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, 2012

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 whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    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, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

þ   Large accelerated filer    ¨  Accelerated filer    ¨  Non-accelerated filer (Do not check if a smaller reporting company)    ¨  Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).    Yes  ¨    No  þ

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 $4.5 billion on June 29, 2012 (based on $35.18 per share, the last sale price of the Common Stock as reported on the New York Stock Exchange on such date). On January 31, 2013, there were 129.0 million shares of the registrant’s Common Stock outstanding.

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 2013 Annual Meeting of Stockholders or, in the event we do not prepare and file such proxy statement, such information shall be filed as an amendment to this Form 10-K. Such information will be filed no later than April 30, 2013.

PLAINS EXPLORATION & PRODUCTION COMPANY

2012 ANNUAL REPORT ON FORM 10-K

Table of Contents

	Part I
Items 1 and 2.	Business and Properties	9
Item 1A.	Risk Factors	34
Item 1B.	Unresolved Staff Comments	51
Item 3.	Legal Proceedings	51
Item 4.	Mine Safety Disclosures	52
	Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	53
Item 6.	Selected Financial Data	54
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	56
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	82
Item 8.	Financial Statements and Supplementary Data	86
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	86
Item 9A.	Controls and Procedures	87
Item 9B.	Other Information	88
	Part III
Item 10.	Directors, Executive Officers and Corporate Governance	89
Item 11.	Executive Compensation	91
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	91
Item 13.	Certain Relationships and Related Transactions, and Director Independence	91
Item 14.	Principal Accounting Fees and Services	91
	Part IV
Item 15.	Exhibits, Financial Statement Schedules	92

1

Statement Regarding Forward-Looking Statements

This Annual Report on Form 10-K includes forward-looking information regarding Plains Exploration & Production Company (“PXP”, the “Company”, “us”, “our” or “we”) 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:

• a condition to the closing of our merger with a subsidiary of Freeport-McMoRan Copper & Gold Inc., or Freeport-McMoRan, may not be satisfied;

• a regulatory approval required for the merger may not be obtained or may be obtained subject to conditions that are not anticipated;

• the integration of our business and operations with those of Freeport-McMoRan may take longer than anticipated, may be more costly than anticipated and may have unanticipated adverse results relating to our existing business or the combined company’s business;

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

• unexpected difficulties in integrating our operations as a result of any significant acquisitions, including our recent acquisition of certain deepwater Gulf of Mexico properties, which we refer to as the Gulf of Mexico Acquisition;

• the impact of hurricanes and other weather conditions on our offshore operations;

• the impact of the lack of physical and oilfield service infrastructure in deeper waters on our ability to bring production online;

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

• the impact of oil and gas price fluctuations, including the impact on our reserve volumes and values and on our earnings;

• 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;

• the effects of competition;

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

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• the availability (or lack thereof) of capital to fund our business strategy and/or operations;

• the impact of current and future laws and governmental regulations, including those related to climate change and hydraulic fracturing;

• the effects of future laws and governmental regulation that result from the Macondo accident and oil spill in the U.S. Gulf of Mexico;

• the value of the common stock of McMoRan Exploration Co., or McMoRan, and our ability to dispose of those shares if the merger between Freeport-McMoRan and McMoRan doesn’t occur;

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

• the ability and willingness of our current or potential counterparties to fulfill their obligations to us or to enter into transactions with us in the future; 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. We do not intend to update these forward-looking statements and information except as required by law. See Item 1A – Risk Factors and Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates 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. 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, www.pxp.com. 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. We intend to post amendments to and waivers of our Policy Concerning Corporate Ethics and Conflicts of Interest (to the extent applicable to our directors, principal executive officer, principal financial officer, principal accounting officer and other executive officers) on our website. 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 or the SEC’s website is incorporated by reference in this Annual Report.

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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:

Analogous reservoir.    Analogous reservoirs, as used in resource assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, analogous reservoir refers to a reservoir that shares all of the following characteristics with the reservoir of interest: (i) the same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) the same environment of deposition; (iii) similar geologic structure; and (iv) the same drive mechanism.

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.

Bcf.    One billion cubic feet of gas.

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.

BOPD.    Barrels of oil per day.

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

Deterministic estimate.    The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering or economic data) in the reserves calculation is used in the reserves estimation procedure.

Developed oil and gas reserves.    Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Development project.    A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

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.

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Economically producible.    The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities.

Estimated ultimate recovery.    Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

Exploratory well.    A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well.

Extension well.    An extension well is a well drilled to extend the limits of a known reservoir.

Gas.    Natural gas.

ICE.    IntercontinentalExchange.

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

MBOE.    One thousand BOE.

Mcf.    One thousand cubic feet of gas.

MMcfe.    One million cubic feet of gas equivalent.

MMBOE.    One million BOE.

MMBtu.    One million British thermal units.

MMcf.    One million cubic feet of gas.

NYMEX.    New York Mercantile Exchange.

Oil.    Crude oil, condensate and natural gas liquids.

Operator.    The individual or company responsible for the exploration and/or production of an oil or gas well or lease.

Play.    A geographic area with hydrocarbon potential.

Probabilistic estimate.    The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrences.

Probable reserves.    Probable oil and gas reserves are those quantities of oil and gas that are less certain to be recovered than proved reserves, but which, together with proved reserves, are as likely as not to be recovered.

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When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

The proved plus probable reserves estimate must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

Where direct observation has defined a highest known oil, or HKO, elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable oil or gas based on reservoir fluid properties and pressure gradient interpretations.

Proved oil and gas reserves.    Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.

The area of the reservoir considered as proved includes all of the following: (i) the area identified by drilling and limited by fluid contacts, if any; and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil and gas on the basis of available geoscience and engineering data.

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty.

Where direct observation from well penetrations has defined a HKO elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

6

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

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

Reasonable certainty.    If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical and geochemical), engineering and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

Reliable technology.    Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Reserves.    Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

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. In our calculation of reserve life, production volumes are based on annualized fourth quarter production and are adjusted, if necessary, to reflect property acquisitions and dispositions.

Resources.    Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.

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Royalty interest.    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 used in estimating proved oil and gas reserves to the year-end quantities of those reserves in effect as of the dates of such estimates and held constant throughout the productive life of the reserves (except for consideration of future price changes to the extent provided by contractual arrangements in existence at year-end), and deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on year-end costs and assuming continuation of existing economic conditions). Future income taxes are calculated by applying the appropriate year-end statutory federal and state income tax rate, with consideration of future tax rates already legislated, to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to proved oil and gas reserves.

Undeveloped oil and gas reserves.    Undeveloped oil and gas reserves are reserves of any category 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 directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for 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 projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Upstream.    The portion of the oil and gas industry focused on acquiring, 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 “analogous reservoir”, “deterministic estimate”, “developed oil and gas reserves”, “development project”, “development well”, “economically producible”, “estimated ultimate recovery”, “exploratory well”, “probabilistic estimate”, “probable reserves”, “proved oil and gas reserves”, “reasonable certainty”, “reliable technology”, “reserves”, “resources” and “undeveloped oil and gas reserves” are defined by the SEC.

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PART I

Items 1 and 2.  Business and Properties

General

Plains Exploration & Production Company, a Delaware corporation formed in 2002, is an independent energy company engaged in the upstream oil and gas business. The upstream business acquires, develops, explores for and produces oil and gas. Our upstream activities are located in the United States. We own oil and gas properties with principal operations in:

• Onshore California;

• Offshore California;

• the Gulf of Mexico;

• the Gulf Coast Region; and

• the Rocky Mountains.

Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities, as well as newer properties with development and exploration potential. We believe our balanced portfolio of assets and our ongoing risk management program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities, including the Eagle Ford Shale, Gulf of Mexico, California and the Haynesville Shale.

On December 5, 2012, the Company entered into an Agreement and Plan of Merger, or the Freeport-McMoRan Merger Agreement, with Freeport-McMoRan and IMONC LLC, a wholly owned subsidiary of Freeport-McMoRan, or the Merger Sub, pursuant to which we will merge with and into the Merger Sub with the Merger Sub continuing as the surviving company and a wholly owned subsidiary of Freeport-McMoRan. See Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Recent Developments.

Oil and Gas Reserves

As of December 31, 2012, we had estimated proved reserves of 440.4 million barrels of oil equivalent of which 82% was comprised of oil and 63% was proved developed. We have a total proved reserve life of approximately seven years and a proved developed reserve life of approximately four years. As of December 31, 2012, and based on the twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials, our proved reserves had a standardized measure of $10.0 billion. As of December 31, 2012, we had estimated probable reserves of 193.8 million barrels of oil equivalent of which 89% was comprised of oil and 20% was probable developed. We believe our long-lived, low production decline reserve base, combined with our active risk management program, should provide us with relatively stable and recurring cash flow. Unless otherwise indicated, any reference to reserves is to PXP reserves and excludes our share of McMoRan reserves.

The following table sets forth certain information with respect to our proved and probable reserves that for 2012 are based upon (1) reserve reports prepared by the independent petroleum engineers of Netherland, Sewell & Associates, Inc., or NSA, (100% of proved reserve volumes and 99% of probable

9

reserve volumes) and (2) reserve volumes prepared by us, which were not audited by an independent petroleum engineer (1% of probable reserve volumes). In 2011, our proved and probable reserves were based upon (1) reserve reports prepared by the independent petroleum engineers of NSA (95% of proved reserve volumes and 40% of probable reserve volumes) and (2) reserve volumes prepared by us, which were not audited by an independent petroleum engineer (5% of proved reserve volumes and 60% of probable reserve volumes). In 2010, our proved reserves were based upon (1) reserve reports prepared by the independent petroleum engineers of NSA and Ryder Scott Company L.P., or Ryder Scott, (99% of proved reserve volumes) and (2) reserve volumes prepared by us, which were not audited by an independent petroleum engineer (1% of proved reserve volumes). The reserve volumes and values were determined using the methods prescribed by the SEC, which require the use of an average price, calculated as the twelve-month average of the first-day-of-the-month reference price as adjusted for location and quality differentials, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

We and our independent petroleum engineers used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. Our reserves have been estimated using deterministic methods. Standard engineering and geoscience methods were used, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we and our independent petroleum engineers considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for undeveloped locations; such reserves are based on estimates of reserve volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

	As of December 31,
	2012		2011		2010
Oil and Gas Proved Reserves
Consolidated entities
Oil (MBbls)
Proved developed		213,169		151,480		150,492
Proved undeveloped		149,262		92,550		72,776
		362,431		244,030		223,268
Gas (MMcf)
Proved developed		388,008		454,248		517,183
Proved undeveloped		80,017		547,063		639,887
		468,025		1,001,311		1,157,070
MBOE		440,435		410,915		416,113
Entity’s share of equity investee (1)
Oil (MBbls)
Proved developed		3,957		4,921		4,315
Proved undeveloped		449		542		401
		4,406		5,463		4,716
Gas (MMcf)
Proved developed		31,417		39,066		46,974
Proved undeveloped		11,402		8,982		15,394
		42,819		48,048		62,368
MBOE		11,542		13,471		15,111

Table continued on following page.

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	As of December 31,
	2012		2011		2010
Oil and Gas Probable Reserves (2)
Consolidated entities
Oil (MBbls)
Probable developed (3)		34,295		2,841
Probable undeveloped		138,821		106,685
		173,116		109,526
Gas (MMcf)
Probable developed (3)		27,557		14,593
Probable undeveloped		96,254		1,080,967
		123,811		1,095,560
MBOE		193,751		292,119
Standardized Measure (in thousands)
Consolidated entities (4)	$	10,024,450	$	5,134,181	$	3,093,135
Entity’s share of equity investee (1)	$	167,048	$	261,911	$	210,898
Average Realized Price (5)
Oil (per Bbl)	$	103.06	$	104.59	$	72.83
Gas (per Mcf)	$	2.71	$	4.08	$	4.29
Reference Price (6)
Oil (per Bbl)	$	94.71	$	95.99	$	79.43
Henry Hub Gas (per MMBtu)	$	2.76	$	4.12	$	4.38
Reserve Life (years)		7.0		12.2		13.0

(1) Amounts relate to our equity investment in McMoRan acquired on December 30, 2010.

(2) We began reporting probable reserves in 2011.

(3) Reflects reserves associated with incremental recovery from existing production/injection wells that require no future development costs and reserves associated with work performed on existing producers/injectors that do not meet the reasonable certainty requirements to be classified as proved.

(4) Our year-end 2012 standardized measure includes future development costs related to proved undeveloped reserves of $861 million, $723 million and $266 million in 2013, 2014 and 2015, respectively.

(5) Reflects the average realized price in our reserve reports based on the twelve-month average of the first-day-of-the-month reference prices, in each case adjusted for location and quality differentials. Historically, the market price for California crude oil differs from the established market indices in the United States due principally to the higher transportation and refining costs associated with heavy oil. The market price for California crude oil has strengthened relative to NYMEX and West Texas Intermediate, or WTI, primarily due to world demand and declining domestic supplies of both Alaskan and California crude oil.

(6) Reflects the twelve-month average of the first-day-of-the-month reference prices. Our reference prices are the WTI spot price for oil and the Henry Hub spot price for gas.

