government Lots 1 and 2 Section 34 and Government Lots 1 and 2 of Section 35, Township 8 North, Range 34 West, San Bernardino Meridian according to the Official Plat thereof on the file in the General Land Office.

Except therefrom that portion of said land granted to the Union Oil Company of California that lies easterly of the westerly line of the land described in a deed granted to the County of Santa Barbara, recorded June 7, 1932 in Book 265, Page 272 of Official Records.

Also excepting therefrom that portion of said land that lies within the boundaries of the land described in a deed granted to the State of California and recorded July 6, 1981 as Instrument No. 81-27447 of Official Records.

Also excepting therefrom that portion of said land that lies within the boundaries of the land described in a deed granted to the State of California and recorded June 20, 1991 as Instrument No. 91-038941 of Official Records.

Also excepting therefrom that portion of said land described as last exception to “Parcel A” and shown as the 100 acre exception on Sheet 7 of 7 of Exhibit A in a deed granted to the State of California and recorded June 20, 1991 as Instrument No. 91-038941 of Official Records.

A.1-1

EXHIBIT B

LEGAL DESCRIPTION OF MINERAL RIGHTS

“Mineral Rights” means

(1) all oil, gas and other hydrocarbon substances, and all other mineral and otherwise valuable substances, in the Lompoc Surface Estate or under the Lompoc Surface Estate or which may be produced therefrom; and the sole and exclusive right to the possession, use, development and improvement of the surface and all subsurface depths thereof as may be necessary or convenient to surveying, prospecting and exploring for, producing, storing, treating, and transporting any and all such substances; including operations (and such possession, use, development and improvement of the surface and all subsurface depths thereof as may be necessary or convenient to operations) by means and in a manner now known or unknown; and, further, including the exclusive right to mine or drill from the surface of, or into or through the subsurface of, any part of the Lompoc Surface Estate in connection with operations incidental to surveying, prospecting and exploring for, producing, storing, treating, and transporting any and all such substances within and from any and all other lands; and, further, including the exclusive right to the possession, use, development and improvement of the surface and all subsurface depths thereof as may be necessary or convenient to surveying, prospecting and exploring for, producing, storing, treating, and transporting any and all such substances within and from any and all lands other than and in addition to the Lompoc Surface Estate (all of which are hereinafter referred to and included within the “Mineral Interest” in the Lompoc Surface Estate); and

(2) all of PXP’s existing right, title and interest in, to and under any and all oil and gas leases affecting all or any part of the Lompoc Surface Estate (which, if any, are hereinafter referred to collectively as the “Leases”);

(3) all right, title and interest of PXP in, to and under easements, tangible and intangible personal property, facilities, fixtures, equipment, rights and benefits incidental and appurtenant to the ownership, use or operation of any part of the Mineral Interest, under the Leases or otherwise, within all or any part of the Lompoc Surface Estate or other lands, or both, including, without limitation:

(a) all contracts and agreements whether recorded or unrecorded in existence at the Effective Date, which affect any part of the Mineral Interest in the Lompoc Surface Estate, or other lands, or any of the Leases; and

(b) all facilities and equipment (whether active or inactive) customarily used directly in the production of crude oil, natural gas, casinghead gas, condensate, sulphur, natural gas liquids, plant products and other liquid or gaseous hydrocarbon substances (including CO₂), and all other minerals of every kind and character attributable to PXP’s interest in any part of the Lompoc Surface Estate, or other lands, or any of the Leases (collectively, “Hydrocarbons”), including but not limited to wells (whether plugged or unplugged), injection

B-1

facilities, disposal facilities, equipment, fixtures, incidentals and appurtenances, facilities and personal property of any kind (including, but not limited to, tubing, casing, wellheads, pumping units, production units, compressors, valves, meters, flowlines, pipelines and other lesser piping, tanks, heaters, separators, dehydrators, pumps, injection units, gates and fences, field separators, liquid extractors, compressors, LACT units; plants, tanks and the like); and

(c) presently existing pooling, unitization and communitization agreements or other operating agreements and the right, title and interest of PXP in and to the units created thereby (including without limitation all units formed under orders, regulations, rules or other official acts of any governmental entity, agency or officer) related, incidental or appurtenant to the Mineral Interest in any part of the Lompoc Surface Estate, or other lands, or any of the Leases; and

(d) exclusive and non-exclusive rights to the use and occupancy of land, including, without limitation, tenements, appurtenances, surface leases, easements, permits, licenses, franchises, servitudes and rights-of-way appertaining, belonging, affixed or incidental to or used in connection with the ownership of the Mineral Interest, or operations incidental to the enjoyment of the Mineral Interest, in any part of the Lompoc Surface Estate, or other lands, or any of the Leases, whether recorded or unrecorded; and

(e) licenses, authorizations, permits, variances and similar rights and interests, and other rights, privileges, benefits and powers conferred upon the owner of the Mineral Interest, or operations incidental to the enjoyment of the Mineral Interest, in any part of the Lompoc Surface Estate, or other lands, or upon the holder of any of the Leases, including, without limitation, all claims causes of action, insurance policies or proceeds therefrom, appertaining, belonging, affixed or incidental to or held or exercised in connection with the Mineral Interest in any part of the Lompoc Surface Estate, or other lands, or any of the Leases; and

(f) general operating records, well files (including applicable well logs and production data), lease files, land files, environmental compliance files, regulatory reports and certificates, abstracts and title work appertaining, belonging or incidental to the Mineral Interest in any part of the Lompoc Surface Estate, or other lands, or any of the Leases; and

all easements and rights-of-way of any kind or nature standing in the name of, reserved by or granted by PXP, PXP’s predecessors, subsidiaries or affiliates or any predecessor, subsidiary or affiliate, related to the Lompoc Surface Estate, whether or not such rights appear of record and whether or not identifiable by inspection of the real property, and all equipment, pipelines, powerlines and other facilities used in association with such easements and rights-of-way.

B-2

SCHEDULE 7.4

THIRD PARTY AGREEMENTS

Consultant is in discussions with the Ezralow Company and John Markley pursuant to which it expects to enter into an agreement to engage both parties to assist Consultant in performing the services contemplated herein.

7.4-1

EX-10.5

Exhibit 10.5

CONSULTING AGREEMENT

This Consulting Agreement (the “Agreement”) is entered into as of January 19, 2006 by and between by and between Arroyo Grande Land Company LLC (the “Company”), a wholly owned subsidiary of Plains Exploration & Production Company (“PXP”), and Cook Hill Properties LLC (“Consultant”).

BACKGROUND:

A. PXP will contribute to the Company that certain surface estate of land comprising not more than 325 acres located in San Luis Obispo County, California, being a portion of the property described more fully on Exhibit A (the “Arroyo Grande Surface Estate”), and PXP will retain all right, title and interest in and to any Mineral Rights (as defined below).

B. Consultant has a management team with expertise in the entitlement and development of residential communities in Southern California and the Company desires that Consultant assist the Company with the entitlement and development of the Arroyo Grande Surface Estate and Consultant desires to do so.

AGREEMENT:

NOW, THEREFORE, in consideration of the foregoing and the respective representations, warranties, covenants and agreements set forth in this Agreement, the parties hereto agree as follows:

ARTICLE I

DEFINITIONS

“Costs” means the following: all costs, expenses, fees, charges and losses related to and applicable to the Arroyo Grande Surface Estate which are, or are to be, or have been, paid, delivered and/or incurred by the Company, by DevelopmentCo or by PXP, whether before or after any Entitlements are obtained (without duplication), including, without limitation: (i) all costs, fees and expenses relating to Entitlements, (ii) all salaries and other general and administrative and operating expenses of the Company and DevelopmentCo (including expense reimbursements paid under this Agreement with respect to the Consultant Services), but not including any salaries or other expenses of PXP personnel, (iii) expenses, fees and costs relating to the ownership, development, entitlement, improvement, subdivision, management and land preparation of the Arroyo Grande Surface Estate, including costs, expenses, fines or other liabilities arising out of any suits, claims, administrative or other proceedings against Company or its affiliates and equity holders relating to the Arroyo Grande Surface Estate imposed or initiated by a governmental authority or any other person or entity; provided, that this clause (iii) shall not include any costs, expenses, fines or other liabilities arising out of any suits, claims, administrative or other proceedings relating to (a) PXP’s exploitation of the Mineral Rights or

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(b) Excluded Mineral Rights Costs, (iv) all property taxes (excluding those applicable to the Mineral Rights), (v) all costs, fines and expenses of any environmental clean-up or remediation of the Arroyo Grande Surface Estate (other than Excluded Mineral Rights Costs), including liabilities arising out of any suits, claims, administrative or other proceedings relating thereto, (vi) expenses incurred in connection with the collection of any amounts owed to the Company by any person, (vii) all professional fees, including attorneys, accountants, agents, appraisers, consultants, environmental experts and other consultants, incurred in connection with the ownership, development, entitlement, improvement, subdivision, management, or land preparation of the Arroyo Grande Surface Estate, (viii) all financing costs and fees, including interest, points and loan fees, and amounts payable by the Company to any third party in connection with any form of equity financing or investment by third party in connection with the development and maintenance of the Arroyo Grande Surface Estate; provided, that this clause (viii) shall not include any such financing that is non-recourse to PXP, (ix) a consulting fee to Lodwrick Cook of $1 per month; and (x) all costs associated with any sale, disposition or transfer (or any proposed sale, disposition or transfer) of any portion of the Arroyo Grande Surface Estate, including marketing, legal and accounting fees, brokerage fees, sale commissions, bank charges, transfer fees, custodial fees, costs, closing costs, escrow fees, and other related costs and expenses. Notwithstanding the foregoing, it is agreed that (a) costs incurred to the date hereof shall not exceed $2.5 million in the aggregate, (b) the Entitlement Fee (as defined in Section 4.1) shall not be included in the definition of Costs, and (c) Costs shall not include any costs, expenses, fees, charges and losses incurred by DevelopmentCo or PXP relating to the ownership, development and entitlement of PXP’s real property located in the City of Montebello, California and in Santa Barbara County, California which are included in “Costs” under either of the respective Consulting Agreements entered into as of even date herewith.

“DevelopmentCo” means Cane River Development LLC, a Delaware limited liability company.

“Entitlement” means that the Company has obtained all of the Entitlements.

“Entitlements” means all permits, licenses, approvals and other administrative certifications and satisfaction of other requirements (federal, state and local) as may be reasonably necessary to commence and carry out the development of the Arroyo Grande Surface Estate as a residential project, in accordance with such development plans and development budgets as may be, from time to time, proposed by the Consultant and approved by the Company in the Company’s reasonable discretion as evidenced by formal written resolutions of the Company. Without limiting the scope of the forgoing, Entitlements shall include the following permits, licenses, approvals and other administrative certifications: (i) the Final Environmental Assessment/§404 Permit to be issued by the U. S. Army Corps of Engineers; (ii) final permits from the Regional Water Quality Control Board and the California Department of Fish & Game; (iii) a final Environmental Impact Report to be issued by the County of San Luis Obispo, California; (iv) the final Development Agreement (including A level and final B Level maps); and (v) Redevelopment Agreement with the County of San Luis Obispo.

“Entitlement Date” means the date, if any, on which the Company has actually obtained all the Entitlements.

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“Excluded Mineral Rights Costs” means all costs, expenses and liabilities (i) relating to environmental liabilities or conditions of the Arroyo Grande Surface Estate and Mineral Rights which PXP has actual knowledge as of the date hereof, and (ii) resulting from PXP’s exploitation of the Mineral Rights during the period subsequent to the date hereof, provided, however, costs associated with plugging oil wells which have previously been plugged and abandoned by PXP shall not constitute Excluded Mineral Rights Costs.

“Hazardous Materials” means petroleum and petroleum products and compounds containing them, including gasoline, diesel fuel and oil; explosives; flammable materials; radioactive materials; polychlorinated biphenyls (“PCBs”) and compounds containing them; lead and lead-based paint; asbestos or asbestos-containing materials in any form that is or could become friable; underground or above-ground storage tanks, whether empty or containing any substance; radon; Mold; toxic or mycotoxin spores; any substance the presence of which on the property is prohibited by any federal, state or local authority; any substance that requires special handling under any Hazardous Materials Law; and any other material or substance (whether or not naturally occurring) now or in the future that (i) is defined as a “hazardous substance,” “hazardous material,” “hazardous waste,” “toxic substance,” “toxic pollutant,” “solid waste,” “pesticide,” “contaminant, “ or “pollutant” or otherwise classified as hazardous or toxic by or within the meaning of any Hazardous Materials Law, or (ii) is regulated in any way by or within the meaning of any Hazardous Materials Law.

“Hazardous Materials Law” means all federal, state, and local laws, ordinances and regulations and standards, rules, policies and other governmental requirements, rules of common law (including without limitation nuisance and trespass), consent order, administrative rulings and court judgments and decrees or other government directive in effect now or in the future and including all amendments, that relate to Hazardous Materials or to the protection or conservation of the environment or human health, including without limitation those relating to industrial hygiene, or the use, analysis, generation, manufacture, storage, discharge, release, disposal, transportation, treatment, investigation or remediation of Hazardous Materials. Hazardous Materials Laws include, but are not limited to, the Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. Section 9601, et seq., the Resource Conservation and Recovery Act, 42 U.S.C. Section 6901, et seq., the Toxic Substance Control Act, 15 U.S.C. Section 2601, et seq., the Clean Water Act, 33 U.S.C. Section 1251, et seq., and the Hazardous Materials Transportation Act, 49 U.S.C. Section 5101, et seq., the Superfund Amendments and Reauthorization act, the Solid Waste Disposal Act, the Clean Water Act, the Clean Air Act, the Toxic Substances Control Act, the Occupational Safety and Health Act, and their state analogs

“Laws” means any law (statutory, common, or otherwise), constitution, treaty, convention, ordinance, equitable principle, code, rule, regulation, executive order, or other similar authority enacted, adopted, promulgated, or applied by any governmental authority, each as amended and now and hereinafter in effect.

“Mineral Rights” means all surface and subsurface rights to and ownership of (along with the rights of surface entry to extract) all minerals, oil and gas in, on under and around the land constituting the Arroyo Grande Surface Estate as more fully described in Exhibit B hereto.

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“Net Profits” means, at any time, the (a) the sum of all gross cash proceeds received by the Company from the sale(s) of the Arroyo Grande Surface Estate or any portion thereof (including non-refundable amounts irrevocably received for granting options to a buyer), minus (b) all Costs and minus (c) an amount equal to 20% of the aggregate Costs, provided that “Costs” for purposes of this clause (c) only shall not include any consulting fees paid to Lodwrick Cook. For purposes of determining Net Profits, no Net Profits will be deemed received with respect to any promissory note until and only to the extent that cash payments are actually received by the Company on such promissory note.

“Senior Management of Consultant” shall mean Lodwrick Cook, John Markley or any other senior management individuals of Consultant that are reasonably acceptable to the Company.

ARTICLE II

ENGAGEMENT; TERM

SECTION 2.1. Engagement as Independent Contractor. The Company hereby retains Consultant and Consultant hereby accepts such retention, as an independent contractor to provide the Consultant Services (as defined below). Consultant shall be and at all times relevant hereto remain an independent contractor of the Company.

SECTION 2.2. Term. This Agreement shall remain in effect from the date hereof until the earlier to occur of (the “Termination Date”): (i) termination by the Company in accordance with ARTICLE V or (ii) sale, transfer or other disposition of all of the Company’s right, title and interest in the Arroyo Grande Surface Estate, the collection of all sales proceeds in connection therewith (including any that are deferred) and the making of any payment which may be due under Article IV in connection therewith. Subject to the Company’s obligations pursuant to Section 5.1 in connection with a termination without Cause, upon termination, the Company shall thereafter have no further obligations to Consultant and Consultant shall have no further obligations to the Company under ARTICLE III for future Consultant Services.