The increase in proved reserves in 2012 was primarily due to higher oil reserves as a result of the Gulf of Mexico Acquisition from BP Exploration & Production Inc. and BP America Production Company, or BP, and Shell Offshore, Inc., or Shell, and increased reserves in the Eagle Ford Shale, partially offset by lower gas reserves primarily in the Haynesville Shale due to persistent low natural gas prices. Additionally, we had a total of 59 MMBOE of extensions and discoveries, including 42 MMBOE in the Eagle Ford Shale resulting from continued successful drilling during 2012 that extended and developed our proved acreage and 10 MMBOE in the deepwater Gulf of Mexico resulting from successful appraisal drilling in the Lucius oil field. The decrease in probable reserves in 2012 was primarily due to lower probable gas reserves in the Haynesville Shale due to continued persistent low natural gas prices, partially offset by higher probable oil reserves as a result of the Gulf of Mexico Acquisition and continued development of the Eagle Ford Shale.

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In 2011, we had a total of 75 MMBOE of extensions and discoveries, including 25 MMBOE in the Haynesville Shale and 22 MMBOE in the Eagle Ford Shale resulting from successful drilling during 2011 that extended and developed our proved acreage and 19 MMBOE in the Gulf of Mexico resulting from the sanctioning of the Lucius project. The divestment of our Panhandle and South Texas properties resulted in a 48 MMBOE reduction. With persistent low natural gas prices and a corresponding assumed reduction in the pace of development in the Haynesville Shale, we classified 44 MMBOE of our Haynesville Shale undeveloped reserves as probable undeveloped. These reserves met the reasonable certainty, economic and other conditions needed to be classified as proved undeveloped reserves but the slower pace of drilling extended the development of these reserves past five years.

During the three-year period ended December 31, 2012, we participated in 1,027 exploratory wells, of which 1,017 were successful, and 515 development wells, of which 512 were successful. During this period, we incurred aggregate oil and gas acquisition, exploration and development costs of $11.8 billion, approximately 75.0% of which was for acquisition and development activities. During this period, proved reserve additions from acquisitions, extensions and discoveries totaled 343 MMBOE.

Approximately 89% of our proved undeveloped reserves are scheduled for development within five years and approximately 86%, or $2.5 billion, of our future estimated capital to develop proved undeveloped reserves is associated with those reserves. The only exceptions are due to five planned sidetrack development wells in certain deepwater Gulf of Mexico properties that cannot be executed until the current producing well depletes. As of December 31, 2012, we had proved undeveloped reserves of 163 MMBOE, a net decrease of 21 MMBOE relative to December 31, 2011. The decrease in proved undeveloped reserves resulted primarily from reductions in the Haynesville Shale, where we no longer classify reserves as proved undeveloped due to persistent low natural gas prices, partially offset by increased proved undeveloped reserves in the Gulf of Mexico and Eagle Ford Shale. During 2012, we invested $467.1 million and converted 16 MMBOE, or 9% of our year-end 2011 proved undeveloped reserve balance, to proved developed. The pace of development continued to be heavily influenced by the large number of unproved locations that were drilled on our Eagle Ford Shale acreage in order to capture our significant leasehold on a held by production basis.

There are numerous uncertainties inherent in estimating quantities and values of proved reserves, and in projecting future rates of production and timing of development expenditures. Many of the factors that impact these estimates are beyond our control. Reservoir engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner and the accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Because all reserve estimates are to some degree subjective, 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 an estimate only and should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties.

Probable reserves are additional reserves that are less certain to be recovered than proved reserves, but which, together with proved reserves, are as likely as not to be recovered. In addition to the uncertainties inherent in estimating quantities and values of proved reserves, probable reserves may be assigned to areas where data control or interpretations of available data are less certain and are structurally higher than proved reserves if they are adjacent to the proved reservoirs. See Item 1A – Risk Factors – 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.

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Undeveloped reserves that meet the reasonable certainty, economic and other requirements to be classified as proved undeveloped, except that they are not expected to be developed within five years, are classified as probable reserves. In 2011, 44 MMBOE of our Haynesville Shale undeveloped reserves were classified as probable because they related to undeveloped locations that were expected to be developed beyond five years but otherwise met the requirements to be classified as proved undeveloped reserves.

The reserve documentation and calculations for substantially all of our reserves are reviewed both by our internal engineers and, where noted, by independent third party engineers each year. During this process, all performance projections are updated and revised where appropriate, all new well control and petrophysical data acquired is incorporated into our estimated ultimate recovery and remaining reserve calculations and the remaining proved reserves are redistributed among proved developed and proved undeveloped categories where appropriate. This ensures forecasts of proved undeveloped reserves represent incremental capture and not acceleration.

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 the twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials 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. The reserve estimates exclude the effect of any derivative instruments we have in place. The prices for oil and gas have historically been volatile and are likely to continue to be volatile in the future.

Internal Control

Our corporate reservoir engineering department reports to the Vice President of Engineering who maintains oversight and compliance responsibility for the internal reserve estimate process and provides appropriate data to independent third party engineers for the annual estimation of our year-end reserves. The management of our corporate reservoir engineering department, including the Vice President of Engineering, consists of three degreed petroleum engineers, with between 23 and 36 years of industry experience, between 13 and 36 years of reservoir engineering/management experience, and between seven and 11 years of experience managing our reserves. All are members of the Society of Petroleum Engineers.

Qualifications of Third Party Engineers

The technical personnel responsible for preparing the reserve estimates at NSA meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. NSA is an independent firm of petroleum engineers, geologists, geophysicists, and petrophysicists; it does not own an interest in our properties and is not employed on a contingent fee basis.

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.

Gulf of Mexico

During the fourth quarter of 2012, we completed the acquisition of certain oil and gas interests in and near the Holstein, Diana, Hoover, Horn Mountain, Marlin, Dorado, King and Ram Powell Fields

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located in the Gulf of Mexico from BP, subject to customary post-closing adjustments. After pre-closing adjustments from the effective date of October 1, 2012, which resulted in a reduction to the $5.55 billion purchase price of approximately $191.0 million, we paid $5.36 billion in cash, which included the deposit of $555.0 million previously paid to BP.

During the fourth quarter of 2012, we also completed the acquisition of the 50% working interest in the Holstein Field located in the Gulf of Mexico from Shell, subject to customary post-closing adjustments. After pre-closing adjustments from the effective date of October 1, 2012, which resulted in a reduction to the $560.0 million purchase price of approximately $27.9 million, we paid $532.1 million in cash.

Eagle Ford Shale

During the fourth quarter of 2010, we completed the acquisition of approximately 60,000 net acres in the Eagle Ford Shale oil and gas condensate windows in South Texas for approximately $596.3 million in cash.

Divestments

Panhandle and South Texas Properties

In December 2011, we divested our Texas Panhandle properties to Linn Energy, LLC. After the exercise of third party preferential rights and preliminary closing adjustments, we received approximately $554.8 million in cash. The cash proceeds received, net of approximately $6.2 million in transaction costs, were primarily used to reduce indebtedness. Our aggregate working interest in the Texas Panhandle properties generated total sales volumes of approximately 84 MMcfe per day during the third quarter of 2011 and had 263 Bcfe of estimated proved reserves as of December 31, 2010. Additionally, during the first quarter of 2012, we completed the divestment of our interests in approximately 2,000 gross leasehold acres in our Texas Panhandle properties to Linn Energy, LLC. After the exercise of third party preferential rights and closing adjustments, we received approximately $43.4 million in cash. The Texas Panhandle divestment was effective November 1, 2011.

At December 31, 2012, we continue to have interests in approximately 40,000 gross leasehold acres in the Texas Panhandle. We expect to receive additional proceeds from future closings, as may be further modified for additional post-closing adjustments.

In December 2011, we completed the divestment of all our working interests in our South Texas conventional natural gas properties to a third party. After preliminary closing adjustments, we received $181.0 million in cash. The cash proceeds received were primarily used to reduce indebtedness. The transaction was effective September 1, 2011.

The proceeds from the 2012 and 2011 sales of oil and gas properties were recorded as reductions to capitalized costs pursuant to full cost accounting rules.

Gulf of Mexico

In December 2010, we completed the divestment of our Gulf of Mexico shallow water shelf properties to McMoRan. At closing and after preliminary closing adjustments, we received approximately $86.1 million in cash, which included $11.1 million in working capital adjustments, and 51.0 million shares of McMoRan common stock in exchange for all our interests in our Gulf of Mexico leasehold located in less than 500 feet of water. The transaction was completed pursuant to an Agreement and Plan of Merger dated as of September 19, 2010, and effective as of August 1, 2010, between us and certain of our subsidiaries and McMoRan and certain of its subsidiaries. The

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McMoRan shares were valued at approximately $665.9 million based on McMoRan’s closing stock price of $17.18 on December 30, 2010 discounted to reflect certain limitations on the marketability of the McMoRan shares under the registration rights agreement and stockholder agreement entered into by us and McMoRan at the closing of the transaction. The cash proceeds received, net of approximately $8.8 million in transaction costs, were primarily used to repay outstanding borrowings under our credit facilities. The proceeds were recorded as reductions to capitalized costs pursuant to full cost accounting rules.

Development and Exploration

We expect to continue growing reserves and production through the long-term development of our existing project inventory in each of our primary operating areas in the Eagle Ford Shale, Gulf of Mexico and California and by developing future exploration successes primarily in the Gulf of Mexico. To implement our development and exploration plan, we will focus on:

• allocating investment capital prudently after rigorous evaluation to projects with the best economic returns;

• optimizing production practices;

• reducing drilling and production costs;

• 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 development and exploration plan, we seek to add to our proved reserves and thereby increase cash flows and enhance the value of our asset base. During the three-year period ended December 31, 2012, our additions to proved reserves from extensions and discoveries totaled 211 MMBOE. During this period, we incurred aggregate oil and gas development and exploration costs of $4.8 billion.

Our 2013 capital budget is expected to be approximately $2.1 billion, including capitalized interest and general and administrative expenses. We intend to fund our capital budget from internally generated funds and borrowings under our revolving line of credit, with the portion of our budget related to Plains Offshore Operations Inc., or Plains Offshore, being funded with cash on hand and the Plains Offshore senior credit facility. In addition, because approximately 80% of our 2013 capital budget is allocated to properties we operate, we could curtail the portion of our capital expenditures that is discretionary if our cash flows decline from expected levels.

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Description of Properties

Our oil and gas operations are concentrated in onshore California, offshore California, the Gulf of Mexico, the Gulf Coast Region and the Rocky Mountains. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities, as well as newer properties with development and exploration potential.

Our capital investments are allocated to asset areas with the greatest expected returns and highest growth prospects. These investments support a diversified growth strategy with sustained development of our properties in the Eagle Ford Shale, the Gulf of Mexico and California. Also, we have continued exploration primarily in the Gulf of Mexico. Capital additions to our oil and gas properties were $1.9 billion in 2012.

The following table sets forth information with respect to our proved and probable oil and gas reserves as of December 31, 2012:

	As of December 31, 2012
	Proved Reserves						Probable Reserves
	Proved Developed		Proved Undeveloped		Total Proved		Probable Developed (1)		Probable Undeveloped		Total Probable
	(MMBOE)
Consolidated entities
Onshore California		116.4		61.8		178.2		3.3		85.3		88.6
Offshore California		11.3		-		11.3		0.7		6.2		6.9
Gulf of Mexico		75.6		79.0		154.6		33.7		46.7		80.4
Gulf Coast Region		55.7		21.8		77.5		1.1		16.7		17.8
Rocky Mountains and Other		18.8		-		18.8		0.1		-		0.1
Total		277.8		162.6		440.4		38.9		154.9		193.8
Entity’s share of equity investee (2)		9.2		2.3		11.5

(1) Reflects reserves associated with incremental recovery from existing production/injection wells that require no future development costs and reserves associated with work performed on existing producers/injectors that do not meet the reasonable certainty requirements to be classified as proved.

(2) Amounts relate to our equity investment in McMoRan.

Onshore California

Los Angeles Basin

We hold a 100% working interest in the majority of our Los Angeles Basin, or LA Basin, properties, including Inglewood, Las Cienegas, Montebello, Packard and San Vicente. The LA Basin properties are characterized by light crude (21 to 32 degree API gravity), have well depths ranging from 2,000 feet to over 10,000 feet and include both primary production and mature waterfloods where producing wells have high water cuts.

In 2012, we spent $76 million on capital projects in the LA Basin, focused on improved waterflood recovery efficiency through infill drilling, producer and injector well recompletions and facility additions and enhancements to process higher fluid volumes. Drilling was concentrated in the Inglewood field where we drilled two wells, both of which were injector wells. Our net average daily LA Basin sales volumes were 11.1 MBOE per day in the fourth quarter of 2012. In 2013, we will continue to concentrate on development drilling and on recompletion projects in the LA Basin.

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San Joaquin Basin

Our San Joaquin Basin properties are located primarily in the Cymric, Midway Sunset and South Belridge Fields. These are long-lived fields that have heavier oil (12 to 16 degree API gravity) and shallow wells (generally less than 2,000 feet) that require enhanced oil recovery techniques, including steam injection, and produce with high water cuts.

We spent $114 million in 2012 on capital projects in the San Joaquin Basin focused on improved recovery efficiency through infill drilling, well recompletions, facility expansions and enhancements to process higher fluid volumes. During 2012, we drilled 62 wells, including three injector wells, in the San Joaquin Basin. Our net average daily San Joaquin Basin sales volumes were 18.8 MBOE per day in the fourth quarter of 2012.

We hold approximately 16,000 net acres in the San Joaquin Basin. In 2013, we will continue to concentrate on development drilling and on recompletion projects and facility expansions, including developing a diatomite expansion project.

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. This is a long-lived field that has heavier oil (12 to 16 degree API gravity) and well depths averaging 1,700 feet and requires continuous steam injection. In 2012, we spent $86 million on capital projects in this field focused on improved recovery efficiency primarily through facility enhancements projects. Our net average daily sales volumes from the Arroyo Grande Field were 0.9 MBOE per day in the fourth quarter of 2012.

Construction of a produced water reclamation facility is underway. Upon completion of the facility, we will begin to dewater the reservoir, allowing for improved efficiency of steam flood and continued development drilling. Additionally, we have signed a ten-year operations agreement for the facility which will commence upon commercial operations expected in the first quarter of 2013.

Offshore California

Point Arguello

We hold a 69.3% working interest (58% net revenue interest) in the Point Arguello Unit and the various partnerships owning the related transportation, processing and marketing infrastructure. Our net average daily sales volumes were 2.3 MBOE per day in the fourth quarter of 2012.

Point Pedernales

We hold a 100% working interest (83% net revenue interest) in the Pt. Pedernales Field, which includes one platform that is utilized to access the Federal OCS Monterey Reservoir by extended reach directional wells and support facilities which lie within the onshore Lompoc Field. Our combined net average daily sales volumes from our Pt. Pedernales and Lompoc Fields averaged 5.5 MBOE per day in the fourth quarter of 2012. In 2012, we spent $49 million on capital projects primarily associated with drilling of the A-29 exploratory well at Point Pedernales and the exploratory drilling and well recompletions in the Lompoc area. During 2012, we drilled five new wells. During 2013, we plan to drill additional extended reach Monterey wells in this area and continue our focus on plug back recompletions to maintain production.

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Gulf of Mexico

Our Gulf of Mexico portfolio includes a 100% working interest in the Holstein, Horn Mountain, Marlin, Dorado and King Fields, a 31% working interest in the Ram Powell Field and a 33.3% working interest in the Diana and Hoover Fields acquired on November 30, 2012. Additionally, we hold a 23.3% working interest in the Lucius oil field, a high-quality oil discovery. Our deepwater Gulf of Mexico exploration portfolio includes interests in 133 blocks containing 53 prospects or leads in the Pliocene, Miocene and lower Tertiary reservoirs. Our net average daily Gulf of Mexico sales volumes were 65.3 MBOE per day in December 2012.

Holstein Field

The Holstein Field is located in Green Canyon blocks 644, 645 and 688. The Holstein platform is a truss spar in water depth of approximately 4,300 feet, and production commenced in December 2004. The platform capacity is approximately 113,500 barrels of oil per day, 142,300 Mcf of gas per day and 45,900 barrels of water per day. We plan to upgrade the Holstein drilling rig and infrastructure and focus on further developing existing field pay intervals through recompletion, sidetrack, and water injection projects. In addition, we plan to develop and explore via subsea tiebacks deeper potential on the Holstein structure and leases in the Green Canyon area.

Horn Mountain Field

The Horn Mountain Field is located in Mississippi Canyon blocks 82, 126 and 127. The Horn Mountain platform is a truss spar in water depth of approximately 5,400 feet, and production commenced in November 2002. The platform capacity is approximately 75,000 barrels of oil per day, 72,000 Mcf of gas per day and 30,000 barrels of water per day. We plan to focus on further developing the field primarily through sidetracks of existing producing wells to undrained portions of the field pay reservoir intervals. In addition, we plan to develop and explore via subsea tiebacks additional amplitude driven resource opportunities as well as deeper potential on the Horn Mountain leases.

Marlin Hub

The Marlin Hub is the production facility for three fields: the Marlin Field (S/2 Viosca Knoll block 871 and N/2 Viosca Knoll block 915), the Dorado Field (S/2 Viosca Knoll block 915) and the King Field (Mississippi Canyon 84, 85, 128 and 129). The Marlin Hub is a tension leg platform in water depth of approximately 3,200 feet and production commenced in December 2000. The platform capacity is approximately 60,000 barrels of oil per day, 235,000 Mcf of gas per day and 20,000 barrels of water per day. The Marlin Field currently produces via a combination of platform and subsea tieback wells while the Dorado and King Fields currently produce exclusively via subsea wells and tieback infrastructure. Our development plans focus on installation of additional compression, deepening of existing wells, and drilling of additional producing wells to optimize recovery and target additional resources primarily in the King and Dorado Fields. In addition, we plan to target deeper potential in the King Field for future tieback to the Marlin Hub.

Ram Powell Field

The Ram Powell Field is located in Viosca Knoll blocks 911 through 913 and 955 through 957. The Ram Powell platform is a tension leg platform in water depth of approximately 3,200 feet, commissioned in 1997 with capacity of approximately 70,000 barrels of oil per day and 310,000 Mcf of gas per day. We intend to participate in production optimization projects as well as drilling opportunities in the main field pay intervals as planned by the operator.

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Diana and Hoover Fields

The Diana Field is located in East Breaks blocks 945, 946 and 989, and the Hoover Field is located in Alaminos Canyon blocks 25 and 26. The Hoover platform is a deep draft caisson vessel located in Alaminos Canyon block 25 in water depth of approximately 4,800 feet. Production commenced in May 2000, and the platform has capacity of approximately 100,000 barrels of oil per day, 325,000 Mcf of gas per day and 60,000 barrels of water per day. While the Hoover Field is developed via platform wells, production from the Diana Field is produced via subsea tieback at the Hoover platform. Several additional drilling opportunities exist in established field pay intervals in the Diana Field.

Lucius Oil Field and Other Gulf of Mexico

In October 2011, we entered into a securities purchase agreement with EIG Global Energy Partners, or EIG, pursuant to which we received $430.2 million of net cash proceeds in November 2011, upon closing of the transaction, in exchange for a 20% equity interest in Plains Offshore, a former wholly owned subsidiary. Plains Offshore holds certain of our oil and natural gas properties and assets located in the United States Gulf of Mexico in water depths of 500 feet or more, including the Lucius oil field and the Phobos exploration prospect, excluding the properties acquired from BP and Shell (see Acquisitions – Gulf of Mexico). The proceeds raised are expected to be used to fund Plains Offshore’s share of capital investment in the Lucius oil field, which is expected to commence production in 2014, and the Phobos exploration prospect for which results are expected in 2013. Under the agreement, Plains Offshore issued to EIG managed funds and accounts, or the EIG Funds, (i) 450,000 shares of Plains Offshore 8% convertible perpetual preferred stock and (ii) non-detachable warrants to purchase in aggregate 9,121,000 shares of Plains Offshore’s common stock with an exercise price of $20 per share. In addition, Plains Offshore issued 87 million shares of Plains Offshore Class A common stock, which will be held in escrow until the conversion and cancellation of the preferred stock or the exercise of the warrants held by EIG. In November 2011, Plains Offshore also entered into a senior credit facility providing for $300 million of commitments to fund future capital costs beyond that already raised.

Through our ownership in Lucius, located in the deepwater U.S. Gulf of Mexico, we joined the Lucius and Hadrian working interest partners and executed a unit participation and unit operating agreement effective June 1, 2011. As part of the agreements, we have agreed to share in our portion of certain costs for construction and installation of the production facility and subsea infrastructure, long lead equipment orders and detailed engineering work.

Plains Offshore and its partners have entered into various agreements with third parties for long-term oil and gas gathering and transportation services at the Lucius oil field. Beginning in 2014, Plains Offshore will pay guaranteed fixed minimum monthly fees plus additional variable gathering fees based upon actual throughput. The commitments of Plains Offshore under the oil gathering agreements are guaranteed by PXP.

In December 2011, the operator and our working interest partners sanctioned development of Lucius. Lucius will be a subsea development consisting of a truss spar hull located in 7,200 feet of water with a topsides capacity of 80,000 barrels of oil per day and 450,000 Mcf of gas per day. The development drilling program began in 2012 with achievement of first production anticipated in 2014. In 2013, we will continue development of the Lucius oil field and exploratory drilling of the Phobos prospect.

In October 2012, Plains Offshore entered into a waiver agreement with PXP to waive Plains Offshore’s rights to purchase properties acquired by PXP and PXP Resources LLC in the Gulf of Mexico Acquisition and to amend the existing stockholders agreement to limit certain exclusivity provisions.

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Gulf Coast Region

Eagle Ford Shale

At December 31, 2012, we own interests in oil and gas properties on approximately 88,000 gross acres (59,000 net acres) with 385 square miles of 3-D seismic data located in the Eagle Ford Shale. The Eagle Ford Shale is Upper Cretaceous in age, and typical well depths range from 9,500 feet to 11,500 feet. The area is currently being developed with horizontal wells with lateral lengths ranging from 3,500 feet to 6,000 feet at a measured total depth from 14,500 to 17,500 feet. Based on the 80 to 130 acre well spacing, we anticipate over 500 potential well locations.

Our net average daily sales volumes during the fourth quarter of 2012 were 40.4 MBOE per day, an increase of greater than 300% from the 9.1 MBOE per day net average during the fourth quarter of 2011.

We spent $1.1 billion of capital in 2012 focused on continued development drilling and the completion of seven production facilities. At December 31, 2012, we had eight rigs drilling horizontal development wells on our acreage and plan a similar activity level in 2013. For 2013, we allocated approximately $900 million of our capital budget to Eagle Ford Shale activity and plan to focus on drilling and completing approximately 100 wells and constructing two additional multi-well facilities.

Haynesville Shale

As of December 31, 2012, we have rights to approximately 430,000 gross acres (81,000 net acres) in the Haynesville Shale that we acquired from Chesapeake Energy Corporation, or Chesapeake, including approximately 51,000 net acres of leasehold that we believe is also prospective for the Bossier Shale. The Haynesville Shale is characterized by gas production from the Jurassic aged Haynesville shale formation, and typical well depth is 10,500 feet. The area has historically been developed with approximately 4,000 foot horizontal wells at a measured total depth of 16,000 feet. Based on the potential of 80 acre well spacing, we anticipate that there could be over 11,000 unrisked potential drilling locations on our acreage.

Our net average daily sales volumes during the fourth quarter of 2012 were 162.8 MMcfe per day, a 19% decrease from the 199.8 MMcfe per day net average during the fourth quarter of 2011. The decrease in sales volumes is primarily due to natural declines of wells and production and reduced drilling activity due to the prolonged decrease in natural gas prices.

We spent $67 million of capital in 2012 focused on converting undeveloped leases to leases held by production. In 2013, we plan to spend $20 million drilling horizontal wells and plan to focus on the development of our undeveloped leasehold.

Rocky Mountains

Wind River Basin

We own an approximate 14% working interest in the Madden Deep Unit and Lost Cabin Gas Plant located in central Wyoming. The Madden Deep Unit is a federal unit operated by a third party and consists of approximately 64,000 gross acres in the Wind River Basin. The Madden area is characterized by gas production from multiple stratigraphic horizons of the Lower Fort Union, Lance, Mesaverde and Cody sands and the Madison Dolomite. Production from the Madden Deep Unit is typically found at depths ranging from 5,500 to 25,000 feet. Some of the gas produced from the Madden Deep Unit requires processing at the Lost Cabin Gas Plant to remove high concentrations of

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carbon dioxide and hydrogen sulfide. Our net average daily sales volumes during the fourth quarter of 2012 were 16.7 MMcfe from the Wind River Basin.

During 2012, we spent $3 million on capital projects in the Madden Deep Unit. In 2013, we are focused on maintaining production and high-grading the remaining development drilling inventory.

Big Horn Basin

We hold leases covering 125,000 gross acres (111,000 net acres) in the Big Horn Basin located in Wyoming. During 2013, we plan to monitor industry activity in this play.

Acquisition, Exploration and Development Expenditures

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

	Year Ended December 31,
	2012		2011		2010
Consolidated entities
Property acquisition costs
Unproved properties	$	2,102,628	$	36,562	$	612,471
Proved properties		4,139,000		9,236		48,078
Exploration costs (1)		1,078,986		1,147,858		719,004
Development costs		829,090		708,519		363,242
	$	8,149,704	$	1,902,175	$	1,742,795
Entity’s share of equity investee (2)
Property acquisition costs
Unproved properties	$	-	$	15,523
Proved properties		-		-
Exploration costs		162,150		175,802
Development costs		6,708		17,190
	$	168,858	$	208,515

(1) Exploration costs are related to exploratory activities as defined for accounting purposes and include the drilling of exploratory wells primarily in the Eagle Ford Shale and acquisition of seismic data.

(2) Amounts relate to our equity investment in McMoRan acquired on December 30, 2010. Our proportionate share of McMoRan’s 2010 costs incurred is not presented because it is insignificant as PXP owned the investment for one day and it is not practicable to determine one day of costs incurred.

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Production and Sales

The following table presents information with respect to oil and gas production attributable to our properties, average sales prices we realized and our average production expenses during the years ended December 31, 2012, 2011 and 2010.