ARTICLE III

CONSULTANT SERVICES

SECTION 3.1. Consultant Services. Consultant hereby agrees to provide the following services to the Company and DevelopmentCo from and after the date hereof until the Termination Date (the “Consultant Services”), all subject to the direction, oversight and approval of the Company in its reasonable discretion:

(a) expertise, advice, guidance, management, recommendations and other assistance in obtaining the Entitlements and plans for development of the Arroyo Grande Surface Estate;

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(b) coordinate, meet, negotiate and interact with local, state and federal regulatory authorities regarding the Entitlements and development, including preparation and filing of all necessary applications, filings, permit requests and other documentation as may be required in connection with obtaining the Entitlements;

(c) regularly report to the Company and DevelopmentCo regarding the status of the Entitlement process, and provide such information and progress updates regarding the Entitlements as may be requested by the Company, including weekly progress reports and monthly reports to PXP management, critical path schedules, cost estimates and budget refinements;

(d) preparation of budgets, financial models and forecasts regarding the Entitlements process and development (provided that no budget shall be deemed approved by the Company unless formally adopted in writing by the Company in accordance with this Agreement in its reasonable discretion);

(e) assist the Company and DevelopmentCo in identifying sources of third party financing for development after the Entitlement Date, and, subject to formal written approval of the Company, negotiate the terms of any financings with such sources;

(f) infrastructure planning;

(g) manage community and public affairs relating to obtaining the Entitlements and development;

(h) negotiate and arrange for the services of third party contractors;

(i) development of a post-Entitlement Date plan of development, including budgets, financing and marketing plans;

(j) prepare, or cause to be prepared such environmental and neighborhood impact studies or reports, engineering surveys, hazardous substance reports, preliminary plans and specifications, as may be requested by the Company or DevelopmentCo in connection with the Entitlement process and development;

(k) perform, or cause to be performed, an analysis of the market and demographic environment to determine the feasibility of development plans under consideration by the Company;

(l) the services of Lodwrick Cook to serve as CEO of DevelopmentCo, except in the case of death or legal disability, and such other individuals who are approved by DevelopmentCo and are reasonably qualified for the services to be performed;

(m) provide ongoing access to the management services of the Senior Management of Consultant; and

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(n) such other management and consulting services as the Company and/or DevelopmentCo may reasonably request in connection with the Entitlement and development of the Arroyo Grande Surface Estate.

SECTION 3.2. Nature of Services. The Consultant Services will be provided at the direction and control of the Company, and shall be directly supervised by the senior management of Consultant, including, without limitation, Lodwrick Cook. The Consultant Services will be provided directly or through third parties approved by the Company in its reasonable discretion. The Consultant Services shall be performed in a diligent and timely manner, and shall be of a type and at a service level substantially equivalent to services provided by other real estate and development companies in the marketplace in connection with real estate development and entitlement transactions of a similar size. Consultant shall use commercially reasonable efforts to ensure that each employee, officer, and consultant of Consultant who performs any Consultant Services shall be reasonably qualified to perform the Consultant Services that such individual is performing.

SECTION 3.3. Budgets; Expenses. The Company hereby agrees that it shall fund 100% of the costs and expenses of Entitlement that are specifically authorized in any entitlement budget that is prepared under the direction of the Consultant and approved by DevelopmentCo and the Company in its reasonable discretion (each an “Approved Entitlement Budget”). To the extent that the Company requests Consultant Services that include the services of the support staff of Consultant (including insurance, personnel, accountants, paralegals, attorneys and regulatory staff) such Approved Entitlement Budget will include reimbursement for any out-of-pocket expenses incurred in connection therewith. Budgets will be prepared on an annual basis and may include salaries and other general and administrative expenses anticipated for the next calendar year, estimated costs and expenses of the dedicated project manager. Except as otherwise agreed to herein or in writing, Consultant and the Company agree that the services of Lodwrick Cook and other senior managers of Consultant will be provided without compensation from PXP, the Company or DevelopmentCo. For purposes of clarification, the Company shall have no obligation to fund any Consultant, DevelopmentCo or third party expenses unless such amounts are budgeted and approved in advance by DevelopmentCo and the Company. Consultant shall provide the board of directors of DevelopmentCo and the Company with quarterly comparisons of budgeted to actual expenses. The Consultant or the Company may propose an amendment to any Approved Entitlement Budget at any time and from time to time as changing circumstances may dictate. Any such amendment must be approved by DevelopmentCo, the Consultant and the Company in their reasonable discretion. For purposes of this Agreement, all approvals. consents or authorizations of DevelopmentCo required or permitted by this Agreement shall require the approval of a majority of board of directors of DevelopmentCo.

SECTION 3.4. Management Power Reserved to the Company. This Agreement shall not constitute a delegation by the Company of authority with respect to the Entitlement and development of the Arroyo Grande Surface Estate or otherwise. Consultant specifically understands and agrees that this Agreement shall not be deemed to grant or imply that Consultant is authorized to sign, contract, deal or otherwise act in the name or on behalf of the Company except as may be expressly authorized for any specific purpose by the Company in writing hereafter in the Company’s reasonable discretion. Without limiting the foregoing and subject to

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the Company’s obligations set forth in Section 3.5, Consultant acknowledges that the Company shall have sole and absolute discretion to make all decisions with respect to the Arroyo Grande Surface Estate, including decisions with respect to: (i) the timing, type and amount of costs and expenses to be incurred on behalf of or invested in the Company or the Arroyo Grande Surface Estate, including costs of Entitlement, scope of development and whether to modify, continue with, or delay pursuit of development or Entitlements, and sources and uses of additional debt or equity financing, and (ii) timing, terms and conditions of any sale, transfer or other disposition of any right title or interest in the Arroyo Grande Surface Estate.

SECTION 3.5. Obligations of the Company. The Company agrees to use its reasonable efforts to work with the Consultant toward receipt of the Entitlements and the development and/or sale of the Arroyo Grande Surface Estate; provided, however, the parties hereto agree and acknowledge that PXP intends to maximize the value of the Mineral Rights and to develop such Mineral Rights and further agree that the development and/or sale of the Arroyo Grande Surface Estate shall be subject to the rights of PXP set forth in Section 8.14.

SECTION 3.6. (a) Limitation On Consultant’s Liability. The Company acknowledges that the Consultant is not acting as a general contractor, architect or real estate broker for the Company and shall not be required to perform, nor shall it perform, services for which a general contractor’s, architect or broker’s license is required. In addition, and except in the event of any gross negligence or willful misconduct by Consultant which directly and materially contributes to such defect or deficiency, the Company acknowledges and agrees that the Consultant shall have no liability to the Company whatsoever for (i) any defects or deficiencies in any plans, permits, entitlements, drawings, specifications, blueprints or other documents, items or work-product of any kind or nature prepared or generated by any third-party in connection with the development of the Arroyo Grande Surface Estate (it being agreed that the Company shall look solely to the preparer of such item or others for such defect, and not to the Consultant), or (ii) any defects or deficiencies in any materials, work, workmanship or improvements of any kind or nature constructed, made a part of, incorporated into, undertaken, utilized or otherwise involved with any Arroyo Grande Surface Estate, whether or not such work, materials, improvements or items were inspected by the Company (it being agreed that the Company shall look solely to the supplier or installer of such item, the party undertaking such work and/or others for such defect, and not to the Consultant). Further, the Consultant makes no assurance that it will be able to obtain the Entitlements and the Consultant shall have no liability whatsoever to the Company should the Consultant be unable to obtain any of the Entitlements.

(b) Limitation On the Company’s Liability. Consultant acknowledges that the Company is not acting as a general contractor, architect or real estate broker and shall not be required to perform, nor shall it perform, services for which a general contractor’s, architect or broker’s license is required. In addition, and except in the event of any gross negligence or willful misconduct by the Company which directly and materially contributes to such defect or deficiency, Consultant acknowledges and agrees that the Company shall have no liability to Consultant whatsoever for (i) any defects or deficiencies in any plans, permits, entitlements, drawings, specifications, blueprints or other documents, items or work-product of any kind or nature prepared or generated by any third-party in connection with the development of the Arroyo Grande Surface Estate (it being agreed that Consultant shall look solely to the preparer of such

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item or others for such defect, and not to the Company), or (ii) any defects or deficiencies in any materials, work, workmanship or improvements of any kind or nature constructed, made a part of, incorporated into, undertaken, utilized or otherwise involved with any Arroyo Grande Surface Estate, whether or not such work, materials, improvements or items were inspected by the Company (it being agreed that Consultant shall look solely to the supplier or installer of such item, the party undertaking such work and/or others for such defect, and not to the Company). Further, the Company makes no assurance that it will be able to obtain the Entitlements and the Company shall have no liability whatsoever to the Consultant should any of the Entitlements not be obtained and the subsequent sale of the Arroyo Grande Surface Estate not be completed, except as specifically provided herein.

SECTION 3.7. Cooperation. The Company and the Consultant shall reasonably cooperate with each other in order to accomplish the purposes stated herein. The Company further agrees that it shall execute and deliver all applications, maps, plans, drawings, contracts, and other documents and instruments reasonably necessary to the development process and the Entitlements, as reasonably requested by Consultant and approved by the Company.

ARTICLE IV

CONSIDERATION

SECTION 4.1. Consideration. Subject to the terms and conditions set forth herein, as consideration for the Consultant Services, from and after the Entitlement Date, the Company shall pay to Consultant an amount (the “Entitlement Fee”) equal to 15% of the Net Profits less $2.5 million; provided, however, that in the event that the Net Profits received exceed $112.5 million, the Entitlement Fee shall be equal to 20% of the Net Profits received less $3.75 million. In no event, however, shall the Entitlement Fee be less than $1.00. The Entitlement Fee (if any) shall be the sole and exclusive consideration and/or compensation of any kind to Consultant; provided, however, that the Company shall reimburse Consultant for costs and expenses incurred by Consultant that are included in an Approved Entitlement Budget. Notwithstanding anything to the contrary herein or elsewhere, subject to Section 4.2, no Entitlement Fee shall be due or payable to Consultant unless the closing of a sale of all or a portion of the Arroyo Grande Surface Estate generating Net Profits shall have actually taken place (whether or not any failure to enter into a sale transaction or any failure to actually close a sale transaction is due to any action or inaction by the Company or any other person or entity or for any other reason).

SECTION 4.2. Payments. To the extent the Company receives funds from the sale(s) of the Arroyo Grande Surface Estate, prior to making any payments the Company, DevelopmentCo and/or PXP shall reimburse itself for all Costs funded by the Company, DevelopmentCo and or PXP plus an amount equal to 20% of such Costs. Amounts payable by the Company to Consultant pursuant to Section 4.1 will be paid to Consultant periodically if and when Net Profits are received by the Company within 30 days after the Company receives any funds that constitute Net Profits, by wire transfer of immediately available funds, provided however that in the event of a sale of all or any portion of the Arroyo Grande Surface Estate prior to the Entitlement Date

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any amounts payable to Consultant pursuant to Section 4.1 and this Section 4.2 shall be retained by the Company in an escrow account until the Entitlement Date; provided, further, that the Company may, in its good faith reasonable discretion, withhold from any payments a portion of Net Profits representing a reserve against future commitments, expenses and contingent liabilities relating to the Entitlement or development of the Arroyo Grande Surface Estate as are set forth in any Approved Entitlement Budget; provided, however, when such reserves are no longer needed by the Company in its reasonable discretion, they shall be deemed cash proceeds for the purpose of calculating Net Profits.

SECTION 4.3. Adjustment. (a) Upon the actual date which the last portion of the proceeds from the sale of the Arroyo Grande Surface Estate is received by the Company, the Company shall calculate the Net Profits. In the event that the aggregate sum of all amounts paid by the Company to Consultant pursuant to Sections 4.1 and 4.2 of this Agreement (other than the reimbursement of Costs) exceed (i) in the event that Net Profits are less than or equal to $112.5 million, 15% of Net Profits as of such date less $2.5 million, or (ii) in the event that aggregate Net Profits exceed $225 million, 20% of Net Profits as of such date less $3.75 million, then Consultant shall pay to the Company an amount equal to such excess by wire transfer of immediately available funds to an account designated by the Company within 15 days of the Company’s notification of its determination of Net Profits; provided, however, that in no event shall amounts payable by Consultant pursuant to this Section 4.3 exceed the aggregate amount of payments previously paid to Consultant pursuant to this Agreement.

(b) In the event that the aggregate amount of Entitlement Fees paid to Consultant pursuant to Sections 4.1 and 4.2 hereof (other than the reimbursement of Costs) is less than (i) in the event that Net Profits are less than or equal to $112.5 million, 15% of Net Profits as of such date less $2.5 million, or (ii) in the event that aggregate Net Profits exceed $112.5 million, 20% of Net Profits less $3.75 million, then the Company shall pay to Consultant an amount equal to such deficiency by wire transfer of immediately available funds to an account designated by Consultant within 15 days of the Company’s determination of Net Profits.

ARTICLE V

TERMINATION

SECTION 5.1. Termination by the Company. At any time prior to the Entitlement Date, the Company shall have the right to terminate this Agreement upon written notice to Consultant. In the event that the Company terminates this Agreement for Cause (as defined in Section 5.2) all of the Company’s obligations under this Agreement shall terminate effective as of the date of such notice, including the Company’s obligation to make any payments to Consultant pursuant to Sections 4.1 and 4.2. In the event that the Company terminates this Agreement other than termination for Cause, the Company’s obligations pursuant to Sections 4.1 and 4.2 shall survive such termination.

SECTION 5.2. Definition of Cause. As used in this Agreement “Cause” shall mean:

(a) Any failure, refusal or neglect by Consultant at any time to perform fully any of Consultant’s material obligations hereunder, if such failure is not cured and continues for thirty (30) calendar days subsequent to Consultant’s receipt of written notice thereof from the Company;

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(b) Willful misconduct or gross negligence of any employees or management of Consultant that is not cured and continues for twenty (20) days after Consultant receives written notice from the Company that identifies the misconduct, negligence or actions taken in bad faith in connection with Consultant’s responsibilities under this Agreement;

(c) If at any time Lodwrick Cook (other than in the case of the death or legal disability) shall (i) cease to materially participate in the provision of the Consultant Services or (ii) cease to make himself generally available to management of the Company at reasonable times upon the Company’s reasonable notice; or

(d) Failure to achieve Entitlement prior to January 1, 2013, provided, however, that such deadline shall be extended by the number of days (if any) that Entitlement was actually delayed as a direct or indirect result of any failure of the Company to fund any costs or expenses necessary to obtain the Entitlements that were included in a budget approved by the Company.

SECTION 5.3. Termination by Consultant. In the event that (i) Entitlement has been achieved, (ii) the Company has received a bona fide offer from a third party ready, willing and able to purchase, fund and close on all or a portion of the Arroyo Grande Surface Estate within 90 days at a price that exceeds the then-current value of the Mineral Rights as determined by PXP’s independent reserve engineers in accordance with Securities and Exchange Commission regulations, and (iii) the Company rejects such offer, then Consultant may terminate this Agreement and shall be entitled to receive 50% of the Entitlement Fee calculated as if such sale had occurred and any then incurred but unpaid reimbursable costs. In such event, upon any sale of the Arroyo Grande Surface Estate the Company shall pay to Consultant the Entitlement Fee less the portion paid pursuant to the previous sentence.

ARTICLE VI

REPRESENTATIONS AND WARRANTIES

OF THE COMPANY

The Company hereby represents and warrants to Consultant (except as otherwise disclosed in writing on the date hereof and prior to the execution and delivery hereof) as follows:

SECTION 6.1. Organization; Authority. The Company is a limited liability company duly organized, validly existing and in good standing under the laws of the State of Delaware. The Company has the requisite power and authority necessary to execute and deliver this Agreement and to perform and consummate the transactions contemplated hereunder. The execution, delivery and performance by the Company of this Agreement and the consummation of the transactions contemplated hereby have been duly authorized by the Company and no other action on the part of the Company is necessary to authorize the execution, delivery and performance by the Company of this Agreement or the consummation of such transactions. This Agreement has been has been duly authorized, executed and delivered by, and assuming due authorization by Consultant, is enforceable against the Company, subject to bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium and similar laws of general applicability relating to or affecting creditor rights and for general equitable principles.

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SECTION 6.2. No Conflict; Required Filings and Consents. The execution and delivery of this Agreement by the Company does not, and the performance by the Company of its obligations hereunder and the consummation of the transactions contemplated hereby will not, (i) conflict with or violate the Company’s charter documents, (ii) conflict with or violate any Law applicable to the Company or by which any property or asset of the Company is bound or (iii) violate any note, bond, mortgage, indenture, contract, agreement, lease, license, permit or other instrument or obligation to which the Company is a party or by which the Company or its properties may be bound, except in the case of (ii) and (iii) for any conflict or violation that does not materially adversely affect the performance of the Company’s obligations hereunder or the consummation of the transactions contemplated hereby.

SECTION 6.3. Condition of the Arroyo Grande Surface Estate.

(a) Neither Company nor PXP has received any notice of, or has knowledge of, any pending or threatened taking or condemnation of the Arroyo Grande Surface Estate or any portion thereof.

(b) The Arroyo Grande Surface Estate is free of any right of possession or claim of right of possession of any party other than the Company, and there are no leases or occupancy agreements currently affecting any portion of the Arroyo Grande Surface Estate, except for easements and for any such rights, claims, leases or agreements relating to the Mineral Rights.

(c) Neither the Company nor PXP has received a notice of, or has knowledge of, any material violations of law, municipal or county ordinances, or other legal requirements with respect to the Arroyo Grande Surface Estate or with respect to the use, occupancy or construction thereon.

(d) There are no purchase contracts or option agreements affecting the Arroyo Grande Surface Estate.

(e) PXP will transfer to the Company fee title to the Arroyo Grande Surface Estate as soon as practicable after the date hereof, but in any event no later than the Entitlement Date.

(f) Neither the Company nor PXP is a party to any litigation, arbitration, or administrative proceeding affecting the Arroyo Grande Surface Estate or the Company’s ability to perform its obligations hereunder and to the knowledge of Company, no such litigation, arbitration or administrative proceeding is threatened.

(g) The Company has provided Consultant with the Phase I environmental report prepared on the Arroyo Grande Surface Estate and other than related to PXP’s oil and gas operations, to the Company’s knowledge there are no Hazardous Materials situated on, under or about the Arroyo Grande Surface Estate in violation of applicable law.

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ARTICLE VII

REPRESENTATIONS AND WARRANTIES

OF CONSULTANT

Consultant hereby represents and warrants to the Company (except as otherwise disclosed in writing on the date hereof and prior to the execution and delivery hereof) as follows:

SECTION 7.1. Organization; Authority. Consultant is a limited liability company duly organized, validly existing and in good standing under the laws of the State of California. Consultant has the requisite power and authority necessary to execute and deliver this Agreement and to perform and consummate the transactions contemplated hereunder. The execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby by Consultant have been duly authorized by Consultant, and no other action on the part of Consultant is necessary to authorize the execution, delivery and performance of this Agreement or the consummation of such transactions by Consultant. This Agreement has been duly authorized, executed and delivered by, and assuming due authorization by the Company, is enforceable against Consultant, subject to bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium and similar laws of general applicability relating to or affecting creditor rights, and for general equitable principles whether applied in a proceeding at law or in equity.

SECTION 7.2. No Conflict; Required Filings and Consents. The execution and delivery of this Agreement by Consultant does not, and the performance by Consultant of its obligations hereunder and the consummation of the transactions contemplated hereby will not, (i) conflict with or violate the organizational or governing documents of Consultant, (ii) conflict with or violate any Law applicable to Consultant or by which any property or asset of Consultant is bound or (iii) result in any violation pursuant to, any note, bond, mortgage, indenture, contract, agreement, lease, license, permit, franchise or other instrument or obligation to which Consultant is a party or by which Consultant or any of its properties may be bound, except in the case of (ii) and (iii) for any conflict or violation that does not materially adversely affect the performance of Consultant’s obligations hereunder or the consummation of the transactions contemplated hereby.

SECTION 7.3. Arroyo Grande Surface Estate. Consultant agrees that (i) it has had the opportunity to perform any inspections, tests and/or studies that it desired or deemed necessary or appropriate in order to determine the suitability of the Arroyo Grande Surface Estate for the Company’s intended use thereof, and (ii) it has had the opportunity to review all instruments, records, documents, and studies concerning the Arroyo Grande Surface Estate (including zoning, ordinances and regulations and any other laws, ordinances or governmental regulations restricting or regulating the use, occupancy or enjoyment of the Arroyo Grande Surface Estate) which it deemed appropriate or advisable to review. Consultant also acknowledges that it has relied and will be relying on the advice of its own consultants and advisors that in its sole discretion it has deemed appropriate concerning its execution of this Agreement, the development of the Arroyo Grande Surface Estate and the viability and suitability of the Arroyo Grande Surface Estate for the Company’s intended uses.

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SECTION 7.4. Other Agreements. All arrangements and agreements between Consultant and and any non-affiliated third party relating to the Arroyo Grande Surface Estate and/or any amounts which may become payable pursuant to this Agreement have been disclosed to the Company and are set forth on Schedule 7.4 hereto, and Consultant hereby agrees to disclose to the Company any such arrangements or agreements upon entering into such arrangements or agreements.

SECTION 7.5. “AS-IS” CONSULTANT ACKNOWLEDGES AND AGREES THAT, NONE OF PXP, DEVELOPMENTCO OR THE COMPANY HAS MADE, DOES MAKE OR WILL MAKE (AND EACH OF PXP, DEVELOPMENTCO AND THE COMPANY HEREBY SPECIFICALLY NEGATES AND DISCLAIMS) ANY REPRESENTATIONS, WARRANTIES, OR GUARANTIES OF ANY KIND OR CHARACTER WHATSOEVER, WHETHER EXPRESS OR IMPLIED, ORAL OR WRITTEN, PAST, PRESENT OR FUTURE, OF, AS TO, CONCERNING OR WITH RESPECT TO ANY MATTER (EXCEPT FOR EXPRESS REPRESENTATIONS AND WARRANTIES IN THIS AGREEMENT), INCLUDING, WITHOUT LIMITATION, WITH RESPECT TO ANY OF THE FOLLOWING MATTERS CONCERNING THE ARROYO GRANDE SURFACE ESTATE: (I) VALUE OR ANY ANTICIPATED SALE PRICES OF LOTS OR OTHER PORTIONS THEREOF; (II) REVENUE TO BE DERIVED; (III) SUITABILITY FOR ANY AND ALL ACTIVITIES AND USES, INCLUDING THE POSSIBILITIES FOR FUTURE DEVELOPMENT; (IV) HABITABILITY, MERCHANTABILITY, MARKETABILITY, PROFITABILITY OR FITNESS FOR A PARTICULAR PURPOSE; (V) NATURE, QUALITY OR CONDITION, INCLUDING WATER, SOIL AND GEOLOGY; (VI) COMPLIANCE WITH ANY LAWS, RULES, ORDINANCES OR REGULATIONS; (VII) MANNER OR QUALITY OF THE CONSTRUCTION OR MATERIALS, IF ANY; (VIII) COMPLIANCE WITH ANY ENVIRONMENTAL PROTECTION, POLLUTION, ENDANGERED SPECIES OR LAND USE LAWS, RULES, REGULATIONS, ORDERS OR REQUIREMENTS, INCLUDING BUT NOT LIMITED TO, THE AMERICANS WITH DISABILITIES ACT OF 1990, HEALTH & SAFETY CODE, WATER POLLUTION CONTROL ACT, RESOURCE CONSERVATION AND RECOVERY ACT, ENVIRONMENTAL PROTECTION AGENCY REGULATIONS, THE COMPREHENSIVE ENVIRONMENTAL RESPONSE, COMPENSATION AND LIABILITY ACT OF 1980, AS AMENDED, THE RESOURCE CONSERVATION AND RECOVERY ACT OF 1976, THE CLEAN WATER ACT, THE SAFE DRINKING WATER ACT, THE HAZARDOUS MATERIALS TRANSPORTATION ACT, THE TOXIC SUBSTANCE CONTROL ACT; (IX) PRESENCE OR ABSENCE OF HAZARDOUS MATERIALS AT, ON, UNDER, OR ADJACENT TO THE ARROYO GRANDE SURFACE ESTATE, (X) CONTENT, COMPLETENESS OR ACCURACY OF ANY DOCUMENTS PROVIDED TO CONSULTANT BY PXP, DEVELOPMENTCO OR THE COMPANY OR OTHERS OR ANY TITLE REPORT, TITLE COMMITMENT OR SURVEY; (XI) CONFORMITY OF ANY IMPROVEMENTS TO ANY PLANS OR SPECIFICATIONS; (XII) CONFORMITY TO PAST, CURRENT OR FUTURE APPLICABLE ZONING OR BUILDING REQUIREMENTS; (XIII) DEFICIENCY OF ANY UNDERSHORING; (XIV) DEFICIENCY OF ANY DRAINAGE; (XV) POSSIBLE LOCATION IN, ON OR NEAR AN EARTHQUAKE

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FAULT LINE, LIQUEFACTION AREA, FLOOD AREA, FIRE HAZARD OR OTHER HAZARDOUS AREA; OR (XVI) EXISTENCE OF LAND USE, ZONING OR BUILDING ENTITLEMENTS OR (XVII) ANY MATTER RELATING TO THE SUBSURFACE RIGHTS, OIL OPERATIONS OR OTHER RIGHTS RETAINED BY PXP. CONSULTANT FURTHER ACKNOWLEDGES AND AGREES THAT TO THE MAXIMUM EXTENT PERMITTED BY LAW (EXCEPT FOR EXPRESS REPRESENTATIONS AND WARRANTIES SET FORTH IN THIS AGREEMENT), THE CONDITION OF THE ARROYO GRANDE SURFACE ESTATE AND ANY OTHER RELATED MATTERS HAS BEEN MADE IN/ON AN “AS IS” CONDITION AND BASIS WITH ALL FAULTS, AND THAT NONE OF PXP, DEVELOPMENTCO OR THE COMPANY HAS ANY OBLIGATIONS TO MAKE REPAIRS, REPLACEMENTS OR IMPROVEMENTS.

ARTICLE VIII

MISCELLANEOUS

SECTION 8.1. Entire Agreement. This Agreement, together with the exhibits and schedules hereto and the certificates, documents, instruments and writings that are delivered pursuant hereto constitutes the entire agreement and understanding of the parties in respect of its subject matter and supersedes all prior understandings, agreements, or representations by or among the parties, written or oral, to the extent they relate in any way to the subject matter hereof. There are no third party beneficiaries having rights under or with respect to this Agreement except that PXP and DevelopmentCo, and Lodwrick Cook with respect to the consulting fee to be paid to him pursuant to (ix) of the definition of “Costs” herein, are express intended third party beneficiaries of this Agreement and shall be entitled to the benefits of and to enforce the terms of this Agreement.

SECTION 8.2. Successors; Etc. All of the terms, agreements, covenants, representations, warranties, and conditions of this Agreement are binding upon, and inure to the benefit of and are enforceable by, the parties and their respective successors. Consultant shall not, and hereby expressly waives any right to, assign, directly or indirectly, any of its rights under this Agreement or to file or record this Agreement or any notice hereof or any notice of any action hereon in any public records or give any notice to or make any claim or demand with respect to this Agreement to, in or against any third party or any escrow.

SECTION 8.3. Notices. All notices, requests, demands, claims and other communications hereunder will be in writing. Any notice, request, demand, claim or other communication hereunder will be deemed duly given if (and then three (3) business days after) it is sent by registered or certified mail, return receipt requested, postage prepaid, and addressed to the intended recipient as set forth the signature pages hereto. Any party may send any notice, request, demand, claim, or other communication hereunder to the intended recipient at the address set forth above using any other means (including personal delivery, expedited courier, messenger service, telecopy, telex, ordinary mail, or electronic mail), but no such notice, request, demand, claim, or other communication will be deemed to have been duly given unless and until it actually is received by the intended recipient. Any party may change the address to which notices, requests, demands, claims, and other communications hereunder are to be delivered by giving the other parties notice in the manner herein set forth, or may require the delivery of up to one additional copy.

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SECTION 8.4. Specific Performance. Each party acknowledges and agrees that the other party would be irreparably damaged if any provision of this Agreement is not performed in accordance with its specific terms or is otherwise breached. Accordingly, each party agrees that the other parties will be entitled to an injunction or injunctions to prevent breaches of the provisions of this Agreement and to specifically enforce this Agreement and its terms and provisions in any action instituted in any court of the United States or any state thereof having jurisdiction over the parties in the matter, subject to this Section 8.4 and Section 8.7, in addition to any other remedy to which such party may be entitled, at law or equity. .

SECTION 8.5. Counterparts. This Agreement may be executed in two or more counterparts, each of which will be deemed an original but all of which together will constitute one and the same instrument.

SECTION 8.6. Headings. The section headings contained in this Agreement are inserted for convenience only and will not affect in any way the meaning or interpretation of this Agreement.

SECTION 8.7. Governing Law and Dispute Resolution.

(a) This Agreement and the performance of the transactions contemplated hereby and the obligations of the parties hereunder will be governed by and construed in accordance with the laws of the State of California, without giving effect to any choice of law principles.

(b) The parties agree that any and all disputes, claims or controversies arising out of or relating to this Agreement shall be first submitted to JAMS or its successor, for mediation, and if the matter is not resolved through mediation, then it shall be submitted to JAMS, or its successor, for final and binding arbitration pursuant to the arbitration clause set forth below. Either party may commence mediation by providing to JAMS and the other party a written request for mediation, setting forth the subject of the dispute and the relief requested. The parties will cooperate with JAMS and with one another in selecting a mediator from JAMS panel of neutrals, and in scheduling the mediation proceedings. The parties covenant that they will participate in the mediation in good faith, and that they will share equally in its costs. All offers, promises, conduct and statements, whether oral or written, made in the course of the mediation by any of the parties, their agents, employees, experts and attorneys, and by the mediator or any JAMS employees, are confidential, privileged and inadmissible for any purpose, including impeachment, in any arbitration or other proceeding involving the parties, provided that evidence that is otherwise admissible or discoverable shall not be rendered inadmissible or non-discoverable as a result of its use in the mediation. Either party may initiate arbitration with respect to the matters submitted to mediation by filing a written demand for arbitration at any time following the initial mediation session or 45 days after the date of filing the written request for mediation, whichever occurs first. The mediation may continue after the commencement of arbitration if the parties so desire. Unless otherwise agreed by the parties, the mediator shall be disqualified from serving as arbitrator in the case.

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The provisions of this clause (b) may be enforced by any Court of competent jurisdiction, and the party seeking enforcement shall be entitled to an award of all costs, fees and expenses, including attorneys’ fees, to be paid by the party against whom enforcement is ordered.

(c) Any dispute, claim or controversy arising out of or relating to this Agreement or the breach, termination, enforcement, interpretation or validity thereof, including the determination of the scope or applicability of this agreement to arbitrate, which has failed to be resolved during the mediation process above shall be determined by arbitration before a panel of three (3) arbitrators. The arbitration shall be administered by JAMS pursuant to its Comprehensive Arbitration Rules and Procedures (Streamlined Arbitration Rules and Procedures). Unless the parties agree otherwise, the place of arbitration shall be Los Angeles, California. The arbitrators shall not be empowered to award any form of exemplary or punitive damages. As part of any arbitral award pursuant to this paragraph, the arbitrators shall render a reasoned award. The parties consent to judgment on such award being entered in any court having jurisdiction.

(d) Each party is required to continue to perform its obligations under this Agreement pending final resolution of any dispute.

(e) Should any party hereto institute any arbitration proceedings permitted under this Section 8.7, the prevailing party (as determined by the arbitral panel) shall be entitled to recover costs of the arbitration proceeding and reasonable attorneys’ fees to be fixed by the arbitral panel.

(f) Any judicial proceedings permitted to be brought with respect to this Agreement shall be brought in any state or federal court of competent jurisdiction in the State of California, and the parties generally and unconditionally accept the exclusive jurisdiction of such courts. The parties waive, to the fullest extent permitted by applicable Law, any objection which they may now or hereafter have to the bringing of any such action or proceeding in such jurisdiction.

SECTION 8.8. Amendments and Waivers. No amendment, modification, replacement, termination or cancellation of any provision of this Agreement will be valid, unless the same will be in writing and signed by each party hereto. Neither any failure nor any delay by any party in exercising any right, power or privilege under this Agreement will operate as a waiver of such right, power or privilege, and no single or partial exercise of any such right, power or privilege will preclude any other or further exercise of such right, power or privilege or the exercise of any other right, power or privilege. To the maximum extent permitted by applicable law, (a) no claim or right arising out of this Agreement can be discharged by one party, in whole or in part, by a waiver or renunciation of the claim or right unless in writing signed by the other party; (b) no waiver that may be given by a party will be applicable except in the specific instance for which it is given; and (c) no notice to or demand on one party will be deemed to be a waiver of any obligation of that party or of the right of the party giving such notice or demand to take further action without notice or demand as provided in this Agreement.

SECTION 8.9. Severability. The provisions of this Agreement are severable, and the invalidity of any provision shall not affect the validity of any other provision.

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SECTION 8.10. Expenses. Except as otherwise expressly provided in this Agreement, each party will bear its own costs and expenses incurred in connection with the negotiation and preparation of this Agreement.

SECTION 8.11. Construction. This Agreement will be deemed to have been drafted by both parties thereto and will not be construed against either party as the draftsperson hereof. “Including” or “include” or “includes” or “including without limitation” means “including without limitation”.

SECTION 8.12. Incorporation of Exhibits, Annexes and Schedules. The exhibits, annexes, schedules, and other attachments identified in this Agreement are incorporated herein by reference and made a part hereof.

SECTION 8.13. Remedies. Except as expressly provided herein, the rights, obligations and remedies created by this Agreement are cumulative and in addition to any other rights, obligations, or remedies otherwise available at law or in equity. Except as expressly provided herein, nothing herein will be considered an election of remedies.