	Total (1)
2012
Oil and liquids sales (MBbls)		24,365
Gas (MMcf)
Production		88,472
Used as fuel		1,362
Sales		87,110
MBOE
Production		39,110
Sales		38,883
Average realized sales price before derivative transactions (2)
Oil (per Bbl)	$	95.46
Gas (per Mcf)		2.67
Per BOE		65.79
Average production cost per BOE (3)
Lease operating expenses	$	10.12
Steam gas costs		1.22
Electricity		1.13
Gathering and transportation		1.90

	Inglewood (4)		Haynesville Shale (4)		Other		Total
2011
Oil and liquids sales (MBbls)		2,332		-		15,540		17,872
Gas (MMcf)
Production		969		68,015		42,593		111,577
Used as fuel		35		-		2,073		2,108
Sales		934		68,015		40,520		109,469
MBOE
Production		2,494		11,336		22,638		36,468
Sales		2,488		11,336		22,293		36,117
Average realized sales price before derivative transactions (2)
Oil (per Bbl)	$	96.65	$	-	$	83.87	$	85.53
Gas (per Mcf)		4.10		3.85		4.01		3.91
Per BOE		92.14		23.11		65.75		54.18
Average production cost per BOE (3)
Lease operating expenses	$	21.23	$	1.71	$	11.78	$	9.27
Steam gas costs		-		-		2.94		1.81
Electricity		5.67		-		1.22		1.14
Gathering and transportation		0.17		4.38		0.54		1.72

Table continued on following page.

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	Inglewood (4)		Haynesville Shale (4)		Other		Total
2010
Oil and liquids sales (MBbls)		2,211		-		14,558		16,769
Gas (MMcf)
Production		1,089		43,051		50,907		95,047
Used as fuel		31		-		1,923		1,954
Sales		1,058		43,051		48,984		93,093
MBOE
Production		2,393		7,175		23,042		32,610
Sales		2,387		7,175		22,723		32,285
Average realized sales price before derivative transactions (2)
Oil (per Bbl)	$	73.02	$	-	$	67.41	$	68.14
Gas (per Mcf)		4.45		4.17		4.39		4.29
Per BOE		69.60		25.05		52.66		47.77
Average production cost per BOE (3)
Lease operating expenses	$	17.88	$	1.61	$	9.17	$	8.13
Steam gas costs		-		-		2.92		2.06
Electricity		5.98		-		1.26		1.33
Gathering and transportation		0.22		4.54		0.77		1.57

(1) In 2012, we had no fields that contained 15% or more of our total proved reserves.

(2) See Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations for cash payments related to our derivatives. Our derivative transactions are not included in oil and gas sales because they are not classified as hedges for accounting purposes.

(3) Does not include production and ad valorem taxes.

(4) The field has been attributed total proved reserves greater than 15% of our total proved reserves. The Inglewood field is located onshore California and the Haynesville Shale is located onshore Louisiana and Texas.

Product Markets and Major Customers

Our revenues are highly dependent upon the prices of, and demand for, oil and gas. The markets for oil and gas have historically 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.

We use various derivative instruments to manage our exposure to commodity price risk on sales of oil and gas production. Derivatives provide us protection on the sales revenue streams if prices decline below the prices at which the derivatives are set. However, ceiling prices in derivatives may result in us receiving less revenue on the volumes than would be received in the absence of the derivatives. Our derivative instruments currently consist of crude oil put option, collar and swap contracts and natural gas swap contracts entered into with financial institutions.

A substantial portion of our oil reserves are located in California and approximately 39% of our production is attributable to heavy crude (generally 21 degree API gravity crude oil or lower). Historically, the market price for California crude oil differs from the established market indices in the United States due principally to the higher transportation and refining costs associated with heavy oil. Recently, however, the market price for California crude oil has strengthened relative to NYMEX and WTI primarily due to world demand and declining domestic supplies of both Alaskan and California crude oil.

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Our heavy crude is primarily sold to Phillips 66, which was spun off from ConocoPhillips effective May 1, 2012, at which time we consented to the assignment of our crude oil purchase agreement from ConocoPhillips to Phillips 66. Our current marketing contract with Phillips 66 was effective January 1, 2012 and expires January 1, 2023. The contract covers approximately 88% of our California production with prices based upon regional benchmarks that are not linked to NYMEX. A large portion of our Eagle Ford Shale crude oil is sold to third party purchasers using a Light Louisiana Sweet based pricing mechanism. Due to these marketing contracts, we increased oil price realizations in 2012 on a significant portion of our crude oil production relative to Brent. During 2012, we received approximately 88% of the Brent index price for crude oil sold under the Phillips 66 contract and 89% of the Brent index price for crude oil for our Eagle Ford Shale crude oil production, which represented approximately 52% and 32%, respectively, of our total crude oil production. During 2011, we received approximately 77% of the Brent index price for crude oil sold under the ConocoPhillips contract, which represented approximately 50% of our total crude oil production.

Our share of oil and gas production from the Gulf of Mexico Acquisition will be sold under a series of arms-length contracts awarded on a competitive bid basis or entered into following negotiations. Crude oil will be sold directly to companies with refineries in the Gulf Coast regions of Texas and Louisiana at prices based on widely-used industry benchmarks. Gas will be processed in one of three large onshore gas plants, where we will be paid our contractual share of revenues from the sale of natural gas liquids. We will sell or deliver our residue gas to various industrial and energy markets as well as intrastate and interstate pipeline systems. We will use a series of pipelines, some of which will be ours, to transport our oil and gas production from the platforms to shore. These movements will be made under a combination of transportation contracts and tariffs.

Approximately 99% of our 2012 crude oil production was sold under contracts with prices based upon regional benchmarks that are not linked to NYMEX with the remainder sold under contracts that provide for NYMEX less a fixed price differential (as of December 31, 2012 the fixed price differential averaged $3.41 per barrel).

Our share of production from the Haynesville Shale is sold by Chesapeake under the terms of a fifteen-year contract with a primary term which expires on September 1, 2023. The contract with Chesapeake provides that Chesapeake will sell our production along with its own for which Chesapeake charges a marketing fee.

Beginning in December 2012, we have oil and gas production volume delivery commitments for a period of five years. If we are unable to meet the commitments to deliver this production, our maximum financial commitment at December 31, 2012 would be $50.6 million over the remaining contract term. We currently have sufficient reserves and production capacity to fulfill this commitment. See Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Commitments and Contingencies.

Prices received for our gas are subject to seasonal variations and other fluctuations. Approximately 50% 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 spot and index prices can significantly impact the overall differential to the Henry Hub.

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During the three years ended December 31, 2012, 2011 and 2010, sales to the following purchasers accounted for the percentages of our total revenues as disclosed:

	2012			2011			2010
ConocoPhillips (1)		14	%		41	%		57	%
Phillips 66 (1)		35	%		-			-
Valero Energy Corporation		17	%		11	%		-	%  (2)
Tesoro Corporation (3)		-			13	%		-	%  (2)

(1) Phillips 66 was spun off from ConocoPhillips on May 1, 2012. On a combined basis, sales to Phillips 66 and ConocoPhillips accounted for 49% of our total revenues in 2012.

(2) Sales accounted for less than 10% of our total revenues.

(3) The contract with Tesoro Corporation expired in November 2011. We did not renew this contract, and upon expiration we entered into a contract with ConocoPhillips for these volumes, which was subsequently assigned to Phillips 66.

During 2012, 2011 and 2010, no other purchaser accounted for more than 10% of our total revenues. Beginning in early 2013, a large portion of our production from the Gulf of Mexico Acquisition will be sold to Phillips 66. Based on current production rates, we anticipate a larger percentage of our total revenue will result from sales to Phillips 66 in 2013. The loss of any single significant purchaser or contract could have a material adverse short-term effect; however, we do not believe that the loss of any single significant purchaser 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 such purchasers may be affected by changes in economic, industry or other conditions. We do not currently require letters of credit or other collateral from the above stated purchasers to support trade receivables. Accordingly, a material adverse change in any such purchaser’s financial condition could adversely impact our ability to collect the applicable receivables, and thereby affect our financial condition.

There are a limited number of alternative methods of transportation for our production. A substantial portion 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 us 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.

Acreage

The following table sets forth information with respect to our developed and undeveloped acreage as of December 31, 2012:

	Developed Acres				Undeveloped Acres (1)
	Gross		Net		Gross		Net
California
Onshore		61,309		60,733		57,736		34,900
Offshore		43,300		39,000		-		-
Florida		-		-		115,397		15,006
Louisiana
Onshore		369,586		69,348		30,263		5,678
Offshore		133,800		80,900		618,300		249,500
Nevada		-		-		246,072		246,072
Texas		104,606		46,133		56,432		31,573
Utah		-		-		88,862		62,734
Wyoming		78,750		11,075		143,669		120,471
Other states (2)		3,124		529		57,696		36,105
		794,475		307,718		1,414,427		802,039

(1) Approximately 24% of our total net undeveloped acres is covered by leases that expire from 2013 to 2015.

(2) Other states include Arkansas, Illinois, Indiana, Kansas, Mississippi, Montana, North Dakota and Oklahoma.

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Productive Wells

As of December 31, 2012, we had working interests in 3,193 gross (3,061 net) active producing oil wells and 1,544 gross (209 net) active producing gas wells. One or more completions in the same well bore are counted as one well. If any well in which one of the multiple completions is an oil completion, then the well is classified as an oil well. As of December 31, 2012, we owned an interest in five gross wells containing multiple completions.

Drilling Activities

The number of oil and gas wells completed during the years ended December 31, 2012, 2011 and 2010 is set forth below:

	Year Ended December 31,
	2012				2011				2010
	Gross		Net		Gross		Net		Gross		Net
Exploratory Wells (1)
Oil		95.0		74.4		36.0		27.6		6.0		3.1
Gas		119.0		19.6		443.0		42.7		318.0		38.3
Dry		3.0		1.0		3.0		-		4.0		2.2
		217.0		95.0		482.0		70.3		328.0		43.6
Development Wells
Oil		92.0		79.4		192.0		165.2		109.0		106.4
Gas		44.0		5.9		67.0		22.5		8.0		2.7
Dry		-		-		2.0		1.9		1.0		1.0
		136.0		85.3		261.0		189.6		118.0		110.1
		353.0		180.3		743.0		259.9		446.0		153.7

(1) Includes extension wells.

At December 31, 2012, there were 64 gross exploratory and 20 gross development wells (36.6 net exploratory and 5.6 net development wells) including 49 wells in progress in the Eagle Ford Shale where we had eight rigs actively drilling horizontal wells at year-end.

Investment

At December 31, 2012 and 2011, we owned 51.0 million shares of McMoRan common stock, approximately 31.5% and 31.6%, respectively, of its common shares outstanding. McMoRan is a publicly traded oil and gas exploration and production company (New York Stock Exchange listing MMR) engaged in the exploration, development and production of natural gas and oil in the United States, specifically offshore in the shallow waters of the Gulf of Mexico Shelf and onshore in the Gulf Coast area. We acquired the McMoRan common stock and other consideration in exchange for all of our interests in our Gulf of Mexico leasehold located in less than 500 feet of water. See Items 1 and 2 – Business and Properties – Divestments.

As contemplated by the Agreement and Plan of Merger, we and McMoRan entered into a registration rights agreement and a stockholder agreement at the closing of the transaction on December 30, 2010. The registration rights agreement gives us piggyback registration rights and demand registration rights under certain circumstances. Under the terms of the stockholder agreement, McMoRan expanded its board of directors and we have the right to designate two board members for so long as we own at least 10% of the outstanding shares of McMoRan. If our ownership falls below

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10%, but is at least 5%, we will have the right to designate one director. The stockholder agreement requires us to refrain from certain activities that could be undertaken to acquire control of McMoRan. We may sell shares of McMoRan common stock pursuant to underwritten offerings, in periodic sales under the shelf registration statement filed by McMoRan (subject to certain volume limitations), pursuant to the exercise of piggyback registration rights or as otherwise permitted by applicable law.

On December 5, 2012, Freeport-McMoRan entered into an Agreement and Plan of Merger, or the MMR Merger Agreement, with McMoRan and INAVN Corp., a wholly owned subsidiary of Freeport-McMoRan, or the MMR Merger Sub, pursuant to which MMR Merger Sub will be merged with and into McMoRan, or the MMR Merger, with McMoRan continuing as the surviving company and a wholly owned subsidiary of Freeport-McMoRan. The per share consideration consists of $14.75 in cash and 1.15 units of a royalty trust, which will hold a 5% overriding royalty interest in future production from McMoRan’s existing ultra-deep exploration properties. In connection with the MMR Merger, on December 5, 2012, PXP and Freeport-McMoRan entered into a Voting and Support Agreement, or the Support Agreement. The Support Agreement generally requires that the Company, in its capacity as a stockholder of McMoRan, vote all of its shares of McMoRan common stock in favor of the MMR Merger and against alternative transactions and generally prohibits us from transferring our shares of McMoRan common stock prior to the consummation of the MMR Merger. The Support Agreement will terminate upon the earlier of (i) the Expiration Date (defined as the earlier of (A) the consummation of the MMR Merger and (B) the termination of the MMR Merger Agreement) and (ii) any breach by Freeport-McMoRan of its obligation under the Freeport-McMoRan Merger Agreement not to change the merger consideration in the MMR Merger Agreement, amend the covenant relating to standstill waivers in the MMR Merger Agreement or otherwise materially amend any material provision of the MMR Merger Agreement, or terminate the MMR Merger Agreement, without PXP’s prior written consent. The MMR Merger is subject to the approval of the shareholders of McMoRan, including the approval of an amendment to McMoRan’s certificate of incorporation, receipt of regulatory approvals and customary closing conditions.

Real Estate

We have surface development activities on the following tracts of real property, some 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

We have real estate consulting agreements with Cook Hill Properties, LLC. Under the terms of the agreements, Cook Hill Properties is 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 properties listed above. Cook Hill Properties is a 15% participant in the venture and can earn an additional incentive on each property.