SECTION 8.14. Other Business Interests/No Fiduciary Duty. The parties and their respective members and affiliates may engage, directly or indirectly, without consent of the other parties, in other business opportunities or arrangements, independently or with others, including those competitive with the Company, regardless of geographic location, and without any duty or obligation to offer or account to the other parties. Without limitation, PXP owns the Mineral Rights which now and may hereafter burden the Arroyo Grande Surface Estate and Consultant acknowledges its understanding that PXP shall be free to exploit the same in any manner even if it would be harmful to the Company’s interests in the Arroyo Grande Surface Estate or hinder, delay or prevent the Entitlement or development thereof and/or Consultant’s ability to earn any (or the amount, if any) Entitlement Fee. Consultant acknowledges its understanding that PXP will have conflicts of interests arising from its other business interests, including the Mineral Rights. Further, PXP and the Company are free to act in their own best interests and in accordance with their respective sole and absolute discretion as to all aspects of the Arroyo Grande Surface Estate, including the Entitlement, development, budgeting, scheduling, financing and/or sale thereof, notwithstanding any adverse impact on Net Profits. Without limiting the foregoing or any other provision of this Agreement, Consultant specifically acknowledges its understanding that the Company and PXP may elect to delay providing funding for the Entitlement and development process at any time and/or elect to delay the development of the Arroyo Grande Surface Estate for residential purposes despite whether any such delay or abandonment could impact the timing and amount of Entitlement Fees (if any) payable hereunder. Further, nothing herein is intended to create a partnership, joint venture, agency, or other relationship creating fiduciary or quasi-fiduciary duties and obligations or to impose any duty, obligation, or liability that would arise therefrom with respect to any or all of the parties or their Affiliates or any permitted assigns. Neither party shall be deemed to be a fiduciary to the other party. To the full extent permitted by law, the parties waive any such fiduciary obligations as might have otherwise applied.

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[Signature page follows]

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IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their respective officers thereunto duly authorized, all as of the date first written above.

COOK HILL PROPERTIES LLC
By:	/s/ Lodwrick M. Cook
Name:	Lodwrick M. Cook
Title:	Managing Member
Copy of any notices, requests, demands, claims and other communications to be sent to:
9355 Wilshire Boulevard, 4th Floor
Beverly Hills, CA 90210
Attn: Gerry Ginsberg
ARROYO GRANDE LAND COMPANY LLC
By its Sole Member:
Plains Exploration and Production Company
By:	/s/ John F. Wombwell
Name:	John F. Wombwell
Title:	Executive Vice President, General Counsel and Secretary
Copy of any notices, requests, demands, claims and other communications to be sent to:
Plains Exploration & Production Company
700 Milam, Suite 3100
Houston, TX 77002
Attn: John F. Wombwell

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EXHIBIT A

LEGAL DESCRIPTION OF REAL PROPERTY

WHICH INCLUDES ARROYO GRANDE SURFACE ESTATE

PARCEL 1

All those portions of Lots 55 and 56 of Stratton’s Subdivision of the Ranchos Corral de Piedra, Pismo and Bolsa de Chemisal, in the County of San Luis Obispo, State of California, according to map recorded in Book A, Page 65 of Maps, described as follows:

Commencing at an oak S.401, 10 inches in diameter, the common corner of Lots 55, 56, 57 and 58 of Jas. T. Stratton’s Subdivision of said Ranchos; Thence North 63 ³/4° East 27.40 chains to post in pile of stone on the summit of a sharp chemisal ridge, being the same as called for in a deed from W.W. Stow, et al., to L. Maxwell, dated March 29, 1882 and recorded in Book O, Page 139, et seq., of Deeds, records of said county; thence following the line of a sharp ridge on the following courses and distances, to wit:

South 44 ¹/2° East 4.14 chains to a stake “A. No. 1” from which a scrub oak 3 inches in diameter bears North 27° East 45 links distant; thence South 60° East 6.92 chains to stake “A. No. 2”; thence South 70 ¹/2° East 7.20 chains to a stake “A. No. 3”; thence South 60 ¹/4° East 14.38 chains to a stake “A. No. 4” from which a scrub oak 4 inches in diameter bears South 36° West 7 links distant; thence South 42° East 6.70 chains to a stake “B.O.”; Thence North 74 ¹/4° East 9.87 chains to a stake in a stone mound on the end of a ridge; thence descending ridge and leaving ridge North 63 ¹/2° East 3.09 chains to a post “A. No. 5” in the line of a fence on the Westerly side of the county road from the City of San Luis Obispo to the Pismo Landing; thence along said line of fence on Westerly line of said above mentioned county road on the following courses and distances, to wit:

South 3° East 4.16 chains; thence South 6° West 11.14 chains to a point in a fence “A. No. 7” on the line between Lots 56 and 60 of Jas. T. Stratton’s Subdivision above mentioned; thence following said line between said Lots 56 and 60 as above South 89° 21’ West 72.03 chains to the Southwesterly corner of said Lot 56 from which a live oak 14 inches in diameter marked “J.B.T.” bears North 86 ¹/4° East 19 links distant; thence along Westerly boundary of said Lot 56 North 4° East 20 chains to Oak S.401, the point of beginning.

Excepting therefrom that portion conveyed to the County of San Luis Obispo for roadway purposes per deed recorded November 15, 1962 in Book 1211 of Official Records at Page 363.

Also excepting that which was conveyed by Mineral Deed recorded November 6, 1995 as Instrument No. 1995-051711 of Official Records.

(A.P.N.: 044-141-001)

A-1

PARCEL 2

All that part of Lot 56 of Stratton’s Subdivision of the Ranchos Corral de Piedra, Pismo and Bolsa de Chemisal, in the County of San Luis Obispo, State of California, according to the map recorded in Book A, Page 65 of Maps, described as bounded on the North and East by lands now or formerly owned by J.C. Coleman and Edward Coleman, as described in deed recorded in Book 45, Page 203 of Deeds, records of said county; on the West by the Easterly line of the Pacific Coast Railroad, and on the South by the Northerly line of Lot 60 of said Rancho. Excepting therefrom that portion conveyed to the County of San Luis Obispo for roadway purposes.

Also excepting that which was conveyed by Mineral Deed recorded November 6, 1995 as Instrument No. 1995-051711 of Official Records.

(A.P.N.: 044-151-013)

A-2

PARCEL 3

A Portion of Lot 60 of Stratton’s Subdivision of the Rancho Corral de Piedra, Pismo and Bolsa de Chemisal, in the County of San Luis Obispo, State of California, according to map recorded in Book A, Page 65 of Maps in deed from H. Loobliner to L. Maxwell in deed recorded April 14, 1882 in Book of Deeds at Page 134 more particularly described as follows:

Commencing at an Oak tree marked “S.402” being the Southwest corner of Lot No. 60 as per said map; thence

North 48 East, along the west line of Lot 60 29.25 chains to a stake; thence

North 88 ³/4 8 East along the north line of said Lot 60 18 chains to a stake; thence

South 48 West 33 chains to a stake on the south boundary of said lot No. 60, thence

North 79 ¹/2 8 West along the north line of Lot 60 18 chains to the place of beginning.

Also excepting that which was conveyed by Mineral Deed recorded November 6, 1995 as Instrument No. 1995-051711 of Official Records.

Containing 55 acres more or less.

(portion of A.P.N.: 044-191-004)

A-3

PARCEL 4

A portion of Lot 60 of Stratton’s Subdivision of the Rancho Corral de Piedra, Pismo and Bolsa de Chemisal, in the County of San Luis Obispo, State of California, according to map recorded in Book A, Page 65 of Maps and in a deed from F. Adams et. al. to S.L.O. Bituminous Rock Company in deed recorded July 5, 1887 in Book X of Deeds at Page 236 and more particularly described as follows:

Commencing at a stake on the line between lots Number 60 and 62 of said map, said stake being distant South 89  ¹/2 8 E 18 chains from an oak tree 18 inches in diameter “S.402” the corner to lots no. 58, 59, 60 and 62 of said map, said stake being the southeast corner of the tract of land conveyed to L. Maxwell Lobliner by deed dated April 13^th 1882 and recorded in Book O of deeds at page 124 et.seq. at the County Recorder’s office of San Luis Obispo County, California; thence along the easterly boundary of the last mentioned tract North 48 East to a stake on the line between lots 56 and 60 of the abovementioned subdivision; thence following the line of fence between said lots 56 and 60 North 89 8 21’ East 54.03 chains to a post marked “A No. 7” in line of fence on westerly line of County road from the City of San Luis Obispo to the Pismo Landing; thence along the line of fence on westerly line of said road on the following courses and distances: South 5 ¹/4 8 West 5.34 chains; thence South 1/2 8 West 3.91 chains; thence South 48 East 14.33 chains; thence South 12 ³/4 8 East 13.67 chains; thence South 218 East 2.55 chains; thence South 268 East 3.37 chains; thence South 19 ¹/2 8 West 3.32 chains; thence South 16 ¹/4 8 West 3.12 chains; thence South 3/4 8 West 2.58 chains; thence South 98 West 1.74 chains to post “A No. 6 in fence line on Northeast line of tract of land conveyed to F.W. Newval by J. B. Townsend September 18^th 1874 and recorded in Book “F” of deeds , at page 359 et. seq. in said County Recorder’s office, thence following said Northeast line of said Newval tract North 608 West 28.62 chains to post F.N. No. 3 from which a live oak tree 10 inches in diameter bears North 1.13 chains distant; thence South 6 ¹/4 West 10 chains to post FN No. 2 in stone mound on the line between Lots 60 and 62 of the abovementioned subdivision; thence along said line between Lots 60 and 62 North 79 ¹/2 8 West 33.69 chains to a stake and the point of beginning.

Containing 204.59 acres

Excepting therefrom those portions conveyed to the County of San Luis Obispo for roadway purposes per deed recorded November 15, 1962 in Book 1211 of Official Records at page 363.

Also excepting therefrom those portions lying within the right of way of the Pacific Coast Railroad according to deed recorded July 16, 1884 in Book N of deeds at Page 166 and the Southern Pacific Railroad according to deed recorded September 17, 1891 in Book 13 of deeds at page 348.

Also excepting that which was conveyed by Mineral Deed recorded November 6, 1995 as Instrument No. 1995-051711 of Official Records.

(Portion A.P.N.: 044-191-004)

A-4

PARCEL 5

A portion of Lot 60 of Stratton’s Subdivision of the Rancho Corral de Piedra, Pismo and Bolsa de Chemisal, in the County of San Luis Obispo, State of California, according to map recorded in Book A, Page 65 of Maps described as follows:

That portion of Lot 60 which lies easterly of the westerly line of the old County Road No. 254 which leads from the Town of Maxwellton to the Pismo Landing.

Containing 129.21 Acres

Excepting therefrom those portions conveyed to the County of San Luis Obispo for roadway purposes per deed recorded November 15, 1962 in Book 1211 of Official Records at page 363.

Also excepting therefrom those portions lying within the right of way of the Pacific Coast Railroad according to deed recorded July 16, 1884 in Book N of deeds at Page 166 and the Southern Pacific Railroad according to deed recorded September 17, 1891 in Book 13 of deeds at page 348.

Excepting therefrom that portion conveyed to the State of California per deed recorded September 28, 1989 in Book 3389 of Official Records at page 895.

Also excepting that which was conveyed by Mineral Deed recorded November 6, 1995 as Instrument No. 1995-051711 of Official Records.

(Portion A.P.N.: 044-191-005)

A-5

PARCEL 6

That portion of Lot 60 of Stratton’s Subdivision of the Rancho Corral de Piedra, Pismo and Bolsa de Chemisal, in the County of San Luis Obispo, State of California, according to map recorded in Book A, Page 65 of Maps described as follows:

Commencing at Stake No. 192 set at the northeast corner of Lot 62 of the Rancho Corral de Piedra , Pismo and Bolsa de Chemisal from which an oak tree bears South 128 West 120 links, thence North 798 30’ West on line between Lots 60 and Lot 62 a distance of 9 chains; thence North 88 15’ East 10 chains to Post “F.N. No. 3” from which an oak tree bears North 113 links; thence South 608 East 30 chains 25 links to the center of Corral de Piedra Creek from which a witness post and stone mound F.N.N. No. 4 bears North 608 West 110 links distant; thence westerly following the creek to a point on the centerline of same from which a stake No. 192 bears North 108 East 5 chains distant thence North 108 East 5 chains to Stake No. 192 and the point of beginning.

Containing 21.5 acres.

Excepting therefrom those portions conveyed to the County of San Luis Obispo for roadway purposes per deed recorded November 15, 1962 in Book 1211 of Official Records at page 363.

Also excepting therefrom those portions lying within the right of way of the Southern Pacific Railroad according to deed recorded September 17, 1891 in Book 13 of deeds at page 348.

Also excepting that which was conveyed by Mineral Deed recorded November 6, 1995 as Instrument No. 1995-051711 of Official Records.

(Portion A.P.N.: 044-191-004)

A-6

PARCEL 7

Lots 62 of Stratton’s Subdivision of the Rancho Corral de Piedra, Pismo and Bolsa de Chemisal, in the County of San Luis Obispo, State of California, according to map recorded in Book A, Page 65 of Maps.

Excepting therefrom those portions conveyed to the County of San Luis Obispo for roadway purposes per deed recorded November 15, 1962 in Book 1211 of Official Records at page 363.

Also excepting that which was conveyed by Mineral Deed recorded November 6, 1995 as Instrument No. 1995-051711 of Official Records.

(A.P.N.: 044-201-002)

A-7

PARCEL 8

Lot 60 of Oak Park, in the County of San Luis Obispo, State of California, according to map recorded November 3, 1893 in Book A, Page 152 of Maps.

Except therefrom that portion of said land described in Book 16 of Deeds at Page 55, as follows:

Beginning at a point on the Northeasterly boundary line of said Oak Park, which point is the common corner of Lots 59 and 60 of said Oak Park; thence North 72° West along the North line of said Lot 60, 22.48 chains to a white oak tree; thence South 64 ¹/4° East, 21.03 chains to stake P.C. 376 on the Easterly line of said Lot 60; thence North 48° East along the line between said Lots 59 and 60, 3.28 chains to the Point of Beginning.

Also except therefrom that portion conveyed to the Southern Pacific Railroad Company, a corporation, being a strip of land 100 feet in width through said Lot 60, by deed recorded September 20, 1894 in Book 24, Page 490 of Deeds.

Excepting therefrom that portion conveyed to the County of San Luis Obispo for roadway purposes.

Also excepting that which was conveyed by Mineral Deed recorded November 6, 1995 as Instrument No. 1995-051711 of Official Records.

(A.P.N.: 044-241-001)

A-8

PARCEL 9

Lot 59 of Oak Park Tract, in the County of San Luis Obispo, State of California, according to map recorded in Book A, Page 152 of Maps.

Except therefrom that portion thereof described in the deed to C.C. Morehouse, recorded June 17, 1925 in Book 3, Page 348 of Official Records.

Also except therefrom that portion thereof described in the deed to the County of San Luis Obispo, recorded November 23, 1931 in Book 119, Page 24 of Official Records.

Also excepting therefrom that portion of Lot 59 of Oak Park Tract as shown on map recorded in Book A, Page 152 of Maps, lying Southwesterly of the Southwest line of County Road 44 (otherwise known as Ormonde-Oak Park Road).

Also excepting that which was conveyed by Mineral Deed recorded November 6, 1995 as Instrument No. 1995-051711 of Official Records.

(A.P.N.: 044-241-031)

A-9

PARCEL 10

Lot 62 of Oak Park Tract, in the County of San Luis Obispo, State of California, according to map recorded in Book A, Page 152 of Maps.

Excepting therefrom that portion conveyed to the County of San Luis Obispo for roadway purposes.

Also excepting that which was conveyed by Mineral Deed recorded November 6, 1995 as Instrument No. 1995-051711 of Official Records.

(A.P.N.: 044-241-006)

A-10

EXHIBIT B

LEGAL DESCRIPTION OF MINERAL RIGHTS

The “Mineral Rights” means

(1) all oil, gas and other hydrocarbon substances, and all other mineral and otherwise valuable substances, in the Arroyo Grande Surface Estate or under the Arroyo Grande Surface Estate or which may be produced therefrom; and the sole and exclusive right to the possession, use, development and improvement of the surface and all subsurface depths thereof as may be necessary or convenient to surveying, prospecting and exploring for, producing, storing, treating, and transporting any and all such substances; including operations (and such possession, use, development and improvement of the surface and all subsurface depths thereof as may be necessary or convenient to operations) by means and in a manner now known or unknown; and, further, including the exclusive right to mine or drill from the surface of, or into or through the subsurface of, any part of the Arroyo Grande Surface Estate in connection with operations incidental to surveying, prospecting and exploring for, producing, storing, treating, and transporting any and all such substances within and from any and all other lands; and, further, including the exclusive right to the possession, use, development and improvement of the surface and all subsurface depths thereof as may be necessary or convenient to surveying, prospecting and exploring for, producing, storing, treating, and transporting any and all such substances within and from any and all lands other than and in addition to the Arroyo Grande Surface Estate (all of which are hereinafter referred to and included within the “Mineral Interest” in the Arroyo Grande Surface Estate); and

(2) all of PXP’s existing right, title and interest in, to and under any and all oil and gas leases affecting all or any part of the Arroyo Grande Surface Estate (which, if any, are hereinafter referred to collectively as the “Leases”);

(3) all right, title and interest of PXP in, to and under easements, tangible and intangible personal property, facilities, fixtures, equipment, rights and benefits incidental and appurtenant to the ownership, use or operation of any part of the Mineral Interest, under the Leases or otherwise, within all or any part of the Arroyo Grande Surface Estate or other lands, or both, including, without limitation:

(a) all contracts and agreements whether recorded or unrecorded in existence at the Effective Date, which affect any part of the Mineral Interest in the Arroyo Grande Surface Estate, or other lands, or any of the Leases; and

(b) all facilities and equipment (whether active or inactive) customarily used directly in the production of crude oil, natural gas, casinghead gas, condensate, sulphur, natural gas liquids, plant products and other liquid or gaseous hydrocarbon substances (including CO₂), and all other minerals of every kind and character attributable to PXP’s interest in any part of the Arroyo Grande Surface Estate, or other lands, or any of the Leases (collectively, “Hydrocarbons”), including but not limited to wells (whether plugged or unplugged), injection facilities, disposal facilities, equipment, fixtures,

B-1

incidentals and appurtenances, facilities and personal property of any kind (including, but not limited to, tubing, casing, wellheads, pumping units, production units, compressors, valves, meters, flowlines, pipelines and other lesser piping, tanks, heaters, separators, dehydrators, pumps, injection units, gates and fences, field separators, liquid extractors, compressors, LACT units; plants, tanks and the like); and

(c) presently existing pooling, unitization and communitization agreements or other operating agreements and the right, title and interest of PXP in and to the units created thereby (including without limitation all units formed under orders, regulations, rules or other official acts of any governmental entity, agency or officer) related, incidental or appurtenant to the Mineral Interest in any part of the Arroyo Grande Surface Estate, or other lands, or any of the Leases; and

(d) exclusive and non-exclusive rights to the use and occupancy of land, including, without limitation, tenements, appurtenances, surface leases, easements, permits, licenses, franchises, servitudes and rights-of-way appertaining, belonging, affixed or incidental to or used in connection with the ownership of the Mineral Interest, or operations incidental to the enjoyment of the Mineral Interest, in any part of the Arroyo Grande Surface Estate, or other lands, or any of the Leases, whether recorded or unrecorded; and

(e) licenses, authorizations, permits, variances and similar rights and interests, and other rights, privileges, benefits and powers conferred upon the owner of the Mineral Interest, or operations incidental to the enjoyment of the Mineral Interest, in any part of the Arroyo Grande Surface Estate, or other lands, or upon the holder of any of the Leases, including, without limitation, all claims causes of action, insurance policies or proceeds therefrom, appertaining, belonging, affixed or incidental to or held or exercised in connection with the Mineral Interest in any part of the Arroyo Grande Surface Estate, or other lands, or any of the Leases; and

(f) general operating records, well files (including applicable well logs and production data), lease files, land files, environmental compliance files, regulatory reports and certificates, abstracts and title work appertaining, belonging or incidental to the Mineral Interest in any part of the Arroyo Grande Surface Estate, or other lands, or any of the Leases; and

(4) all easements and rights-of-way of any kind or nature standing in the name of, reserved by or granted by PXP, PXP’s predecessors, subsidiaries or affiliates or any predecessor, subsidiary or affiliate, related to the Arroyo Grande Surface Estate, whether or not such rights appear of record and whether or not identifiable by inspection of the real property, and all equipment, pipelines, powerlines and other facilities used in association with such easements and rights-of-way.

B-2

SCHEDULE 7.4

THIRD PARTY AGREEMENTS

Consultant is in discussions with the Ezralow Company and John Markley pursuant to which it expects to enter into an agreement to engage both parties to assist Consultant in performing the services contemplated herein.

7.4-1

EX-10.15

Exhibit 10.15

PLAINS EXPLORATION & PRODUCTION COMPANY

2004 STOCK INCENTIVE PLAN

RESTRICTED STOCK UNIT AGREEMENT

This Restricted Stock Unit Agreement (the “Agreement”), made as of the                      day of                      (the “Grant Date”), by and between Plains Exploration & Production Company (the “Company”), and «Name» (the “Grantee”), evidences the grant by the Company of restricted stock units (“Restricted Stock Units” or “Award”) to the Grantee on such date and the Grantee’s acceptance of the Award in accordance with the provisions of the Plains Exploration & Production Company 2004 Stock Incentive Plan, as amended or restated from time to time (the “Plan”). The Company and the Grantee agree as follows:

1. Basis for Award. This Award is made in accordance with Section 10 of the Plan. The Grantee hereby receives as of the date hereof an Award of Restricted Stock Units pursuant to the terms of this Agreement (the “Grant”).

2. Stock Awarded.

(a) Effective upon the execution of this Agreement by all of the parties hereto, which must occur no later than                     , failure of which causes this award to immediately expire and terminate, the Company hereby awards to the Grantee, in the aggregate, «Units» Restricted Stock Units.

(b) The Company shall in accordance with the Plan establish and maintain a Restricted Stock Unit Account for the Grantee, and such account shall be credited for the number of Restricted Stock Units granted to the Grantee. The Restricted Stock Unit Account shall be credited for any securities or other property (including regular cash dividends) distributed to the Company in respect of its Shares. Any such property shall be subject to the same vesting schedule as the Restricted Stock Units to which they relate.

(c) Until the Restricted Stock Units awarded to the Grantee shall have vested, the Restricted Stock Units and any related securities, cash dividends or other property nominally credited to a Restricted Stock Unit Account shall not be sold, transferred, or otherwise disposed of and shall not be pledged or otherwise hypothecated.

3. Vesting. The Restricted Stock Units covered by this Agreement shall vest one-third on                     , one-third on                     , and one-third on                     , provided that, Grantee is still employed by the Company (or any Parent or Subsidiary) on such vesting date. The vesting of Restricted Stock Units may be deferred under the terms of a deferred compensation plan of the Company, if any, in which the Grantee participates. The Restricted Stock Units shall immediately vest with respect to 100% of the Restricted Stock Units covered by this Agreement upon the occurrence of any of the following events: (a) the Grantee’s death, separation from employment due to Disability, termination of employment by the Company without Cause, or termination of employment by the Grantee for Good Reason provided that the Grantee’s employment agreement with the Company provides for a termination of employment by

the Grantee for Good Reason (as defined in such employment agreement), or (b) a Change in Control of the Company. If the Grantee ceases to be employed by the Company (or any Parent or Subsidiary) for any other reason at any time prior to the lapse of restrictions, the unvested Restricted Stock Units shall automatically be forfeited upon such cessation of employment.

4. Payment. As soon as practicable after the vesting date, payment shall be made in Shares. The Committee shall cause a stock certificate to be delivered to the Grantee with respect to such Shares free of all restrictions hereunder, except for applicable federal securities laws restrictions. Any securities, cash dividends or other property credited to the Restricted Stock Unit Account other than Restricted Stock Units shall be paid in kind, or, in the discretion of the Committee, in cash.

5. Compliance with Laws and Regulations. The issuance of Shares upon vesting of the Restricted Stock Units shall be subject to compliance by the Company and the Grantee with all applicable requirements of securities laws, other applicable laws and regulations of any stock exchange on which the Shares may be listed at the time of such issuance or transfer. The Grantee understands that the Company is under no obligation to register or qualify the Shares with the Securities and Exchange Commission (“SEC”), any state securities commission or any stock exchange to effect such compliance.

6. Tax Withholding. The Grantee agrees that no later than the date as of which the Restricted Stock Units vest, the Grantee shall pay to the Company (in cash or to the extent permitted by the Committee, Shares held by the Grantee whose Fair Market Value on the day preceding the date the Restricted Stock Units vests is equal to the amount of the Grantee’s tax withholding liability) any federal, state or local taxes of any kind required by law to be withheld, if any, with respect to the Restricted Stock Units for which the restrictions shall lapse. Alternatively, the Company or its Affiliates shall, to the extent permitted by law, have the right to deduct from any payment of any kind otherwise due to the Grantee (including payments due when the Restricted Stock Units vest) any federal, state or local taxes of any kind required by law to be withheld with respect to the shares of Restricted Stock Units.

7. Nontransferability. This Award is not transferable.

8. No Right to Continued Employment. Nothing in this Agreement shall be deemed by implication or otherwise to impose any limitation on the right of the Company or any of its affiliates to terminate the Grantee’s employment at any time, in absence of a specific written agreement to the contrary.

9. Representations and Warranties of Grantee. The Grantee represents and warrants to the Company that:

(a) Agrees to Terms of the Plan. The Grantee has received a copy of the Plan and has read and understands the terms of the Plan and this Agreement, and agrees to be bound by their terms and conditions. The Grantee acknowledges that there may be adverse tax consequences upon the vesting of Restricted Stock Units or thereafter if the Award is paid and the Grantee later disposes of the Shares, and that the Grantee should consult a tax advisor prior to such time.

(b) Cooperation. The Grantee agrees to sign such additional documentation as may reasonably be required from time to time by the Company.

10. Adjustment Upon Changes in Capitalization. In the event of a Change in Capitalization, the Committee may make appropriate adjustments to the number and class of shares relating to the Restricted Stock Units as it deems appropriate, in its sole discretion, to preserve the value of this Award. The Committee’s adjustment shall be made in accordance with the provisions of Section 14 of the Plan and shall be effective and final, binding and conclusive for all purposes of the Plan and this Agreement.

11. Governing Law; Modification. This Agreement shall be governed by the laws of the State of Delaware without regard to the conflict of law principles. The Agreement may not be modified except in writing signed by both parties.

12. Defined Terms. Except as otherwise provided herein, or unless the context clearly indicates otherwise, capitalized terms used but not defined herein have the definitions as provided in the Plan. The terms and provisions of the Plan are incorporated herein by reference, and the Grantee hereby acknowledges receiving a copy of the Plan. In the event of a conflict or inconsistency between the discretionary terms and provisions of the Plan and the provisions of this Agreement, the Plan shall govern and control.

13. Miscellaneous. The masculine pronoun shall be deemed to include the feminine, and the singular number shall be deemed to include the plural unless a different meaning is plainly required by the context.

IN WITNESS WHEREOF, the parties hereto have signed this Agreement as of the date first above written.

PLAINS EXPLORATION & PRODUCTION COMPANY
By:
	John F. Wombwell, Executive Vice President
GRANTEE
«Name»

EX-10.16

Exhibit 10.16

AMENDED AND RESTATED

PLAINS EXPLORATION & PRODUCTION COMPANY

EXECUTIVES’ LONG-TERM RETENTION

& DEFERRED COMPENSATION PLAN

WHEREAS, Plains Exploration & Production Company (the “Company”) heretofore established the Plains Exploration & Production Company Executive’s Long-Term Retention & Deferral Compensation Plan (the “Plan”); and

WHEREAS, the Company has determined that it is in the best interests of the Company and the Participants to amend the Plan to provide for the creation and funding of a “rabbi” trust for the purpose of paying benefits under the Plan in certain specified circumstances as hereinafter provided;

NOW, THEREFORE, the Plan is hereby amended and restated effective as of February 10, 2006 to read as follows:

ARTICLE I.

PURPOSES OF PLAN AND DEFINITIONS

1.1 Purpose

The Company has established the Plan for the purpose of providing certain management and highly compensated employees (“Executives”) of the Company the opportunity to defer all or a portion of their cash or equity compensation, to better align the interests of the Executives with those of the Company’s shareholders and to attract and retain talented individuals. This Plan is intended to be an unfunded nonqualified plan of deferred compensation that complies with section 409A of the Internal Revenue Code of 1986 as amended (the “Code”) and a “top hat” pension plan within the meaning of Department of Labor regulations promulgated pursuant to the Employee Retirement Income Security Act of 1976 as amended.

1.2 Definitions

Account means the bookkeeping account maintained for each Participant to record certain amounts deferred by the Participant in accordance with Article III hereof.

Agreement means an award of Long-Term Retention Compensation made to a Participant pursuant to the terms of the Plan.

Beneficiary means the person or persons designated by the Participant, as provided in § 4.4, to receive any payments otherwise due the Participant under this Plan in the event of the Participant’s death.

Board of Directors or Board means the Board of Directors of the Company.

Change in Control shall have the meaning set forth in the Plains Exploration & Production Company 2004 Stock Incentive Plan.

Compensation means Equity Compensation, Deferred Compensation and Long-Term Retention Compensation.

Code means the Internal Revenue Code of 1986, as amended.

Committee means the Compensation Committee of the Board.

Common Stock means the Company’s common stock, $.01 par value.

Company means Plains Exploration & Production Company, a Delaware corporation.

Deferral Election means an election by the Participant to defer receipt of Compensation.

Deferred Compensation means any Compensation with respect to which Participant has made a Deferral Election or is payable to Participant as Long-Term Retention Compensation.

Disability means that the Participant is disabled within the meaning of section 409A of the Code and any applicable guidance.

Effective Date means the effective date of the Plan, which shall be August 3, 2005.

Election Date means the date on which the Executive makes an election to defer receipt of all or a portion of Compensation pursuant to the terms of the Plan and such election is received by the Committee.

Election Effective Date means the date a Deferral Election becomes effective.

Equity Compensation means all of the Compensation for services to the Company paid in the form of or measured by reference to Common Stock of the Company and which is issued pursuant to a plan of equity compensation which has been adopted by the Company and approved by its shareholders; provided, however, any options granted to a Participant to purchase shares of Common Stock or restricted Common Stock granted to a Participant shall not be subject to Deferral Elections under the terms of the Plan.

Exchange Act means the Securities Exchange Act of 1934, as amended from time to time.

Fair Market Value of a share of Common Stock means, as of a particular date the price at which the last sale of Common Stock was made on the New York Stock Exchange, or if no sales occurred on such day, then on the last day on which there were such sales. Fair Market Value of a Stock Unit shall be deemed to be equal to the Fair Market Value of one share of Common Stock.

2

Long-Term Retention Compensation means Compensation payable to Participant pursuant to the terms of Article IV of the Plan.

Participant means an Executive of the Company who is designated as eligible to participate in the Plan by the Committee and elects to participate in the Plan.

Payment Date means the date or dates on which payment of a Participant’s Deferred Compensation is made, as determined in accordance with § 4.1.

Plan means the Plains Exploration & Production Company Executives’ Long-Term Retention and Deferred Compensation Plan, as amended from time to time.

Restricted Stock Unit means a unit equal in value to one share of Common Stock (as adjusted pursuant to § 3.5), utilized for the purpose of measuring the benefits payable under § 4.2.

Vest, Vested or Vesting means not subject to forfeiture upon the occurrence of any event.

ARTICLE II.

ADMINISTRATION OF THE PLAN

2.1 Committee

This Plan shall be administered by the Committee.

2.2 Committee’s Powers

Subject to the provisions hereof, the Committee shall have full and exclusive power and authority to administer this Plan and to take all actions that are specifically contemplated hereby or are necessary or appropriate in connection with the administration hereof. The Committee shall also have full and exclusive power to interpret this Plan and to adopt such rules, regulations, and guidelines for carrying out this Plan as it may deem necessary or proper, all of which powers shall be exercised in the best interests of the Company and in keeping with the objectives of this Plan. The Committee may, in its discretion, determine the eligibility of individuals to participate herein, determine the amount of Compensation a Participant may elect to defer, or waive any restriction or other provision of this Plan; provided, however, that the Committee shall not waive any restriction or other provision of this Plan or take any other action that would cause any benefits provided to a Participant hereunder to be deemed “derivative securities” within the meaning of § 16 of the Exchange Act or the rules and regulations promulgated thereunder (including, but not limited to, Rule 16a-1(c) or any successor rule) or would result in adverse tax consequences to Participant under section 409A of the Code; provided further, however, that no member of the Committee may participate in or take any action with respect to any decision regarding his or her own Compensation. The Committee may correct any defect or supply any omission or reconcile any inconsistency in this Plan in the manner and to the extent the Committee deems necessary or desirable to carry it into effect.

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2.3 Committee Determinations Conclusive

Any decision of the Committee in the interpretation and administration of this Plan shall lie within its sole and absolute discretion and shall be final, conclusive, and binding on all parties concerned.

2.4 Committee Liability

No member of the Committee or officer of the Company to whom the Committee has delegated authority in accordance with the provisions of § 2.5 of this Plan shall be liable for anything done or omitted to be done by him or her, by any member of the Committee, or by any officer of the Company in connection with the performance of any duties under this Plan, except for his or her own willful misconduct or as expressly provided by statute.

2.5 Delegation of Authority

The Committee may delegate to the Chief Executive Officer or to other senior officers of the Company certain administrative duties under this Plan pursuant to such conditions or limitations as the Committee may establish. In no event may any Participant in this Plan exercise any discretion reserved to the Committee under the Plan.

ARTICLE III.

DEFERRALS

3.1 Establishment of Accounts

The Company shall set up an appropriate record (the “Account”), which will from time to time reflect the name of each Participant and the amounts credited to such Participant pursuant to § 3.2.