During 2012, we primarily focused our efforts on the Montebello property. Our objective relative to the Montebello property is to take advantage of the positioning of this site as a potential significant residential development project in the San Gabriel Valley region of Greater Los Angeles. The project is located in southeastern Los Angeles County ten miles east of downtown Los Angeles. We are actively pursuing the entitlement process for our Montebello property and are engaged in pre-entitlement activities in Arroyo Grande and Lompoc. Our current development plans include master planned communities with a range of housing from entry level to executive and estate homes, parks and recreational land uses.

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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. In 2012, we spent approximately $4.3 million on our real estate projects.

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 generally have 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 governmental regulation. Many federal, state and local legislative bodies and regulatory agencies are authorized to issue, and have issued, laws and regulations binding on the oil and gas industry and its individual participants. The failure to comply with these laws 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 of complex federal, state and local laws and 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 and local statutes and rules that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard, the U.S. Environmental Protection Agency, or EPA, emergency planning and community-right-to-know regulations, and similar state and local statutes and rules require that we maintain certain information about hazardous conditions or materials used or produced in our operations and that we provide this information to our employees, government authorities and citizens. We believe that our operations are in substantial compliance with these requirements, including general industry standards, training, record keeping requirements and monitoring of occupational exposure to regulated conditions or substances.

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BOEM/BSEE.    The United States Bureau of Ocean Energy Management, or BOEM, and the Bureau of Safety and Environmental Enforcement, or BSEE, (together the BOEM/BSEE) were established on October 1, 2011 as agencies of the Department of Interior that were previously one agency known as the Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE. These two newly formed bureaus have broad authority to regulate our oil and gas operations on offshore leases in federal waters. They must approve and grant permits in connection with our exploration, drilling, development and production plans in federal waters. Additionally, BOEM/BSEE will implement regulations and “Notices to Lessees” already issued by BOEMRE requiring offshore production facilities to meet stringent engineering, construction, safety and environmental specifications, including regulations restricting the flaring or venting of gas, governing the plugging and abandonment of wells, regulating workplace safety, and controlling the removal of production facilities. Under certain circumstances, the BOEM/BSEE may suspend or terminate any of our operations on federal leases, as discussed in Item 1A – Risk Factors – We are subject to certain regulations, some of which require permits and other approvals. These regulations could increase our costs and may terminate, delay or suspend our operations. The BOEM/BSEE have adopted regulations providing for enforcement actions, including civil penalties, and lease forfeiture or cancellation for failure to comply with regulatory requirements for offshore operations. The Department of the Interior’s Office of Natural Resources Revenue has also established rules governing the calculation of royalties and the valuation of oil produced from federal offshore leases and regulations regarding transportation allowances for offshore production. Delays in the approval or refusal of plans and issuance of permits by the BOEM/BSEE because of staffing, economic, environmental or other reasons (or other actions taken by the BOEM/BSEE under its regulatory authority) could adversely affect our operations. Platforms acquired as part of the Gulf of Mexico Acquisition are currently under review by the BOEM/BSEE.

Surety and Oil Spill Financial Responsibility Requirements.    Historically, we have complied with the BOEM/BSEE regulations and held any bonds, or provided the financial assurances, required for our leases in federal waters. To cover the various obligations of lessees in federal waters, the BOEM/BSEE generally requires that lessees have substantial U.S. assets and net worth or post bonds or other acceptable assurances that such obligations will be met. We are subject to the following types of surety requirements with BOEM: (i) general lessee or operator’s bonds required to accept title to any lease in federal waters, (ii) supplemental bonding, which is required to be provided by all lessees and specifically covers the plugging and abandonment obligations associated with a lease, and (iii) oil spill financial responsibility, generally provided by operators pursuant to the Oil Pollution Act of 1990 as amended, or OPA. The OPA imposes a variety of requirements related to the prevention of and response to oil spills into waters of the United States, including the Outer Continental Shelf, which includes the U.S. Gulf of Mexico. The OPA subjects operators of offshore leases and owners and operators of oil handling facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. The OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. The OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating oil production facilities on the Outer Continental Shelf, although the Secretary of Interior may increase this amount up to $150 million in certain situations. The cost of these bonds or other surety when combined with financial assurances could be substantial and there is no assurance that bonds or other surety could be obtained in all cases.

Pipeline Safety Regulation.    We have pipelines to deliver our production to sales points. Some of our pipelines are subject to regulation by the United States Department of Transportation, or DOT, 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 prepare

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certain reports and provide information, as required by the Secretary of Transportation. The states in which we have pipelines have comparable regulations. We believe that our pipeline operations are in substantial compliance with applicable requirements.

Recently enacted pipeline safety legislation, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, reauthorizes funding for federal pipeline safety programs, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. The Pipeline Hazardous Materials Safety Administration of the DOT has also published an advanced notice of proposed rulemaking to solicit comments on the need for changes to its safety regulations, including whether to revise the integrity management requirements and add new regulations governing the safety of gathering lines. Such legislative and regulatory changes could have a material effect on our operations and costs of transportation service due to more stringent and comprehensive safety regulation and higher penalties for violations of those regulations.

Sale and Transportation of Gas and Oil.    The Federal Energy Regulatory Commission, or FERC, approves the construction of interstate gas pipelines and the rates and service conditions for the interstate transportation of gas, oil and other liquids by pipeline. Some of our pipelines related to the Point Arguello unit are subject to this regulation by the FERC. Although the FERC does not regulate the production of gas, the FERC exercises regulatory authority over wholesale sales of gas in interstate commerce through the issuance of blanket marketing certificates that authorize the wholesale sale of gas at market rates and the imposition of a code of conduct on blanket marketing certificate holders that regulate certain affiliate interactions. The FERC does not regulate the sale of oil or petroleum products or the construction of oil or other liquids pipelines. The FERC also has oversight of the performance of wholesale natural gas markets, including the authority to facilitate price transparency and to prevent market manipulation. In furtherance of this authority, the FERC imposed an annual reporting requirement on all industry participants, including otherwise non-jurisdictional entities, engaged in wholesale physical natural gas sales and purchases in excess of a minimum level. 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 and other federal agencies, the United States Congress or state legislative bodies and regulatory agencies may consider additional proposals or proceedings that might affect the gas or oil industries. 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.

Market Manipulation Regulations.    The FERC with respect to natural gas, the Federal Trade Commission with respect to petroleum and petroleum products, and the Commodity Futures Trading Commission, or CFTC, with respect to commodity and futures markets, operating under various statutes have each adopted anti-market manipulation regulations, which prohibit, among other things, fraud and price manipulation in the respective markets. Should we violate anti-manipulation laws and regulations we could be subject to substantial penalties, including one or more of the following: civil penalties, potential disgorgement of profits, the payment of refunds and criminal penalties. We could also be subject to third-party damage claims.

Environmental.    Our operations and properties are subject to extensive and increasingly stringent federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission and transportation of materials and the discharge of

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materials into the environment. Such statutes include, but are not limited to, the Comprehensive Environmental Response, Compensation and Liability Act, Resource Conservation and Recovery Act, Clean Air Act, Clean Water Act, OPA and Safe Drinking Water Act, or SDWA, and analogous state laws. Statutes that specifically provide protection to animal and plant species and which may apply to our operations include, but are not limited to, the Marine Mammal Protection Act, the Marine Protection, 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, and often their state and local counterparts. These laws and regulations promulgated thereunder may require the acquisition of a permit or other authorization before construction or drilling commences and limit or prohibit construction, drilling and other activities, particularly on lands lying within wilderness or wetlands and other protected areas; and impose substantial liabilities for pollution resulting from or related to our operations. If a person violates, or is otherwise liable under 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 or if such is found to exist on properties we own or operated, we could incur substantial expense, including removal and/or remediation costs and other liability under applicable laws and regulations, as well as claims made by neighboring landowners and other third parties for personal injury and property damage.

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 laws and 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, usually becoming more stringent, 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.

Climate Change Regulation.    From time to time the U.S. Congress has considered climate-related legislation to reduce emissions of greenhouse gases.

Recent and future environmental regulations, including additional federal and state restrictions on greenhouse gas emissions that may be passed in response to climate change concerns, may increase our operating costs and also reduce the demand for the oil and natural gas we produce. Any laws or regulations that may be adopted to restrict or reduce emissions of U.S. greenhouse gases could require us to incur increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce. The EPA adopted the so-called “Tailoring Rule” in May 2010, which imposes permitting and best available control technology requirements on the largest greenhouse gas stationary sources. In November 2010, the EPA also published mandatory reporting rules for certain oil and gas facilities, with reports required by September 30, 2012, which reports we file timely. Some of our facilities are subject to these various requirements. In addition, many states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas Cap and Trade programs. In California, for example, the California Air Resources Board, or CARB, has developed regulations pursuant to the California Global Warming Solutions Act of 2006, or Assembly Bill 32, that are intended to achieve an overall reduction in greenhouse gas emissions to 1990 levels, a 15% reduction by 2020. Because several of our operations emit greenhouse gases in excess of 25,000 metric tons per year, various operations in California are subject to the requirements of this program. In October 2011 CARB adopted the final Cap and Trade regulation which is intended to implement the Cap and Trade Program under Assembly Bill 32. The regulation established three separate three year compliance periods as follows: 2012 to 2014, 2015 to 2017 and 2018 to 2020. The regulation required regulated

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entities to “true up” their emission offset obligations by the end of each three-year obligation period. Due to time constraints on implementing the Cap and Trade Program, the regulation included a provision which would forego the requirement of regulated entities to surrender compliance instruments for their emissions the first year of the first compliance period. The first year which will require regulated entities to surrender compliance instruments will be for 2013 emissions. Compliance with these regulations will require companies to periodically secure instruments known as offsets and allowances, each of which is equal to one metric ton of emissions under the Cap and Trade program. The price of these instruments will vary in accordance with market conditions. The total amount of instruments we owe will vary annually based on the total greenhouse gas emissions registered in any one year and the number of “free allowances” issued by CARB annually. In November 2012 CARB held the first public auction of allowance instruments for regulated entities to begin meeting their compliance obligations. The settling price in the auction placed the price at $10.09 per allowance. In 2011 our California properties subject to regulation under Assembly Bill 32 emitted 955,000 metric tons of greenhouse gas emissions. In 2012 we were issued 644,000 free allowances by CARB based on estimated emissions using our 2011 verified emissions data. Based on these figures we will be required to secure an estimated 311,000 instruments to meet our 2013 obligations by the end of the first compliance period. We are in the process of acquiring our required allowances and do not believe that the cost of acquiring such allowances will be material. Certain aspects of Assembly Bill 32, including the Cap and Trade program, are the subject of pending litigation and may be changed based on the outcome of such litigation.

Although we would not be impacted to a greater degree than other similarly situated oil and gas companies, passage of climate change legislation or other regulatory initiatives by Congress or various states, or the adoption of regulations by the EPA or analogous state agencies, that regulate or restrict emissions of greenhouse gases (including methane or carbon dioxide) in areas in which we conduct business and could have an adverse effect on our operations and the demand for oil and natural gas.

Hydraulic Fracturing.    Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations such as shales. The process involves the injection of large quantities of water, which contains sand and small amounts of various chemicals, under pressure into the formation to fracture the surrounding rock and stimulate oil and natural gas production. The use of hydraulic fracturing is necessary to produce commercial quantities of oil and natural gas from many reservoirs, especially shale formations such as the Haynesville Shale and Eagle Ford Shale. The process is typically regulated by state oil and natural gas commissions and agencies. Our operations utilize the practice of hydraulic fracturing for new oil and natural gas wells. Hydraulic fracturing is also used occasionally to recomplete or restimulate an existing well that has declined in production performance. The practice of hydraulic fracturing continues to receive significant regulatory and legislative attention at the federal, state, and local level. From time to time, legislation has been introduced in Congress to amend the SDWA to eliminate exemptions for most hydraulic fracturing activities. On May 11, 2012, the Bureau of Land Management, or BLM, proposed regulations that would require public disclosure of the chemicals used in hydraulic fracturing and impose certain permitting, testing and other requirements on such operations on federal lands. However, on January 18, 2013, the BLM announced that it would be revising and re-proposing these regulations at a later date. Various other federal agencies (including the EPA and the Department of Energy) continue to study hydraulic fracturing and may propose additional regulations. The EPA has approved final rules that establish new air emission controls for natural gas and natural gas liquids production, processing and transportation activities, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants frequently associated with production and processing activities. These rules were published in the Federal Register on August 16, 2012. Similar efforts to review the practice of hydraulic fracturing and impose new regulatory conditions are taking place at the state and local level in states where we operate and may operate in the future. California, Texas and

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Wyoming as well as other states have adopted or are considering new regulations and statutes pertaining to hydraulic fracturing. These new requirements will (and future regulatory, judiciary and legislative changes, if enacted or adopted, could) create new permitting and financial assurance requirements, require us to adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping obligations, and meet plugging and abandonment requirements. Although we would not be impacted to a greater degree than other similarly situated oil and gas companies in these jurisdictions, the imposition of stringent new regulatory and permitting requirements related to the practice of hydraulic fracturing could significantly increase our cost of doing business, create adverse effects on our operations, including creating delays related to the issuance of permits, and depending on the specifics of any particular proposal that is enacted, could be material.

Permits.    Our operations are subject to various federal, state and local laws and regulations that include requiring permits for the drilling and operation of wells, and maintaining bonding and insurance requirements to drill, operate, plug and abandon. We are also subject to laws and regulations that require us to restore the surface associated with our wells, regulate 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. In certain instances we may also be subject to permit conditions that require us to reabandon an old well as a condition of adding a new injection well. Also, we have permits from numerous jurisdictions to operate crude oil, natural gas and related pipelines and equipment that run within the boundaries of these governmental jurisdictions. The permits required for various aspects of our operations are subject to enforcement for noncompliance as well as revocation, modification and renewal by issuing authorities.