3.2 Equity Compensation Deferral

A Participant may elect to defer receipt of all or part of any Equity Compensation payable to the Participant. Except as otherwise provided in Section 3.3 below, to be effective, a Deferral Election must be made by the Participant in the calendar year prior to the year in which the services giving rise to the Equity Compensation are performed. The Election Effective Date shall be the first day of the calendar year occurring after the Deferral Election. Subject to the provisions of Section 3.11 below, if a Participant makes a Deferral Election, a number of Restricted Stock Units (rounded up to the nearest whole number) having a Fair Market Value equal to the dollar amount of Equity Compensation the Participant elects to forgo shall be credited to the Participant’s Account as of the date that such Equity Compensation would be paid to Participant but for the Deferral Election. Each Deferral Election shall be irrevocable as of the Election Effective Date and shall be effective for a period of one calendar year beginning on the Election Effective Date. Deferred Compensation attributable to an Equity Compensation Deferral Election shall be Vested according to the terms of the Equity Compensation grant without regard to the Deferral Election.

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3.3 Elections of First-Year Participants

In the case of the first year in which a Participant becomes eligible to participate in the Plan, a Deferral Election may be made with respect to services to be performed subsequent to the election, provided that such election is made within 30 days after the date the Participant first becomes eligible to participate. In such case, the Election Effective Date shall be the first date that services are performed after the Election Date.

3.4 Deferral Elections

Each Deferral Election made by a Participant under the Plan (i) shall take the form of a written document (provided by the Company) signed by the Participant and filed with the Company, (ii) shall designate the calendar year for which the deferral is made and the period of deferral, and (iii) cannot be revoked or modified if either (a) the proposed revocation or modification applies to amounts deferred with respect to a calendar year which has already commenced at the time such revocation or modification is proposed to be effected, or (b) the Committee determines in its sole discretion that the proposed revocation or modification could cause any benefits provided to a Participant hereunder to be treated as “derivative securities” within the meaning of § 16 of the Exchange Act or the rules and regulations promulgated thereunder (including, but not limited to, Rule 16a-1(c) or any successor rule) or could result in adverse tax consequences to the Participant under section 409A of the Code. Any election to change a Deferral Election (including an election to change a Payment Date) shall be subject to the consent of the Committee and the terms of the Plan.

3.5 Dividends

As of each date that dividends are paid with respect to Common Stock, a Participant who has any outstanding Restricted Stock Units credited to his or her Account shall have an additional amount credited to his or her Account equal to the number of Restricted Stock Units (rounded up to the nearest whole number) having a Fair Market Value equal to the dollar amount of dividends paid per share of Common Stock multiplied by the number of Restricted Stock Units credited to the Participant’s Account as of the payment date of such dividend.

3.6 Adjustments

(a) Exercise of Corporate Powers. The existence of this Plan and any outstanding Restricted Stock Units credited hereunder shall not affect in any manner the right or power of the Company or its stockholders to make or authorize any or all adjustments, recapitalizations, reorganizations or other changes in the capital stock of the Company or its business or any merger or consolidation of the Company, or any issue of bonds, debentures, preferred or prior preference stock (whether or not such issue is prior to, on a parity with or junior to the Common Stock) or the dissolution or liquidation of the Company, or any sale or transfer of all or any part of its assets or business, or any other corporate act or proceeding of any kind, whether or not of a character similar to that of the acts or proceedings enumerated above.

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(b) Recapitalizations, Reorganizations and Other Activities. In the event of any subdivision or consolidation of outstanding shares of Common Stock, declaration of a dividend payable in shares of Common Stock or other stock split, then (i) the number of Restricted Stock Units and (ii) the appropriate Fair Market Value and other price determinations for such Restricted Stock Units shall each be proportionately adjusted by the Board to reflect such transaction. In the event of any other recapitalization or capital reorganization of the Company, any consolidation or merger of the Company with another corporation or entity, the adoption by the Company of any plan of exchange affecting the Common Stock or any distribution to holders of Common Stock of securities or property (other than normal cash dividends or dividends payable in Common Stock), the Board shall make appropriate adjustments to (i) the number of Restricted Stock Units and (ii) the appropriate Fair Market Value and other price determinations for such Restricted Stock Units to give effect to such transaction; provided that such adjustments shall only be such as are necessary to preserve, without increasing, the value of such units. In the event of a corporate merger, consolidation, acquisition of property or stock, separation, reorganization or liquidation, the Board shall be authorized to issue or assume units by means of substitution of new units, as appropriate, for previously issued units or an assumption of previously issued units as part of such adjustment.

3.7 Payment Date

(a) Payment Date. A Participant may elect that payment of Deferred Compensation under the Plan be made on a date or pursuant to a fixed schedule specified on the Deferral Election form (the “Payment Date”) provided by the Committee, provided that such date does not occur before the date such Deferred Compensation would be paid or Vested absent such deferral. In the event of the death or Disability of an Executive prior to the date specified on the Deferral Election form, such Executive’s date of death or Disability shall be his or her Payment Date. If Participant does not make a payment election at the time of the Deferral Election, his or her Payment Date shall be the earliest of:

(i) the tenth anniversary of the Election Effective Date;

(ii) death or Disability of the Participant;

(iii) six months (or such shorter period as may be permitted pursuant to regulations or interpretations of Section 409A of the Code) following the date of Executive’s separation from service; or

(iv) occurrence of an unforeseeable emergency as defined in Section 409A of the Code.

(b) Changes to Payment Date. After the Election Effective Date a Participant who has a right to receive Deferred Compensation pursuant to this Plan may elect to

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defer payment beyond the Payment Date, provided that each of the following conditions is met:

(i) such election may not take effect until at least twelve (12) months after the date on which the election is made;

(ii) except in the case of death or Disability the first payment with respect to which such election is made must be deferred for a period of at least 5 years from the date such payment would otherwise have been made, and

(iii) in the case of a payment to be made pursuant to a fixed schedule or on a fixed date, any election may not be made less than twelve (12) months prior to the date of the first scheduled Payment Date.

3.8 Payment/Withholding

As of the Payment Date, the aggregate Fair Market Value of the Restricted Stock Units then credited to a Participant’s Account shall be calculated. Payment to a Participant of his of her Account (subject to any applicable tax or withholding required under state, federal or local law) shall be made in cash or Common Stock, at the discretion of the Committee as soon as administratively feasible following the Payment Date. The Company shall deduct and withhold from the Account or any other amounts due to Participant any applicable employment or income tax or withholding required to be paid or withheld with respect to Participant’s Compensation.

3.9 Death Prior to Payment

In the event that a Participant dies prior to payment pursuant to the Plan, any such unpaid amounts shall be paid to the Participant’s designated Beneficiary in a lump sum within sixty (60) days following the Company’s notification of the Participant’s death. If no Beneficiary has been designated, such payment shall be made to the Participant’s estate. A beneficiary designation, or revocation of a prior beneficiary designation, shall be effective only if it is made in writing on a form provided by the Company, signed by the Participant and received by the Committee.

3.10 Limitation on Restricted Stock Units Credited to Accounts and Hypothetical Investment

Restricted Stock Units shall be credited to a Participant’s Account only if and to the extent that the Company has adopted a plan of equity compensation that has been approved by the Company’s shareholders which permits the granting of Restricted Stock Units to Participant. In the event that Restricted Stock Units may not be credited to Participant’s Account, the Committee shall denominate the portion of Participant’s Account that is not in Restricted Stock Units in US dollars. In addition, notwithstanding anything in the Plan to the contrary, the Committee in its sole discretion may permit the Participant to elect to denominate all or part of his or her Account in US dollars in lieu of Restricted Stock Units. In the event that any portion of a Participant’s Account is denominated in US dollars, the Participant shall be allowed to select from among various hypothetical investment benchmarks selected by the Committee, which shall include, but not be limited to, common stock of the Company. If the Participant does not select

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from among the hypothetical investment benchmarks made available by Committee, the Participant’s Account shall be credited with simple interest at the rate of six (6%) per annum. The Participant’s Account shall be adjusted from time to time, but not less often than semi-annually for any earnings, gains and losses allocable to such Account from such hypothetical investment benchmarks or interest. Notwithstanding the foregoing, the terms of this Plan place no obligation upon the Company to set aside or to invest or to continue to invest any funds or portion of the Account in any specific asset, to liquidate any particular investment, or to apply in any specific manner the proceeds from the sale, liquidation, or maturity of any particular investment. The Company assumes no risk of any decrease in the value of any investment designations made by Participant with respect to the hypothetical investment benchmarks. The Company’s sole obligations are to maintain the Participant’s Account and make payments to the Participant as herein provided.

ARTICLE VI.

LONG-TERM RETENTION COMPENSATION

4.1 Retention Awards

Each Participant shall be eligible to receive Long-Term Retention Compensation in an amount and according to the terms and conditions determined by the Committee and set forth in an Agreement. Such Long-Term Retention Compensation shall be in the form of additional Restricted Stock Units to be added to Participant’s Account according to the terms and conditions determined by the Committee and set forth in an Agreement. Such Agreement shall specify the Payment Date and any provisions relating to Deferral Elections or Vesting not inconsistent with the Plan. Except as otherwise provided in the Agreement, Participant may elect to change the Payment Date with respect to Long-Term Retention Compensation according to the requirements set forth in Section 3.7 (b) of the Plan.

ARTICLE V.

RABBI TRUST

5.1 Creation and Funding of Rabbi Trust

The Company shall enter into a Trust Agreement substantially in the form set forth in Exhibit A Attached hereto (the “Trust”). Prior to or as soon as administratively feasible following a Participant’s separation from service or a Change in Control, the Company shall transfer cash, Common Stock or other property to the Trustee of such Trust, the amount or Fair Market Value of which shall be equal to or greater than the vested Accounts of all Participants in the event of a Change in Control or the Account of the Participant separating from service in the event of a Participant’s separation from service in the absence of a Change in Control. Such amounts shall be held by the trustee of the Trust and shall be paid to the Participant by the trustee on the applicable Payment Date.

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ARTICLE VI.

MISCELLANEOUS

6.1 Unfunded Plan

This Plan shall be unfunded. Any funds invested hereunder shall continue for all purposes to be part of the general funds of the Company. To the extent that a Participant acquires a right to receive payments from the Company under the Plan, such right shall not be greater than the right of any unsecured general creditor of the Company and such right shall be an unsecured claim against the general assets of the Company. Although bookkeeping accounts may be established with respect to Participants who are entitled to rights under this Plan, any such accounts shall be used merely as a bookkeeping convenience. Except as otherwise provided herein, the Company shall not be required to segregate any assets that may at any time be represented by cash or rights thereto, nor shall this Plan be construed as providing for such segregation, nor shall the Company, the Board or the Committee be deemed to be a trustee of any cash or rights thereto to be granted under this Plan. Any liability or obligation of the Company to any Participant with respect to cash or rights thereto under this Plan shall be based solely upon any contractual obligations that may be created by this Plan, and no such liability or obligation of the Company shall be deemed to be secured by any pledge or other encumbrance on any property of the Company. Neither the Company nor the Board nor the Committee shall be required to give any security or bond for the performance of any obligation that may be created by this Plan.

6.2 Statement of Account

A statement will be furnished to each Participant not less often than annually and shall reflect the balance and Fair Market Value of the Participant’s Account as of the preceding December 31.

6.3 Assignability

Except as otherwise provided herein, no right to receive payment hereunder shall be transferable or assignable by a Participant except by will or the laws of descent and distribution or pursuant to a qualified domestic relations order as defined by the Code or Title I of the Employee Retirement Income Security Act of 1974, as amended, or the rules thereunder. Any attempted assignment of any benefit under this Plan in violation of this § 5.4 shall be null and void.

6.4 Amendment, Modification, Suspension, or Termination

The Board may amend, modify, suspend, or terminate this Plan for the purpose of meeting or addressing any changes in legal requirements or for any other purpose permitted by law, except that no amendment, modification, or termination shall, without the consent of the Participant, impair the rights of any Participant to the balance in such Participant’s Stock Unit Account as of the date of such amendment, modification, or termination. The Board may at any time and from time to time delegate to the Committee any or all of its authority under this § 5.5.

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6.5 Payments to Minors and Incompetents

Should the Participant become incompetent or should the Participant designate a Beneficiary who is a minor or incompetent, the Company shall be authorized to pay such funds to a parent or guardian of such minor or incompetent, or directly to such minor or incompetent, whichever manner the Committee shall determine in its sole discretion.

6.6 Governing Law

This Plan and all determinations made and actions taken pursuant hereto, to the extent not otherwise governed by mandatory provisions of the Code or the securities laws of the United States, shall be governed by and construed in accordance with the laws of the State of Texas.

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EX-10.19

Exhibit 10.19

FIRST AMENDMENT

TO THE

PLAINS EXPLORATION & PRODUCTION COMPANY

LONG-TERM RETENTION AGREEMENT

JAMES C. FLORES

WHEREAS, Plains Exploration & Production Company (the “Company”) and James C. Flores (“Executive”) entered into the Plains Exploration & Production Company Long-Term Retention Agreement (the “Agreement”) dated effective as of the 10th day of February, 2006 (the “Effective Date”); and

WHEREAS, the Company and Executive have agreed to amend the Agreement as set forth below;

NOW, THEREFORE, effective as of the Effective Date, the parties hereto agree as follows:

1. The following sentence shall be added to paragraph 4 of the Agreement:

“The amount so credited to Executive’s Account shall then be contributed by the Company in cash, Common Stock or other property to the Trust created under the Plan to be held by the trustee of such Trust until paid according to the terms of this Agreement, to Executive.”

2. The words “a Deferral Election or” shall be stricken from the first sentence of paragraph 5 of the Agreement.

3. The first sentence of paragraph 6 of the Agreement shall be deleted.

4. As modified herein, the Agreement is hereby ratified and affirmed in all respects.

IN WITNESS WHEREOF, the parties hereto have signed this to be effective set forth above.

PLAINS EXPLORATION & PRODUCTION COMPANY

By:	/s/ John F. Wombwell	Date: February 10, 2006
Name:	John F. Wombwell
Title:	Executive Vice President, General Counsel & Secretary
Executive
By:	/s/ James C. Flores	Date: February 10, 2006

EX-10.20

Exhibit 10.20

FIRST AMENDMENT

TO THE

PLAINS EXPLORATION & PRODUCTION COMPANY

LONG-TERM RETENTION AGREEMENT

WHEREAS, Plains Exploration & Production Company (the “Company”) and                      (“Executive”) entered into the Plains Exploration & Production Company Long-Term Retention Agreement (the “Agreement”) dated effective as of the 10th day of February, 2006 (the “Effective Date”); and

WHEREAS, the Company and Executive have agreed to amend the Agreement as set forth below;

NOW, THEREFORE, effective as of the Effective Date, the parties hereto agree as follows:

1. The following sentence shall be added to paragraph 4 of the Agreement:

“The amount so credited to Executive’s Account shall then be contributed by the Company in cash, Common Stock or other property to the Trust created under the Plan to be held by the trustee of such Trust until paid according to the terms of this Agreement, to Executive.”

2. The words “a Deferral Election or” shall be stricken from the first sentence of paragraph 5 of the Agreement.

3. The first sentence of paragraph 6 of the Agreement shall be deleted.

4. As modified herein, the Agreement is hereby ratified and affirmed in all respects.

IN WITNESS WHEREOF, the parties hereto have signed this to be effective set forth above.

PLAINS EXPLORATION & PRODUCTION COMPANY
By:	Date:
Name:
Title:
Executive
By:	Date:

EX-10.25

Exhibit 10.25

PLAINS EXPLORATION & PRODUCTION COMPANY

FIRST AMENDMENT TO

EMPLOYMENT AGREEMENT

WHEREAS, effective as of June 4, 2004 Plains Exploration & Production Company (the “Company”) entered into an employment agreement (the “Agreement”) with James C. Flores (the “Employee”); and

WHEREAS, the Company and the Employee have agreed to amend the Agreement as set forth below;

NOW, THEREFORE, the Company and the Employee agree as follows:

1. Paragraph 4(b) of the Agreement shall be amended by adding the following sentence thereto:

“Such bonus, if any, shall be paid not later than the fifteenth day of the third calendar month following the later of (i) the last day of the calendar year or (ii) the last day of the Company’s fiscal year.”

2. Paragraph 6(c)(i) of the Agreement shall be amended by striking the words “immediately upon termination of Employee’s employment” from the third sentence thereof, changing “one” to “three” in such sentence and inserting the following sentence at the end thereof:

“Immediately upon termination of Employee’s employment, amounts payable pursuant to (A) above shall be contributed to the trustee of a “rabbi” trust substantially in the form attached hereto (the “Trust”). Such amounts shall be held by the trustee pursuant to the terms of such Trust and paid to Executive on the earlier of: (1) the first day that is six months following his separation from service (within the meaning of section 409A of the Internal Revenue Code of 1986 as amended (the “Code”)); or (2) as soon as administratively feasible following Executive’s date of death.”