Plugging, Abandonment and Remediation Obligations

For discussion of our obligations to incur plugging, abandonment and remediation costs, see Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Commitments and Contingencies.

Employees

As of January 31, 2013, we had 906 full-time employees, 335 of whom were field personnel involved in oil and gas producing activities. We believe our relationship with our employees is good.

Additionally, we entered into a transition services agreement with BP, or the BP Transition Services Agreement, in connection with the Gulf of Mexico Acquisition that requires BP to provide for the operational and general and administrative functions for the acquired properties for a specified period of time post-closing. Upon expiration of the BP Transition Services Agreement in April 2013, we intend to add 138 full-time employees, all of whom will be field personnel involved in oil and gas producing activities.

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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.

Risks Related to the Merger with Freeport-McMoRan

Failure to complete the merger could negatively impact our stock price and our future business and financial results.

We cannot assure you that the Freeport-McMoRan Merger Agreement will be approved by the Company’s stockholders or that the other conditions to the completion of the merger will be satisfied. In addition, both the Company and Freeport-McMoRan have the right to terminate the Freeport-McMoRan Merger Agreement and pursue alternative transactions under certain conditions. If the merger is not completed, we will not receive any of the expected benefits of the merger and will be subject to risks and/or liabilities, including the following:

• failure to complete the merger might be followed by a decline in the market price of the Company’s common stock;

• under the Freeport-McMoRan Merger Agreement, the Company may be required, under certain circumstances, to reimburse up to $69.0 million of Freeport-McMoRan’s expenses and/or to pay Freeport-McMoRan a termination fee of $207.0 million (less any amounts previously paid in respect of expenses);

• certain costs relating to the merger (such as legal, accounting and financial advisory fees) are payable by the Company whether or not the merger is completed;

• the Company would continue to face the risks that it currently faces as an independent company; and

• the Company could be subject to litigation related to any failure to complete the merger or to enforcement proceedings commenced against the Company to attempt to force it to perform its obligations under the Freeport-McMoRan Merger Agreement.

If the merger is not completed, these risks and liabilities may materially adversely affect the Company’s business, financial results, financial condition and stock price.

In addition, there can be no assurance that Freeport-McMoRan will be successful in obtaining expected financing. Although financing is not a condition to closing of the merger, if Freeport-McMoRan were not able to obtain the expected financing, or not able to obtain the financing on commercially reasonable terms, it might not be able to complete the merger.

Until the merger is completed or the Freeport-McMoRan Merger Agreement is terminated, under certain circumstances, the Company may not be able to enter into a merger or business combination with another party at a favorable price without incurring potentially significant expenses.

Unless and until the Freeport-McMoRan Merger Agreement is terminated, subject to specified exceptions (which are discussed in more detail in the Freeport-McMoRan Merger Agreement), the Company and its affiliates, advisors and representatives are restricted from initiating, soliciting or

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knowingly encouraging a proposal or offer for an alternative transaction with any person or entity other than Freeport-McMoRan. Subject to specified conditions, including the requirement that the Company not be in material breach of these non-solicitation provisions, the Company’s board may authorize a superior proposal (as defined in the Freeport-McMoRan Merger Agreement). However, in that event, the Company will be required to pay Freeport-McMoRan a termination fee of $207.0 million (less any amounts previously paid in respect of Freeport-McMoRan’s expenses). As a result of these restrictions, the Company may not be able to enter into an alternative transaction at a more favorable price without incurring potentially significant liability to Freeport-McMoRan.

If the Freeport-McMoRan Merger Agreement is terminated, the Company may be obligated to reimburse Freeport-McMoRan for costs incurred related to the merger and, under certain circumstances, pay a termination fee to Freeport-McMoRan. These costs could require the Company to seek loans or use its available cash that would have otherwise been available for operations or other general corporate purposes.

In certain circumstances, the Company may be required to reimburse Freeport-McMoRan for up to $69.0 million in expenses and/or to pay Freeport-McMoRan a termination fee of $207.0 million (less any amounts previously paid in respect of expenses). If the Freeport-McMoRan Merger Agreement is terminated, the termination fee required to be paid, if any, by the Company may require the Company to seek loans or borrow amounts to enable it to pay these amounts to Freeport-McMoRan. In either case, payment of these amounts would reduce the cash the Company has available for operations or other general corporate purposes.

Uncertainties associated with the merger may cause the Company to lose employees, customers and business partners, and while the merger is pending, the Company is subject to restrictions on the conduct of its business.

The Company’s current and prospective employees may be uncertain about their future roles and relationships with the Company following the completion of the merger. This uncertainty may adversely affect our ability to attract and retain key management and employees.

Our customers and business partners may not be as willing to continue business with us on the same or similar terms pending the completion of the merger, which would materially and adversely affect our business and results of operations. In addition, the Freeport-McMoRan Merger Agreement restricts us from taking specified actions without Freeport-McMoRan’s approval including, among other things, making certain significant acquisitions, dispositions or investments, making certain significant capital expenditures and entering into certain material contracts. Our management may also be required to devote substantial time to merger-related activities, which could otherwise be devoted to pursuing other beneficial business opportunities.

Any delay in completing the merger and integrating the businesses may substantially reduce the benefits expected to be obtained from the merger.

In addition to obtaining the required regulatory clearances and approvals, the merger is subject to a number of other conditions beyond the control of the Company and Freeport-McMoRan that may prevent, delay or otherwise materially adversely affect its completion. We cannot predict whether or when the conditions to closing will be satisfied. Any delay in completing the merger and integrating the businesses may diminish the benefits that we expect to achieve in the merger.

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Risks Related to Our Business

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 OPEC and other major producing companies;

• political conditions in other oil-producing and gas-producing countries, including the possibility of insurgency, terrorism 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, including the value of the U.S. Dollar relative to other major currencies; 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 and probable oil and gas reserve information included in this document represents only estimates. These estimates are based on reports prepared by independent petroleum engineers and us. The estimates were calculated using the twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. 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;

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• the assumed effects of regulations by governmental agencies;

• assumptions concerning future oil and gas prices; and

• assumptions concerning future operating costs, transportation 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, with the variability likely to be higher for probable reserves estimates.

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 costs as of the date of the estimates and the twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. 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.

Oil and natural gas prices have the potential to be volatile. As of February 2013, the twelve-month average of the first-day-of-the-month reference price for natural gas has increased from $2.76 per MMBtu at year-end 2012 to $2.86 per MMBtu, while the comparable price for oil has declined from $94.71 per Bbl at year-end 2012 to $94.14 per Bbl. Lower oil and natural gas prices not only decrease our revenues, but also may reduce the amount of hydrocarbons that we can produce economically and therefore potentially reduce the amount of our proved reserves. Reductions in the amount of our proved reserves, in turn, may reduce the borrowing base under our revolving line of credit. The borrowing base is determined at the discretion of our lenders based on, among other things, the collateral value of our proved reserves and is subject to regular redeterminations on May 1 of each year, as well as unscheduled redeterminations as set forth in the credit agreement.

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

Our future success depends on our ability to find, develop and acquire additional oil and gas reserves that are economically recoverable which, in itself, is dependent on oil and gas prices. Without continued successful 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 production.

A substantial portion of our reserves are located in California, and as a result of the Gulf of Mexico Acquisition, a substantial portion of our production is from the Gulf of Mexico. 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, on average, heavier than premium grade light oil and the margin (sales price minus production costs) is generally less than that of lighter oil sales due to the processes required to refine this type of oil and the transportation requirements. As such, the effect of material price decreases will more adversely affect the profitability of heavy oil production compared with lighter grades of oil.

We could lose all or part of our investment in McMoRan common stock.

We owned approximately 31.5% of the outstanding shares of common stock of McMoRan as of December 31, 2012. On December 5, 2012, Freeport-McMoRan agreed to acquire McMoRan for per share consideration consisting of $14.75 in cash and 1.15 units of a royalty trust, which will hold a 5% overriding royalty interest in future production from McMoRan’s existing ultra-deep exploration properties. In connection with the MMR Merger, on December 5, 2012, we entered into the Support Agreement with Freeport-McMoRan, pursuant to which we are generally required to, in our capacity as a stockholder of McMoRan, vote all of our shares of McMoRan common stock in favor of the MMR Merger and against alternative transactions and we are generally prohibited from transferring our shares of McMoRan common stock prior to the consummation of the MMR Merger. If the MMR Merger does not occur, the market price of shares of McMoRan common stock could decline substantially.

We do not control McMoRan’s assets and operations and, if the MMR Merger does not occur, the value of our investment in McMoRan’s common stock will be subject to all of the risks and uncertainties inherent in McMoRan’s business, which include, but are not limited to, the following:

• general economic and business conditions;

• variations in the market demand for, and prices of, oil and natural gas;

• drilling results;

• unanticipated fluctuations in flow rates of producing wells due to mechanical or operational issues (including those experienced by wells operated by third parties where McMoRan is a participant);

• oil and natural gas reserve expectations;

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• the potential adoption of new governmental regulations;

• the failure of third party partners to fulfill their commitments;

• the ability to hold current or future lease acreage rights;

• the ability to satisfy future cash obligations and environmental costs;

• adverse conditions, such as high temperatures and pressure that could lead to mechanical failures or increased costs;

• access to capital to fund drilling activities;

• other general exploration and development risks and hazards inherent in the production of oil and natural gas;

• tropical storms, hurricanes and other adverse weather conditions, which are common in the Gulf of Mexico during certain times of the year;

• the exercise of preferential rights by third parties; and

• other factors discussed in McMoRan’s Annual Report on Form 10-K and as are included from time to time in McMoRan’s public announcements and other filings with the SEC.

For the reasons described above, if the MMR Merger does not occur, we may not realize an adequate return on our investment and we may incur losses on sales of our investment. We have elected to measure our equity investment in McMoRan at fair value. As a result, unrealized gains and losses on the investment will be reported in our consolidated statement of income, which could result in volatility in our earnings. If we are required to write down the value of our investment, it could reduce our net income, result in losses and have a significant impact on our working capital. The value of our investment in shares of McMoRan common stock is subjective. Declines in the valuation of our investment may result in other than temporary impairments of this asset, which would lead to accounting charges that could have a material adverse effect on our net income and results of operations.

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

We use derivative instruments to manage our commodity price risk for a portion of our oil and gas production. This practice may prevent us from receiving the full advantage of increases in oil and gas prices above the maximum fixed amount specified in our derivative contracts. The derivative instruments also expose us to the risks of financial loss in a variety of circumstances, including when:

• a counterparty to the derivative contract is unable to satisfy its obligations;

• production is delayed or less than expected; or

• there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production.

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The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy.

See Item 7A – Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk for a summary of our current derivative positions. Since all of our derivative contracts are accounted for using mark-to-market accounting, we expect continued volatility in derivative gains or losses on our income statement as changes occur in the NYMEX and ICE price indices.

The adoption of derivatives legislation by Congress, and implementation of that legislation by federal agencies, could adversely impact our ability to engage in commodity price risk management activities.

On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act. The Dodd-Frank Act creates a new regulatory framework for federal oversight of derivatives transactions by the CFTC and the SEC and requires the CFTC, the SEC and other regulatory agencies to promulgate rules and regulations implementing the legislation, which they have done since late 2010 and are expected to continue to do well into 2013. From late 2010 and continuing to the present date, the CFTC has introduced dozens of proposed rules and has promulgated numerous final rules based on those proposals. The effect of the proposed and final rules and any additional regulations on our business is not yet entirely clear, but the costs of derivatives-based hedging for commodities will likely increase for all market participants.

The new regulations may require us to comply with certain margin requirements for our over-the-counter derivative contracts with certain CFTC- or SEC-registered entities that could require us to enter into credit support documentation and/or post significant amounts of cash collateral, which could adversely affect our liquidity and ability to use derivatives to hedge our commercial price risk; however, the proposed margin rules are not yet final and therefore the application of those provisions to us is uncertain at this time. The Dodd-Frank Act also contemplates that where appropriate in light of outstanding exposures, trading liquidity and other factors, swaps (broadly defined to include most hedging instruments other than futures) will be required to be cleared through a registered clearing facility and traded on a designated exchange or swap execution facility. On July 19, 2012, the CFTC adopted final regulations to govern the exception to the clearing requirement available to swap counterparties meeting certain conditions under the Commodity Exchange Act, as amended by the Dodd-Frank Act. This exception provides that the clearing requirement shall not apply to a swap if one of the counterparties to the swap (i) is not a financial entity, (ii) is using swaps to hedge or mitigate commercial risk and (iii) notifies the CFTC how it generally meets its financial obligations associated with entering into non-cleared swaps, the requirements together referred to as the End-user Exception. We must obtain approval from the Board of Directors and make certain filings in order to rely on this exception. In addition, although we believe that our trades will generally qualify for the End-user Exception, our derivatives counterparties to uncleared trades will be subject to new compliance and capital, margin and business conduct standards and any of their trades may also be subject to the clearing requirement which could have a material impact on our hedging activities resulting from increased transaction costs. Rules promulgated under the Dodd-Frank Act further defined forwards as well as instances where forwards may become swaps. Because the CFTC rules, interpretations, no-action letters, and case law are still developing, it is possible that some arrangements that previously qualified as forwards, spots, or energy service contracts may fall in the regulatory category of swaps or options. In addition, the CFTC’s rules applicable to trade options may further impose burdens on our ability to conduct our traditional hedging program and could become subject to CFTC investigations in the future.

In addition to the above, the CFTC promulgated final rules imposing federally-mandated position limits covering a wide range of derivatives positions, including non-exchange traded bilateral swaps

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related to commodities including oil and natural gas. These position limit rules were vacated by a Federal court in September 2012, and the CFTC has appealed that decision, and could re-promulgate the rules in a manner that addresses the defects identified by the court. If these position limit rules go into effect in the future, they are likely to increase regulatory monitoring and compliance costs for all market participants, even where a given trading entity is not in danger of breaching position limits. These and other regulatory developments stemming from the Dodd-Frank Act, including stringent new reporting requirements for derivatives positions, could have a material impact on our derivatives trading and hedging activities in the form of increased transaction costs and compliance responsibilities or make it more difficult for us to enter into hedging transactions on favorable terms. Any of the foregoing consequences could have a material adverse effect on our financial position, results of operations and cash flows and, specifically, our inability to enter into hedging transactions on favorable terms, or at all, could increase our operating expenses and put us at increased exposure to the risk of adverse changes in oil and natural gas prices, which could adversely affect the predictability of cash flows from sales of oil and natural gas.

We may be subject to risks in connection with acquisitions, including the Gulf of Mexico Acquisition, and other strategic transactions and the integration of significant acquisitions and other strategic transactions may be difficult.

We periodically evaluate potential acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:

• recoverable reserves;

• future oil and gas prices and their appropriate differentials;

• development and operating costs and potential environmental and other liabilities; and

• our ability to obtain external financing to fund the purchase price.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis, and, as is the case with certain liabilities associated with the properties acquired in the Gulf of Mexico Acquisition, we are entitled to only limited indemnification for environmental liabilities.

Significant acquisitions, including the Gulf of Mexico Acquisition, and other strategic transactions may involve other risks, including:

• diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

• the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;

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• difficulty associated with coordinating geographically separate assets;

• the challenge of attracting and retaining personnel associated with acquired operations; and

• the failure to realize the full benefit that we expect in estimated proved reserves and resource potential, production volume or other benefits anticipated from an acquisition, or to realize these benefits within the expected time frame and costs.

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our ongoing business could suffer.

As a result of the Gulf of Mexico Acquisition, we will have greater exposure to the substantial regulations and risks that affect our offshore operations, which could adversely affect our ability to operate and our financial results.

We currently conduct operations offshore California and in the U.S. Gulf of Mexico, and as a result of the Gulf of Mexico Acquisition, a substantially greater portion of our assets will be located in the U.S. Gulf of Mexico. Offshore oil and gas operations are subject to more extensive governmental regulation than our other oil and gas activities.

In addition, properties offshore Gulf of Mexico, including the Gulf of Mexico properties, are vulnerable to risks relating to:

• hurricanes and other adverse weather conditions;

• oilfield 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.

The Gulf of Mexico properties are located in the deeper waters of the U.S. Gulf of Mexico, where operations are more difficult and costly than in shallower waters or at onshore locations. The deeper waters in the Gulf of Mexico lack the physical and oilfield service infrastructure present in its shallower waters and could result in significant delays in obtaining or maintaining production from the assets. As a result, deepwater operations may require a significant amount of time between a discovery and the time that we can market our production, thereby increasing the risk involved with these operations.

In response to the Macondo incident, the BOEM/BSEE is expected to issue additional governmental regulation of the offshore exploration and production industry. Recent legislative proposals include limitations upon, or elimination of, existing liability caps, an increased minimum level of financial responsibility and additional safety and spill-response requirements. We cannot predict with any certainty what form the additional regulation or limitations will take. The impact upon our business of such regulations or limitations could include cost increases, offshore exploration and development activity delay, limitations on the ability to explore and acquire prospective leases, as well as changes in the availability and cost of insurance.

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The extent to which our business is subject to the risks described above increased as a result of the Gulf of Mexico Acquisition, and therefore our costs, ability to operate and financial results could be adversely affected.

A significant portion of our oil production is dedicated to one customer and as a result, our credit exposure to this customer is significant.

We entered into an oil marketing arrangement with Phillips 66 under which Phillips 66 purchases a significant portion of our oil production. We generally do not require letters of credit or other collateral to support these trade receivables. Accordingly, a material adverse change in the financial condition of Phillips 66 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, all of 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. In addition, we are self-insured for named windstorms in the Gulf of Mexico. 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, developing or exploring for oil and gas properties.

The successful acquisition 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

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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 development and exploration operations may not result in any increases in reserves. Our operations may be curtailed, delayed or canceled as a result of:

• increases in the costs of, or inadequate access to, capital or other factors, such as title problems;

• weather;

• compliance with governmental regulations or price controls;

• mechanical difficulties; or

• shortages or delays in the delivery of equipment.

In addition, 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 and 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 development activities. Future reserve increases and production may be dependent on our success in our exploration efforts, which may be unsuccessful.

Adverse capital and credit market conditions may significantly affect our ability to meet liquidity needs, access to capital and cost of capital.

There is potential for volatility and disruption in the capital and credit markets which could negatively impact our business, financial condition and results of operations, as well as our ability to access capital.

In recent years, there has been significant volatility within the global economy, particularly in certain countries of the European Union. Should these financial concerns continue to cause disruption, it may negatively impact stock price and credit capacity for certain issuers, even those without direct exposure to the affected countries and lending organizations.

The impairment of financial institutions could adversely affect us.

We have exposure to different counterparties, and we have entered into transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies, other investment funds and other institutions. These transactions expose us to credit risk in the event of default of our counterparties. Deterioration in the global economy and financial markets may impact the credit ratings of our current and potential counterparties, including those counterparties who may have exposure to certain European sovereign debt, and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to these financial institutions in the form of oil and gas derivative contracts, which protect our cash flows when commodity prices decline. During periods of low oil and gas prices, we may have significant exposure to our derivative counterparties and the value of our derivative positions may provide a significant amount of cash flow. We also maintain insurance policies with insurance companies to protect us against certain risks inherent in our business. In addition, if any lender under our credit facilities is unable to fund its commitment, our liquidity will be reduced by an

44

amount up to the aggregate amount of such lender’s commitment under our credit facilities. The commitments under our revolving line of credit and the Plains Offshore senior credit facility are from a diverse syndicate of 25 lenders. At December 31, 2012, no single lender’s commitments under both credit facilities combined represented more than 8% of our total commitments. However, if banks continue to consolidate, we may experience a more concentrated credit risk.

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 demand. 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 and processing for our production. Substantially all of our oil and gas production is transported by pipelines and trucks and/or processed in facilities owned by third parties. The inability or unwillingness of these parties to provide transportation and processing services to us for a reasonable fee could result in us having to find transportation and processing alternatives, increased transportation and processing 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.

Our asset carrying values may be impaired in future periods if oil and gas prices decline.

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

• the present value, discounted at 10%, of estimated future net cash flows from proved oil and gas reserves, net of estimated future income taxes; plus

• the cost of unproved properties not being amortized; plus

• the lower of cost or estimated fair value of unproved properties 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 twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials and require an impairment if our capitalized costs exceed this “ceiling”. For 2012, the twelve-month average of the first-day-of-the-month reference prices (prior to adjustment for location and quality differentials) was $94.71 per Bbl for oil and $2.76 per MMBtu for natural gas. At December 31, 2012, the ceiling with respect to our domestic oil and gas properties exceeded the net capitalized costs of those properties by approximately 19%.

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. We may be required to recognize non-cash pre-tax impairment charges in future reporting periods if market prices for oil or natural gas decline.

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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 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.

We are subject to certain regulations, some of which require permits and other approvals. These regulations could increase our costs and may terminate, delay 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. Certain of these regulations require permits for the drilling and operation of wells. The permits required for various aspects of our operations are subject to enforcement for noncompliance as well as revocation, modification and renewal by issuing authorities.

Existing laws and regulations, or their interpretations, could be changed, and any changes could increase costs of compliance and costs of operating drilling equipment, delay projects or significantly limit drilling activity.

Under certain circumstances, the BOEM/BSEE 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.

In addition, our real estate entitlement efforts are subject to regulatory approvals. Some of these regulatory approvals are discretionary by nature. The entitlement approval process is often a lengthy and complex procedure requiring, among other things, the submission of development plans and reports and presentations at public hearings. Because of the provisional nature of these procedures and the concerns of various environmental and public interest groups, our ability to entitle and realize future income from our surface properties could be delayed, prevented or made more expensive.

Regulations related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” may be contributing to the warming of the Earth’s atmosphere. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of refined oil products and natural gas, are examples of greenhouse gases. From time to time the U.S. Congress has considered climate-related legislation to reduce emissions of greenhouse gases. In addition, many states have developed measures to regulate emissions of greenhouse gases, primarily through the planned development of greenhouse gas emissions inventories and/or regional greenhouse gas Cap and Trade programs. In California, for example, the CARB has developed regulations pursuant to Assembly Bill 32 that are intended to achieve an overall reduction in greenhouse gas emissions to 1990 levels, a 15% reduction by 2020. Because several of our operations emit greenhouse gases in excess of 25,000 metric tons per year, various operations in California are subject to the requirements of this program. In October 2011 CARB adopted the final Cap and Trade regulation which is intended

46

to implement the Cap and Trade Program under Assembly Bill 32. The regulation established three separate three year compliance periods as follows: 2012 to 2014, 2015 to 2017 and 2018 to 2020. The regulation required regulated entities to “true up” their emission offset obligations by the end of each three-year obligation period. Due to time constraints on implementing the Cap and Trade Program, the regulation included a provision which would forego the requirement of regulated entities to surrender compliance instruments for their emissions the first year of the first compliance period. The first year which will require regulated entities to surrender compliance instruments will be for 2013 emissions, and we are in the process of acquiring our required allowances. Compliance with these regulations will require companies to periodically secure instruments known as offsets and allowances, each of which is equal to one metric ton of emissions under the Cap and Trade program. The price of these instruments will vary in accordance with market conditions. The total amount of instruments we owe will vary annually based on the total greenhouse gas emissions registered in any one year and the number of “free allowances” issued by CARB annually. These regulations increase our costs for those operations and adversely affect our operating results. The EPA has also adopted regulations imposing permitting and best available control technology requirements on the largest greenhouse gas stationary sources, regulations requiring reporting of greenhouse gas emissions from certain facilities and is considering additional regulation of greenhouse gases as “air pollutants” under the existing federal Clean Air Act. Passage of climate change legislation or other regulatory initiatives by Congress or various states, or the adoption of regulations by the EPA or analogous state agencies, that regulate or restrict emissions of greenhouse gases (including methane or carbon dioxide) in areas in which we conduct business could have an adverse effect on our operations and the demand for oil and natural gas.

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 historical 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 OPA; and

• controlling air emissions, preventing water contamination and unauthorized waste discharges.

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.

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Some of our onshore California fields have been in operation for more than 100 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. The Montebello field operates under a number of federal and California permits that are over and above what may be required in our other California facilities. The primary reason for the additional permits and associated restrictions on property use is the property’s location within what has been designated critical habitat for the federally threatened songbird, known as the California gnatcatcher, in accordance with Section 7 of the federal Endangered Species Act of 1973. 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.

Legislation and regulatory initiatives relating to hydraulic fracturing could increase our cost of doing business and adversely affect our operations.

Our operations utilize the practice of hydraulic fracturing for new oil and natural gas wells. Hydraulic fracturing is also occasionally used to recomplete or restimulate an existing well that has declined in production performance. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formation to stimulate oil and natural gas production. The use of hydraulic fracturing is necessary to produce commercial quantities of oil and natural gas from many reservoirs, especially shale formations such as the Haynesville Shale and the Eagle Ford Shale. The process is typically regulated by state oil and natural gas commissions and agencies, and continues to receive significant regulatory and legislative attention at the federal, state, and local level. On May 11, 2012, the BLM proposed regulations that would require public disclosure of the chemicals used in hydraulic fracturing and impose certain permitting, testing and other requirements on such operations on federal lands, although the BLM announced on January 18, 2013 that it would revise and reissue these regulations at a later time. Various other federal agencies (including the EPA and the Department of Energy) continue to study hydraulic fracturing and may propose additional regulations. From time to time, legislation has been introduced in Congress to amend the federal SDWA to eliminate exemptions for most hydraulic fracturing activities. On August 16, 2012, the EPA published final rules that establish new air emission controls for natural gas and natural gas liquids production, processing and transportation activities, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants frequently associated with production and processing activities. Similar efforts to review the practice of hydraulic fracturing and impose new regulatory conditions are taking place at the state and local level in states where we operate and may operate in the future. California, Texas and Wyoming as well as other states have adopted or are considering new regulations and statutes pertaining to hydraulic fracturing. These new requirements will (and future regulatory and legislative changes, if enacted, could) create new permitting and financial assurance requirements, require us to adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping obligations, and meet plugging and abandonment requirements. The imposition of stringent new regulatory and permitting requirements related to the practice of hydraulic fracturing could significantly increase our cost of doing business, create adverse effects on our operations including creating delays related to the issuance of permits, and depending on the specifics of any particular proposal that is enacted, could be material.

Furthermore, multiple lawsuits have been filed against regulatory agencies throughout the country by non-profit environmental organizations seeking to challenge various rules and regulations related to the practice of hydraulic fracturing and permitting of new wells completed with hydraulic fracturing. Some of these lawsuits have been filed in states where we operate, including California. The resolution

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of these lawsuits could create new permitting or regulatory requirements, which could have an effect on our business.