3. Paragraph 6(c)(ii) shall be amended by striking the words “payable in full, as the case may be, with” and inserting the following sentence at the end thereof:

“Immediately upon termination of Employee’s employment, amounts payable pursuant to this paragraph shall be contributed to the trustee of the Trust. Such amounts shall be held by the trustee pursuant to the terms of such Trust and paid to Executive on the earlier of: (1) the first day that is six months following his separation from service (within the meaning of section 409A of the Internal Revenue Code of 1986 as amended (the “Code”)); or (2) as soon as administratively feasible following Executive’s date of death.”

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4. Paragraph 6(e) shall be amended to read as follows:

“(e) Resignation for Good Reason. If Employee resigns his employment for Good Reason, Employee shall be entitled to the compensation and benefits provided in Section 6(c) hereof. “Good Reason” shall mean (1) the material breach of any of the Company’s obligations under this Agreement without Employee’s written consent or (2) the occurrence of any of the following circumstances and other than with respect to item (iv) below, without the Employee’s written consent:”

5. Paragraph 6(j) of the Agreement shall be amended to read as follows:

“(j) Full Tax Gross-Up of Excise Tax Payments. In the event that any payment, award, benefit or distribution (or any acceleration of any payment, award, benefit or distribution) made or provided to or for the benefit of Employee in connection with this Agreement, or Employee’s employment with Company or the termination thereof (the “Payments”) is determined to be subject to the excise tax imposed by Section 4999 or 409A of the Code or any interest or penalties with respect to such excise taxes (such excise taxes, together with any such interest and penalties, are collectively referred to as the “Excise Taxes”), then the Employee shall be entitled to receive an additional payment (a “Gross-Up Payment”) from Company such that the net amount received by the Executive after paying any applicable Excise Taxes and any federal, state or local income or FICA taxes on such Gross-Up Payment, shall be equal to the amount Executive would have received if such Excise Taxes were not applicable to the Payments.

For purposes of determining whether any of the Payments will be subject to the Excise Taxes and the amount of such Excise Taxes, (i) all of the Payments shall be treated as “parachute payments” (within the meaning of Section 280G(b)(2) of the Code) unless, in the opinion of tax counsel (“Tax Counsel”) reasonably acceptable to the Employee, such payments or benefits (in whole or in part) do not constitute parachute payments, including by reason of Section 280G(b)(4)(A) of the Code; (ii) all “excess parachute payments” within the meaning of Section 280G(b)(1) of the Code shall be treated as subject to the Excise Tax unless, in the opinion of Tax Counsel, such excess parachute payments (in whole or in part) represent reasonable compensation for services actually rendered (within the meaning of Section 280G(b)(4)(B) of the Code) in excess of the base amount (as the term “base amount” is defined in Section 280G(b)(3) of the Code) allocable to such reasonable compensation, or are otherwise not subject to the Excise Tax; (iii) the value of any noncash benefits or any deferred payment or benefit shall be determined by the Tax Counsel in accordance with the principles of Sections 280G(d) and 409A of the Code; and (iv) all Payments shall be deemed subject to the Excise Tax pursuant to section 409A of the Code unless, in the opinion of Tax Counsel, such Payments are not subject to Excise Tax pursuant to section 409A. For purposes of determining the amount of the Additional Payment, the Employee shall be deemed to pay federal income tax at the highest marginal rate of federal income taxation in the calendar year in which the Total Payments are made and State and local income taxes at the highest marginal rate of taxation in the State and locality of the Employee’s

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residence on the date the Total Payments are made, net of the maximum reduction in federal income taxes which could be obtained from deduction of such State and local taxes.

In the event that the Excise Taxes are determined by the IRS, on audit or otherwise, to exceed the amount taken into account hereunder in calculating the Gross-Up Payment (including by reason of any payment the existence or amount of which cannot be determined at the time of the Gross-Up Payment), the Company shall make another Gross-Up Payment in respect of such excess (plus any interest, penalties or additions payable by the Employee with respect to such excess) within the ten (10) business days immediately following the date that the amount of such excess is finally determined. The Employee and the Company shall each reasonably cooperate with the other in connection with any administrative or judicial proceedings concerning the existence or amount of liability for Excise Tax with respect to the Total Payments.

If a termination of the Employee’s employment shall have occurred, the Company shall promptly reimburse to the Employee all reasonable attorneys fees and expenses necessarily incurred by the Employee in disputing in good faith any issue with the Company or its affiliates pursuant to this Agreement or asserting in good faith any claim, demand or cause of action against the Company or its affiliates pursuant to this Agreement. Such payments shall be made within ten (10) business days after delivery of the Employee’s written requests for payment accompanied with such evidence of fees and expenses incurred as the Company reasonably may require.

The Gross-Up Payments provided to the Employee shall be made not later than the tenth (10^th) business day following the last date the Payments are made; provided, however, that if the amounts of such payments cannot be finally determined on or before the due date of any Excise Tax return required as a result of the Payments, the Company shall pay to the Employee on or before thirty (30) days preceding the due date of the Excise Tax return, an estimate of the Payments due, as determined in good faith by the Employee and the Company, the estimate to be of the minimum amount of such payments to which the Employee is clearly entitled, and shall pay the remainder of such payments together with interest on the unpaid remainder (or on all such payments to the extent the Company fails to make such payments when due) at 120% of the rate provided in Section 1274(b)(2)(B) of the Code as soon as the amount thereof can be determined but in no event later than sixty (60) days after the date the Total Payments are made. In the event that the amount of the estimated payment exceeds the amount subsequently determined to have been due, such excess shall constitute a non-interest bearing loan by the Company to the Employee, payable on the tenth (10^th) business day after demand by the Company. At the time the payments are made under this Agreement, the Company shall provide the Employee with a written statement setting forth the manner in which such payments were calculated and the basis for such calculations, including, without limitations any opinions or other advice the Company has received from Tax Counsel or other advisors or consultants and any such opinions or advice which are in writing shall be attached to the statement.”

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6. Paragraph 6(l) shall be added to Agreement to read as follows:

“Notwithstanding the foregoing or anything herein to the contrary, if any amounts payable hereunder are reasonably determined by the Company to be “nonqualified deferred compensation” payable to a “specified employee” upon “separation from service” (within the meaning of section 409A of the Internal Revenue Code of 1986 as amended and any applicable regulations or other guidance issued pursuant thereto (the “Code”)) then such amounts shall not be paid upon separation from service, but shall be paid as described below. As soon as administratively feasible upon the Employee’s separation from service, or, if earlier, upon a Change of Control, the maximum amount which may become payable to Employee after separation from service shall be contributed to the trustee of the Trust. Such amounts that would otherwise be payable upon separation from service shall be held by the trustee pursuant to the terms of such Trust and paid to Employee as soon as administratively feasible following the earlier of: (1) the first day that is six months following his separation from service; or (2) Employee’s date of death. Such amounts that would otherwise be payable in installments commencing on separation from service shall be accumulated and paid in a lump sum on the date that is the earlier of (1) or (2) above and shall be paid in installments thereafter.”

7. Paragraph 12(a) of the Agreement shall be amended by deleting the reference to “6(c)(iii)” therein and substituting a reference to “6(c)(i)”.

IN WITNESS WHEREOF, the Company and the Employee have executed this First Amendment on the 10th day of February, 2006, effective for all purposes as provided above.

PLAINS EXPLORATION & PRODUCTION COMPANY
By:	/s/ John H. Lollar
	John H. Lollar
	Chairman, Organization & Compensation Committee of the Board of Directors
By:	/s/ John F. Wombwell
	John F. Wombwell
	Executive Vice President, General Counsel and Secretary
EMPLOYEE
/s/ James C. Flores
James C. Flores

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EX-10.26

Exhibit 10.26

PLAINS EXPLORATION & PRODUCTION COMPANY

FIRST AMENDMENT TO

EMPLOYMENT AGREEMENT

WHEREAS, effective as of June 9, 2004, Plains Exploration & Production Company (the “Company”) entered into an employment agreement (the “Agreement”) with Stephen A. Thorington (the “Employee”); and

WHEREAS, the Company and the Employee have agreed to amend the Agreement as set forth below;

NOW, THEREFORE, the Company and the Employee agree as follows:

1. Paragraph 4(b) of the Agreement shall be amended by adding the following sentence thereto:

“Such bonus, if any, shall be paid not later than the fifteenth day of the third calendar month following the later of (i) the last day of the calendar year or (ii) the last day of the Company’s fiscal year in which the calendar year ends.”

2. Paragraph 6(c)(ix) shall be added to the Agreement to read as follows:

“Notwithstanding the foregoing or anything herein to the contrary, if any amounts payable hereunder are reasonably determined by the Company to be “nonqualified deferred compensation” payable to a “specified employee” upon “separation from service” (within the meaning of section 409A of the Internal Revenue Code of 1986 as amended and any applicable regulations or other guidance issued pursuant thereto (the “Code”)) then such amounts shall not be paid upon separation from service, but shall be paid as described below. As soon as administratively feasible upon the Employee’s separation from service, or, if earlier, upon a Change of Control, the maximum amount which may become payable to Employee after separation from service shall be contributed to the trustee of a “rabbi” trust substantially in the form attached hereto (the “Trust”). Such amounts that would otherwise be payable upon separation from service shall be held by the trustee pursuant to the terms of such Trust and paid to Employee as soon as administratively feasible following the earlier of: (1) the first day that is six months following his separation from service; or (2) Employee’s date of death. Such amounts that would otherwise be payable in installments commencing on separation from service shall be accumulated and paid in a lump sum on the date that is the earlier of (1) or (2) above and shall be paid in installments thereafter.”

3. Paragraph 6(h) of the Agreement shall be amended to read as follows:

“(h) Full Tax Gross-Up of Excise Payments. In the event that any payment, award, benefit or distribution (or any acceleration of any payment, award, benefit or distribution) made or provided to or for the benefit of Employee in connection with this Agreement, or Employee’s employment with Company or the termination thereof (the “Payments”) is determined to be subject to the excise tax imposed by Section 4999 or 409A of the Code or any interest or penalties with respect to such excise taxes (such excise taxes, together with any such interest and penalties, are collectively referred to as the “Excise Taxes”), then the Employee shall be entitled to receive an additional payment (a “Gross-Up Payment”) from Company such that the net amount received by the Employee after paying any applicable Excise Taxes and any federal, state or local income or FICA taxes on such Gross-Up Payment, shall be equal to the amount Employee would have received if such Excise Taxes were not applicable to the Payments.

For purposes of determining whether any of the Payments will be subject to the Excise Taxes and the amount of such Excise Taxes, (i) all of the Payments shall be treated as “parachute payments” (within the meaning of Section 280G(b)(2) of the Code) unless, in the opinion of tax counsel (“Tax Counsel”) reasonably acceptable to the Employee, such payments or benefits (in whole or in part) do not constitute parachute payments, including by reason of Section 280G(b)(4)(A) of the Code; (ii) all “excess parachute payments” within the meaning of Section 280G(b)(1) of the Code shall be treated as subject to the Excise Tax unless, in the opinion of Tax Counsel, such excess parachute payments (in whole or in part) represent reasonable compensation for services actually rendered (within the meaning of Section 280G(b)(4)(B) of the Code) in excess of the base amount (as the term “base amount” is defined in Section 280G(b)(3) of the Code) allocable to such reasonable compensation, or are otherwise not subject to the Excise Tax; (iii) the value of any noncash benefits or any deferred payment or benefit shall be determined by the Tax Counsel in accordance with the principles of Sections 280G(d) and 409A of the Code; and (iv) all Payments shall be deemed subject to the Excise Tax pursuant to section 409A of the Code unless, in the opinion of Tax Counsel, such Payments are not subject to Excise Tax pursuant to section 409A. For purposes of determining the amount of the Additional Payment, the Employee shall be deemed to pay federal income tax at the highest marginal rate of federal income taxation in the calendar year in which the Total Payments are made and State and local income taxes at the highest marginal rate of taxation in the State and locality of the Employee’s residence on the date the Total Payments are made, net of the maximum reduction in federal income taxes which could be obtained from deduction of such State and local taxes.

In the event that the Excise Taxes are determined by the IRS, on audit or otherwise, to exceed the amount taken into account hereunder in calculating the Gross-Up Payment (including by reason of any payment the existence or amount of which cannot be determined at the time of the Gross-Up Payment), the

2

Company shall make another Gross-Up Payment in respect of such excess (plus any interest, penalties or additions payable by the Employee with respect to such excess) within the ten (10) business days immediately following the date that the amount of such excess is finally determined. The Employee and the Company shall each reasonably cooperate with the other in connection with any administrative or judicial proceedings concerning the existence or amount of liability for Excise Tax with respect to the Total Payments.

If a termination of the Employee’s employment shall have occurred, the Company shall promptly reimburse to the Employee all reasonable attorneys fees and expenses necessarily incurred by the Employee in disputing in good faith any issue with the Company or its affiliates pursuant to this Agreement or asserting in good faith any claim, demand or cause of action against the Company or its affiliates pursuant to this Agreement. Such payments shall be made within ten (10) business days after delivery of the Employee’s written requests for payment accompanied with such evidence of fees and expenses incurred as the Company reasonably may require.

The Gross-Up Payments provided to the Employee shall be made not later than the tenth (10^th) business day following the last date the Payments are made; provided, however, that if the amounts of such payments cannot be finally determined on or before the due date of any Excise Tax return required as a result of the Payments, the Company shall pay to the Employee on or before thirty (30) days preceding the due date of the Excise Tax return, an estimate of the Payments due, as determined in good faith by the Employee and the Company, the estimate to be of the minimum amount of such payments to which the Employee is clearly entitled, and shall pay the remainder of such payments together with interest on the unpaid remainder (or on all such payments to the extent the Company fails to make such payments when due) at 120% of the rate provided in Section 1274(b)(2)(B) of the Code as soon as the amount thereof can be determined but in no event later than sixty (60) days after the date the Total Payments are made. In the event that the amount of the estimated payment exceeds the amount subsequently determined to have been due, such excess shall constitute a non-interest bearing loan by the Company to the Employee, payable on the tenth (10^th) business day after demand by the Company. At the time the payments are made under this Agreement, the Company shall provide the Employee with a written statement setting forth the manner in which such payments were calculated and the basis for such calculations, including, without limitations any opinions or other advice the Company has received from Tax Counsel or other advisors or consultants and any such opinions or advice which are in writing shall be attached to the statement.”

3

IN WITNESS WHEREOF, the Company and the Employee have executed this First Amendment on the 10th day of February, 2006 effective for all purposes as provided above.

PLAINS EXPLORATION & PRODUCTION COMPANY
By:	/s/ James C. Flores
	James C. Flores
	Chief Executive Officer, President and Chairman of the Board
EMPLOYEE
Stephen A. Thorington
[type name]

4

EX-10.27

Exhibit 10.27

PLAINS EXPLORATION & PRODUCTION COMPANY

FIRST AMENDMENT TO

EMPLOYMENT AGREEMENT

WHEREAS, effective as of June 9, 2004, Plains Exploration & Production Company (the “Company”) entered into an employment agreement (the “Agreement”) with John F. Wombwell (the “Employee”); and

WHEREAS, the Company and the Employee have agreed to amend the Agreement as set forth below;

NOW, THEREFORE, the Company and the Employee agree as follows:

1. Paragraph 4(b) of the Agreement shall be amended by adding the following sentence thereto:

“Such bonus, if any, shall be paid not later than the fifteenth day of the third calendar month following the later of (i) the last day of the calendar year or (ii) the last day of the Company’s fiscal year in which the calendar year ends.”

2. Paragraph 6(c)(ix) shall be added to the Agreement to read as follows:

“Notwithstanding the foregoing or anything herein to the contrary, if any amounts payable hereunder are reasonably determined by the Company to be “nonqualified deferred compensation” payable to a “specified employee” upon “separation from service” (within the meaning of section 409A of the Internal Revenue Code of 1986 as amended and any applicable regulations or other guidance issued pursuant thereto (the “Code”)) then such amounts shall not be paid upon separation from service, but shall be paid as described below. As soon as administratively feasible upon the Employee’s separation from service, or, if earlier, upon a Change of Control, the maximum amount which may become payable to Employee after separation from service shall be contributed to the trustee of a “rabbi” trust substantially in the form attached hereto (the “Trust”). Such amounts that would otherwise be payable upon separation from service shall be held by the trustee pursuant to the terms of such Trust and paid to Employee as soon as administratively feasible following the earlier of: (1) the first day that is six months following his separation from service; or (2) Employee’s date of death. Such amounts that would otherwise be payable in installments commencing on separation from service shall be accumulated and paid in a lump sum on the date that is the earlier of (1) or (2) above and shall be paid in installments thereafter.”

3. Paragraph 6(h) of the Agreement shall be amended to read as follows:

“(h) Full Tax Gross-Up of Excise Payments. In the event that any payment, award, benefit or distribution (or any acceleration of any payment, award, benefit or distribution) made or provided to or for the benefit of Employee in connection with this Agreement, or Employee’s employment with Company or the termination thereof (the “Payments”) is determined to be subject to the excise tax imposed by Section 4999 or 409A of the Code or any interest or penalties with respect to such excise taxes (such excise taxes, together with any such interest and penalties, are collectively referred to as the “Excise Taxes”), then the Employee shall be entitled to receive an additional payment (a “Gross-Up Payment”) from Company such that the net amount received by the Employee after paying any applicable Excise Taxes and any federal, state or local income or FICA taxes on such Gross-Up Payment, shall be equal to the amount Employee would have received if such Excise Taxes were not applicable to the Payments.

For purposes of determining whether any of the Payments will be subject to the Excise Taxes and the amount of such Excise Taxes, (i) all of the Payments shall be treated as “parachute payments” (within the meaning of Section 280G(b)(2) of the Code) unless, in the opinion of tax counsel (“Tax Counsel”) reasonably acceptable to the Employee, such payments or benefits (in whole or in part) do not constitute parachute payments, including by reason of Section 280G(b)(4)(A) of the Code; (ii) all “excess parachute payments” within the meaning of Section 280G(b)(1) of the Code shall be treated as subject to the Excise Tax unless, in the opinion of Tax Counsel, such excess parachute payments (in whole or in part) represent reasonable compensation for services actually rendered (within the meaning of Section 280G(b)(4)(B) of the Code) in excess of the base amount (as the term “base amount” is defined in Section 280G(b)(3) of the Code) allocable to such reasonable compensation, or are otherwise not subject to the Excise Tax; (iii) the value of any noncash benefits or any deferred payment or benefit shall be determined by the Tax Counsel in accordance with the principles of Sections 280G(d) and 409A of the Code; and (iv) all Payments shall be deemed subject to the Excise Tax pursuant to section 409A of the Code unless, in the opinion of Tax Counsel, such Payments are not subject to Excise Tax pursuant to section 409A. For purposes of determining the amount of the Additional Payment, the Employee shall be deemed to pay federal income tax at the highest marginal rate of federal income taxation in the calendar year in which the Total Payments are made and State and local income taxes at the highest marginal rate of taxation in the State and locality of the Employee’s residence on the date the Total Payments are made, net of the maximum reduction in federal income taxes which could be obtained from deduction of such State and local taxes.

In the event that the Excise Taxes are determined by the IRS, on audit or otherwise, to exceed the amount taken into account hereunder in calculating the Gross-Up Payment (including by reason of any payment the existence or amount of which cannot be determined at the time of the Gross-Up Payment), the

2

Company shall make another Gross-Up Payment in respect of such excess (plus any interest, penalties or additions payable by the Employee with respect to such excess) within the ten (10) business days immediately following the date that the amount of such excess is finally determined. The Employee and the Company shall each reasonably cooperate with the other in connection with any administrative or judicial proceedings concerning the existence or amount of liability for Excise Tax with respect to the Total Payments.

If a termination of the Employee’s employment shall have occurred, the Company shall promptly reimburse to the Employee all reasonable attorneys fees and expenses necessarily incurred by the Employee in disputing in good faith any issue with the Company or its affiliates pursuant to this Agreement or asserting in good faith any claim, demand or cause of action against the Company or its affiliates pursuant to this Agreement. Such payments shall be made within ten (10) business days after delivery of the Employee’s written requests for payment accompanied with such evidence of fees and expenses incurred as the Company reasonably may require.

The Gross-Up Payments provided to the Employee shall be made not later than the tenth (10^th) business day following the last date the Payments are made; provided, however, that if the amounts of such payments cannot be finally determined on or before the due date of any Excise Tax return required as a result of the Payments, the Company shall pay to the Employee on or before thirty (30) days preceding the due date of the Excise Tax return, an estimate of the Payments due, as determined in good faith by the Employee and the Company, the estimate to be of the minimum amount of such payments to which the Employee is clearly entitled, and shall pay the remainder of such payments together with interest on the unpaid remainder (or on all such payments to the extent the Company fails to make such payments when due) at 120% of the rate provided in Section 1274(b)(2)(B) of the Code as soon as the amount thereof can be determined but in no event later than sixty (60) days after the date the Total Payments are made. In the event that the amount of the estimated payment exceeds the amount subsequently determined to have been due, such excess shall constitute a non-interest bearing loan by the Company to the Employee, payable on the tenth (10^th) business day after demand by the Company. At the time the payments are made under this Agreement, the Company shall provide the Employee with a written statement setting forth the manner in which such payments were calculated and the basis for such calculations, including, without limitations any opinions or other advice the Company has received from Tax Counsel or other advisors or consultants and any such opinions or advice which are in writing shall be attached to the statement.”

3

IN WITNESS WHEREOF, the Company and the Employee have executed this First Amendment on the 10th day of February, 2006 effective for all purposes as provided above.

PLAINS EXPLORATION & PRODUCTION COMPANY
By:	/s/ James C. Flores
	James C. Flores
	Chief Executive Officer, President and Chairman of the Board
EMPLOYEE
John F. Wombwell
[type name]

4

EX-10.28

Exhibit 10.28

PLAINS EXPLORATION & PRODUCTION COMPANY

FIRST AMENDMENT TO

EMPLOYMENT AGREEMENT

WHEREAS, effective as of June 9, 2004, Plains Exploration & Production Company (the “Company”) entered into an employment agreement (the “Agreement”) with Thomas M. Gladney (the “Employee”); and

WHEREAS, the Company and the Employee have agreed to amend the Agreement as set forth below;

NOW, THEREFORE, the Company and the Employee agree as follows:

1. Paragraph 4(b) of the Agreement shall be amended by adding the following sentence thereto:

“Such bonus, if any, shall be paid not later than the fifteenth day of the third calendar month following the later of (i) the last day of the calendar year or (ii) the last day of the Company’s fiscal year in which the calendar year ends.”

2. Paragraph 6(c)(ix) shall be added to the Agreement to read as follows:

“Notwithstanding the foregoing or anything herein to the contrary, if any amounts payable hereunder are reasonably determined by the Company to be “nonqualified deferred compensation” payable to a “specified employee” upon “separation from service” (within the meaning of section 409A of the Internal Revenue Code of 1986 as amended and any applicable regulations or other guidance issued pursuant thereto (the “Code”)) then such amounts shall not be paid upon separation from service, but shall be paid as described below. As soon as administratively feasible upon the Employee’s separation from service, or, if earlier, upon a Change of Control, the maximum amount which may become payable to Employee after separation from service shall be contributed to the trustee of a “rabbi” trust substantially in the form attached hereto (the “Trust”). Such amounts that would otherwise be payable upon separation from service shall be held by the trustee pursuant to the terms of such Trust and paid to Employee as soon as administratively feasible following the earlier of: (1) the first day that is six months following his separation from service; or (2) Employee’s date of death. Such amounts that would otherwise be payable in installments commencing on separation from service shall be accumulated and paid in a lump sum on the date that is the earlier of (1) or (2) above and shall be paid in installments thereafter.”

3. Paragraph 6(h) of the Agreement shall be amended to read as follows:

“(h) Full Tax Gross-Up of Excise Payments. In the event that any payment, award, benefit or distribution (or any acceleration of any payment, award, benefit or distribution) made or provided to or for the benefit of Employee in connection with this Agreement, or Employee’s employment with Company or the termination thereof (the “Payments”) is determined to be subject to the excise tax imposed by Section 4999 or 409A of the Code or any interest or penalties with respect to such excise taxes (such excise taxes, together with any such interest and penalties, are collectively referred to as the “Excise Taxes”), then the Employee shall be entitled to receive an additional payment (a “Gross-Up Payment”) from Company such that the net amount received by the Employee after paying any applicable Excise Taxes and any federal, state or local income or FICA taxes on such Gross-Up Payment, shall be equal to the amount Employee would have received if such Excise Taxes were not applicable to the Payments.

For purposes of determining whether any of the Payments will be subject to the Excise Taxes and the amount of such Excise Taxes, (i) all of the Payments shall be treated as “parachute payments” (within the meaning of Section 280G(b)(2) of the Code) unless, in the opinion of tax counsel (“Tax Counsel”) reasonably acceptable to the Employee, such payments or benefits (in whole or in part) do not constitute parachute payments, including by reason of Section 280G(b)(4)(A) of the Code; (ii) all “excess parachute payments” within the meaning of Section 280G(b)(1) of the Code shall be treated as subject to the Excise Tax unless, in the opinion of Tax Counsel, such excess parachute payments (in whole or in part) represent reasonable compensation for services actually rendered (within the meaning of Section 280G(b)(4)(B) of the Code) in excess of the base amount (as the term “base amount” is defined in Section 280G(b)(3) of the Code) allocable to such reasonable compensation, or are otherwise not subject to the Excise Tax; (iii) the value of any noncash benefits or any deferred payment or benefit shall be determined by the Tax Counsel in accordance with the principles of Sections 280G(d) and 409A of the Code; and (iv) all Payments shall be deemed subject to the Excise Tax pursuant to section 409A of the Code unless, in the opinion of Tax Counsel, such Payments are not subject to Excise Tax pursuant to section 409A. For purposes of determining the amount of the Additional Payment, the Employee shall be deemed to pay federal income tax at the highest marginal rate of federal income taxation in the calendar year in which the Total Payments are made and State and local income taxes at the highest marginal rate of taxation in the State and locality of the Employee’s residence on the date the Total Payments are made, net of the maximum reduction in federal income taxes which could be obtained from deduction of such State and local taxes.

In the event that the Excise Taxes are determined by the IRS, on audit or otherwise, to exceed the amount taken into account hereunder in calculating the Gross-Up Payment (including by reason of any payment the existence or amount of which cannot be determined at the time of the Gross-Up Payment), the

2

Company shall make another Gross-Up Payment in respect of such excess (plus any interest, penalties or additions payable by the Employee with respect to such excess) within the ten (10) business days immediately following the date that the amount of such excess is finally determined. The Employee and the Company shall each reasonably cooperate with the other in connection with any administrative or judicial proceedings concerning the existence or amount of liability for Excise Tax with respect to the Total Payments.

If a termination of the Employee’s employment shall have occurred, the Company shall promptly reimburse to the Employee all reasonable attorneys fees and expenses necessarily incurred by the Employee in disputing in good faith any issue with the Company or its affiliates pursuant to this Agreement or asserting in good faith any claim, demand or cause of action against the Company or its affiliates pursuant to this Agreement. Such payments shall be made within ten (10) business days after delivery of the Employee’s written requests for payment accompanied with such evidence of fees and expenses incurred as the Company reasonably may require.

The Gross-Up Payments provided to the Employee shall be made not later than the tenth (10^th) business day following the last date the Payments are made; provided, however, that if the amounts of such payments cannot be finally determined on or before the due date of any Excise Tax return required as a result of the Payments, the Company shall pay to the Employee on or before thirty (30) days preceding the due date of the Excise Tax return, an estimate of the Payments due, as determined in good faith by the Employee and the Company, the estimate to be of the minimum amount of such payments to which the Employee is clearly entitled, and shall pay the remainder of such payments together with interest on the unpaid remainder (or on all such payments to the extent the Company fails to make such payments when due) at 120% of the rate provided in Section 1274(b)(2)(B) of the Code as soon as the amount thereof can be determined but in no event later than sixty (60) days after the date the Total Payments are made. In the event that the amount of the estimated payment exceeds the amount subsequently determined to have been due, such excess shall constitute a non-interest bearing loan by the Company to the Employee, payable on the tenth (10^th) business day after demand by the Company. At the time the payments are made under this Agreement, the Company shall provide the Employee with a written statement setting forth the manner in which such payments were calculated and the basis for such calculations, including, without limitations any opinions or other advice the Company has received from Tax Counsel or other advisors or consultants and any such opinions or advice which are in writing shall be attached to the statement.”

3

IN WITNESS WHEREOF, the Company and the Employee have executed this First Amendment on the 10th day of February, 2006 effective for all purposes as provided above.

PLAINS EXPLORATION & PRODUCTION COMPANY
By:	/s/ James C. Flores
	James C. Flores
	Chief Executive Officer, President and Chairman of the Board
EMPLOYEE
Thomas M. Gladney
[type name]

4

EX-21.1

Exhibit 21.1

Subsidiaries of Plains Exploration & Production Company

Name of Subsidiary	Jurisdiction of Organization
Arguello Inc.	Delaware	76-0608465
Nuevo Ghana Inc.	Delaware	76-0527372
Nuevo International Inc.	Delaware	76-0577836
Nuevo Offshore Company	Delaware	01-0628961
Nuevo Resources Inc.	Delaware	75-2778316
Pacific Interstate Offshore Company	California	95-3685016
Plains Resources International Inc.	Delaware	76-0040974
PXP Gulf Coast Inc.	Delaware	01-0770800
Plains Louisiana Inc.	Delaware	20-2076470
PXP Louisiana L.L.C.	Delaware	20-2076518
PXP Permian Inc.	Delaware	91-2116322
PXP Texas Inc.	Delaware	75-2744301
Montebello Land Company LLC	Delaware	20-3846207
Lompoc Land Company LLC	Delaware	20-3918482
Arroyo Grande Land Company LLC	Delaware	20-3918402
Cane River Development Company LLC	Delaware	20-3918568
PXP Texas Limited Partnership	Texas	75-2836792
Brown PXP Properties, LLC	Texas	20-2531587

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (No. 333-102627, No. 333-107990, No. 333-115628 and No. 333-117425) and on Form S-3 (No. 333-112027) of Plains Exploration & Production Company of our report dated March 9, 2006 relating to the financial statements, management’s assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Houston, TX

March 9, 2006

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the references in this Form 10-K of Plains Exploration & Production Company, as well as in the Notes to the Consolidated Financial Statements included in such Form 10-K, to our reserve reports to the interest of Plains Exploration & Production Company and its subsidiaries (collectively the “Company”), relating to the estimated quantities of certain of the Company’s proved reserves of oil and gas and present values thereof for certain periods. We also consent to the incorporation by reference of such reports in the Registration Statements on Form S-8 (No. 333-102627, No. 333-107990, No. 333-115628 and No. 333-117425) and Form S-3 (No. 333-112027) of Plains Exploration & Production Company.

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/ David B. Cox
	David B. Cox, P.E. Senior Vice President

Houston, Texas

March 6, 2006

EX-23.3

EXHIBIT NO. 23.3

[RYDER SCOTT COMPANY LETTERHEAD]

CONSENT OF RYDER SCOTT COMPANY, L.P.

As independent oil and gas consultants, Ryder Scott Company, L.P. hereby consents to the incorporation by reference in this Annual Report on Form 10-K of Plains Exploration & Production Company, as well as in the Notes to the Consolidated Financial Statements included in such Form 10-K, of information from our reserve reports for Plains Exploration & Production Company and subsidiaries (collectively, the Company), as of December 31, 2003, relating to the estimated quantities of certain of the Company’s proved reserves of oil and gas and undiscounted and discounted future net income therefrom for the specific periods cited. We further consent to references to our firm under the headings “Oil and Gas Reserves” and “Supplemental reserve information (unaudited)”.

We also consent to the incorporation by reference of such reports in the Registration Statements on Form S-8 (No. 333-102627, No. 333-107990, No. 333-115628 and No. 333-117425) and Form S-3 (No. 333-112027) of Plains Exploration & Production Company.

/S/ RYDER SCOTT COMPANY, L.P.

RYDER SCOTT COMPANY, L.P.

Houston, Texas

March 6, 2006

EX-31.1

Exhibit 31.1

CERTIFICATION

I, James C. Flores, Chairman of the Board, President and Chief Executive Officer of Plains Exploration & Production Company, certify that:

1. I have reviewed this annual report on Form 10-K of Plains Exploration & Production Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c. evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and

d. disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a. all significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

/s/ James C. Flores
Name:	James C. Flores
Title:	Chairman of the Board, President and Chief Executive Officer

Date: March 9, 2006

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Stephen A. Thorington, Executive Vice President and Chief Financial Officer of Plains Exploration & Production Company, certify that:

1. I have reviewed this annual report on Form 10-K of Plains Exploration & Production Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c. evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and

d. disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a. all significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

/s/ Stephen A. Thorington
Name:	Stephen A. Thorington
Title:	Executive Vice President and Chief Financial Officer

Date: March 9, 2006

EX-32.1

Exhibit 32.1

SECTION 906 CERTIFICATION—CEO

In connection with the Annual Report of Plains Exploration & Production Company (the ”Company”) on Form 10-K for the period ending December 31, 2005 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, James C. Flores, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

To the best of my knowledge, after reasonable investigation:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

Dated: March 9, 2006.

/s/ James C. Flores

James C. Flores

Chief Executive Officer

The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

SECTION 906 CERTIFICATION—CFO

In connection with the Annual Report of Exploration & Production Company (the ”Company”) on Form 10-K for the period ending December 31, 2005 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Stephen A. Thorington, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

To the best of my knowledge, after reasonable investigation:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

Dated: March 9, 2006.

/s/ Stephen A. Thorington

Stephen A. Thorington

Chief Financial Officer

The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.