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

As of December 31, 2012, we had leases on approximately 59,000 net acres in the Eagle Ford Shale area. Over 50% of our acreage in the Eagle Ford Shale is currently held by production or held by operations. Unless production in paying quantities is established on units containing these leases during their terms, the leases will expire. If our leases expire and we are unable to renew the leases, we will lose our right to develop the related properties. Our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Further, since we do not operate portions of the Eagle Ford Shale acreage, we have limited impact upon the drilling schedule for those leases.

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 fair value of the liabilities assumed (including deferred income taxes recorded in connection with the transaction) over the fair value of the assets acquired. At December 31, 2012, goodwill totaled $535 million and represented approximately 3% of our total assets.

Goodwill is not amortized; instead it is tested at least annually for impairment at a level of reporting referred to as a reporting unit. Impairment occurs when the carrying amount of goodwill exceeds its implied fair value. 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 equity.

See Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates – Goodwill.

We face strong competition.

We face strong competition in all aspects of our business. Competition is particularly intense for prospective undeveloped leases and purchases of proved oil and gas reserves. There is also competition for the rigs and related equipment and services that are necessary for us to develop and operate our oil and natural gas properties. Our competitive position is also highly dependent on our ability to recruit and retain geological, geophysical and engineering expertise. We compete for prospects, proved reserves, field services and qualified oil and gas professionals with major and diversified energy companies. Many of our larger competitors may be able to more successfully define, evaluate, bid for and purchase properties and prospects than us.

Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

Among the changes expected to be contained in the Obama Administration’s Fiscal Year 2014 budget proposal when it is released is the elimination or deferral of certain U.S. federal income tax deductions and credits currently available to oil and gas exploration companies. Such changes are expected to include, but may not be limited to, (i) the elimination of current deductions for intangible drilling and development costs; (ii) the elimination of the deduction for certain U.S. production activities for oil and gas properties; (iii) an extension of the amortization period for certain geological and

49

geophysical expenditures and (iv) the repeal of the enhanced oil recovery credit. Some of these same proposals to repeal or limit oil and gas tax deductions and credits have been included in recent legislation that has been considered by Congress. It is unclear whether any such changes will be enacted or how soon such changes could be effective. The passage of any legislation as a result of the ultimate budget proposal, or the passage of bills containing similar changes in U.S. federal income tax law could eliminate or defer certain tax deductions and credits that are currently available with respect to oil and gas exploration and development and could negatively affect our financial results.

We have limited control over the activities on properties we do not operate.

Some of our properties, including our Haynesville Shale acreage, portions of our Eagle Ford Shale acreage, the Ram Powell Field and the Diana and Hoover Fields, in which we have an interest are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. Approximately 20% of our 2013 capital budget is allocated to properties we do not operate. These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur unexpected future costs, result in lower production and materially and adversely affect our financial condition and results of operations.

The high cost or unavailability of drilling rigs, equipment, supplies and other oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could have an adverse effect on our business, financial condition or results of operations.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment or supplies. During these periods, the costs of rigs, equipment and supplies are substantially greater and their availability may be limited. Additionally, these services may not be available on commercially reasonable terms. The high cost or unavailability of drilling rigs, equipment, supplies, personnel and other oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could have an adverse effect on our business, financial condition or results of operations.

An adverse cyber security incident, if enacted upon us or our business partners, could comprise proprietary information or disrupt our normal business operations.

Our business may also be impacted by information technology disruptions. Cyber security incidents, in particular, are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and other electronic security breaches that could lead to disruptions in systems, unauthorized release of confidential or otherwise protected information and the corruption of data. We believe that we have implemented appropriate measures to mitigate potential risks to our technology and our operations from these information technology disruptions. However, given the unpredictability of the timing, nature and scope of information technology disruptions, we could potentially be subject to production downtimes, operational delays, the compromising of confidential or otherwise protected information, destruction or corruption of data, security breaches, other manipulation or improper use of our systems and networks or financial losses from remedial actions, any of which could have a materially adverse effect on our business, financial condition or results of operations.

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Item 1B.  Unresolved Staff Comments

Not applicable.

Item 3.  Legal Proceedings

On December 5, 2012, the Company entered into the Freeport-McMoRan Merger Agreement with Freeport-McMoRan and the Merger Sub, pursuant to which Freeport-McMoRan will acquire the Company. On December 5, 2012, Freeport-McMoRan agreed to acquire McMoRan. Between December 11, 2012 and December 20, 2012, three putative class actions challenging the merger were filed on behalf of PXP stockholders in the Court of Chancery of the State of Delaware: Rice v. Plains Exploration & Production Co. et al., No. 8090-VCN, filed on December 11, 2012; MARTA/ATU Local 732 Employees Retirement Plan v. Plains Exploration & Production Co. et al., No. 8135-VCN, filed on December 20, 2012; and Louisiana Municipal Police Employees’ Retirement System v. Arnold et al., No. 8141-VCN, also filed on December 20, 2012. The actions name as defendants PXP, the directors of PXP, Freeport-McMoRan, and a Freeport-McMoRan subsidiary. The actions allege that PXP’s directors breached their fiduciary duties because they, among other things, pursued their own interests at the expense of stockholders and failed to maximize stockholder value with respect to the merger, and that Freeport-McMoRan and a Freeport-McMoRan subsidiary aided and abetted the breach of fiduciary duties by PXP’s directors. The actions seek as relief an injunction barring or rescinding the merger, damages, and attorneys’ fees and costs. On January 7, 2013, the MARTA/ATU Local 732 Employees Retirement Plan action was voluntarily dismissed by the plaintiff. On January 15, 2013, the Court of Chancery of the State of Delaware entered an order consolidating the two remaining actions under the caption In re Plains Exploration & Production Company Stockholder Litigation, No. 8090-VCN, and appointing co-lead counsel for the plaintiffs.

In addition, thirteen derivative actions challenging both the merger and the MMR Merger have been filed on behalf of Freeport-McMoRan by purported Freeport-McMoRan stockholders. Ten of these actions were filed in the Court of Chancery of the State of Delaware: Jacksonville Police & Fire Pension Fund v. Moffett et al., No. 8110-VCN, filed on December 14, 2012; Sklar v. Moffett et al., No. 8126-VCN, filed on December 19, 2012; Gaines v. Adkerson et al., No. 8139-VCN, filed on December 20, 2012; Rosenzweig v. Adkerson et al., No. 8140-VCN, filed on December 20, 2012; Lang v. Moffett et al., No. 8142-VCN, filed on December 21, 2012; Dauphin County Employee Retirement Fund v. Moffett et al., No. 8145-VCN, filed on December 21, 2012; Anthony Newman v. James R. Moffett, et al., No. 8156-VCN, filed on December 28, 2012; State-Boston Retirement System v. Moffett, et al., C.A. No. 8206-VCN, filed on January 11, 2013; Inter-Local Pension Fund of the Graphic Communications Conference of the International Brotherhood of Teamsters v. Moffett, et al., C.A. No. 8207-VCN, filed on January 11, 2013; and United Wire Metal and Machine Pension Fund v. Moffett, et al., C.A. No. 8208-VCN, filed on January 11, 2013. Three were filed in the Superior Court of the State of Arizona, County of Maricopa: Liberatore v. Moffett et al., No. CV2012-018351, filed on December 14, 2012; Teich et al. v. Moffett et al., No. CV2012-018403, filed on December 17, 2012; and Jeffery Harris v. Richard C. Adkerson, et al., CV2013-004163, filed on January 16, 2013. The actions name some or all of the following as defendants: the directors of Freeport-McMoran, two Freeport-McMoRan subsidiaries, PXP, McMoRan, James C. Flores, John F. Wombwell, Suzanne T. Mestayer, and Kathleen L. Quirk. The actions allege that the Freeport-McMoran directors breached their fiduciary duties because they, among other things, pursued their own interests at the expense of Freeport-McMoran stockholders in approving the merger and the MMR Merger, and further allege that some or all of the other defendants aided and abetted such breaches of fiduciary duties. The actions seek as relief, among other things, an injunction barring or rescinding both the merger and the MMR Merger and requiring submission of the proposed merger and MMR Merger to a vote of Freeport-McMoran stockholders, damages, and attorneys’ fees and costs. On January 25, 2013, the Court of Chancery of the State of Delaware entered an order consolidating the ten actions pending in that court

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under the caption In re Freeport-McMoRan Copper & Gold Inc. Derivative Litigation, No. 8145-VCN, and appointing co-lead counsel for the plaintiffs.

In addition, ten putative class actions challenging the MMR Merger have been filed on behalf of McMoRan stockholders. Nine of these actions were filed in the Court of Chancery of the State of Delaware: Krieger v. McMoRan Exploration Co. et al., No. 8091-VCN, filed December 11, 2012; Steven Kosoff IRA v. McMoRan Exploration Co. et al., No. 8100-VCN, filed December 12, 2012; Barasch v. McMoRan Exploration Co. et al., No. 8106-VCN, filed December 13, 2012; Berstein v. Moffett et al., No. 8107-VCN, filed December 13, 2012; Curalov v. McMoRan Exploration Co. et al., No. 8115-VCN, filed December 17, 2012; Purnell et al. v. Adkerson et al., No. 8117-VCN, filed December 17, 2012; Yagoobian v. McMoRan Exploration Co. et al., No. 8128-VCN, filed December 19, 2012; Davis v. McMoRan Exploration Co. et al., No. 8132-VCN, filed December 20, 2012; and Seidlitz v. Adkerson et al., No. 8151-VCN, filed December 26, 2012. One was filed in the Civil District Court for the Parish of Orleans of the State of Louisiana: Langley v. Moffett et al., No. 2012-11904, filed December 19, 2012. Each of the actions names the McMoRan directors as defendants, as well as some or all of the following: Freeport-McMoran, subsidiaries of Freeport-McMoran, and PXP. The actions allege that McMoRan’s directors breached their fiduciary duties in approving the MMR Merger, and further allege that some or all of the other defendants aided and abetted such breaches of fiduciary duties. One of the lawsuits also asserts derivative claims on behalf of McMoRan. The actions seek, among other things, injunctive relief barring or rescinding the MMR Merger, damages, and attorneys’ fees and costs. On January 9, 2013, the Krieger action was voluntarily dismissed by the plaintiff. On January 25, 2013, the Court of Chancery of the State of Delaware entered an order consolidating the remaining eight actions pending in that court under the caption In re McMoRan Exploration Co. Stockholder Litigation, No. 8132-VCN, and appointing co-lead counsel for the plaintiffs.

A hearing has been scheduled in the Court of Chancery of the State of Delaware for April 5, 2013, at which time the court will hear oral argument on the injunctive relief requested in each of the three consolidated actions described above.

The PXP defendants believe the lawsuits are without merit and intend to defend vigorously against them.

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

Item 4.  Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market For Registrant’s Common Equity, 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 sales prices for our common stock as reported on the New York Stock Exchange Composite Tape for the periods indicated below:

	High		Low
2012
1st Quarter	$	47.13	$	35.65
2nd Quarter		43.81		30.12
3rd Quarter		42.34		34.95
4th Quarter		47.09		32.31
2011
1st Quarter	$	40.06	$	31.90
2nd Quarter		38.72		32.61
3rd Quarter		41.96		22.27
4th Quarter		37.21		20.25

At January 31, 2013, we had approximately 2,264 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, reduce our debt, repurchase shares of our common stock and for general corporate purposes. Our Board of Directors has the authority to declare and pay dividends on our common stock at their discretion, as long as we have funds legally available to do so. As discussed in Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Financing Activities, our revolving line of credit and indentures restrict our ability to pay cash dividends.

Issuer Purchases of Equity Securities

On December 17, 2007, we announced that our Board of Directors had authorized the repurchase of up to $1.0 billion of PXP common stock from time to time in open market transactions or privately negotiated transactions at our discretion, subject to market conditions and other factors. In January 2012, we repurchased 2.4 million common shares at an average cost of $37.02, totaling $88.5 million. Subsequent to these repurchases, our Board of Directors reset the authorization to $1.0 billion of PXP common stock and extended the program until January 2016.

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Item 6. Selected Financial Data

The following selected financial information was derived from our consolidated financial statements, including the consolidated balance sheet at December 31, 2012 and 2011 and the related consolidated statements of income and cash flows for each of the three years in the period ended December 31, 2012 and the notes thereto, appearing elsewhere in this report. You should read this information in conjunction with Item 7 – 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,
	2012 (1)			2011 (2)			2010 (3)			2009			2008 (4)
Income Statement Data
Revenues	$	2,565,307		$	1,964,488		$	1,544,595		$	1,187,130		$	2,403,471
Costs and Expenses
Production costs		632,452			558,975			451,902			423,967			626,428
General and administrative		199,173			134,044			136,437			144,586			153,306
Depreciation, depletion, amortization and accretion		1,118,052			681,655			551,118			421,580			621,484
Impairment of oil and gas properties (5)		-			-			59,475			-			3,629,666
Legal recovery		-			-			(8,423	)		(87,272	)		-
Other operating (income) expense		(27	)		(735	)		(4,130	)		2,136			-
		1,949,650			1,373,939			1,186,379			904,997			5,030,884
Income (Loss) from Operations		615,657			590,549			358,216			282,133			(2,627,413	)
Other Income (Expense)
Gain on sale of assets (6)		-			-			-			-			65,689
Interest expense		(297,539	)		(161,316	)		(106,713	)		(73,811	)		(116,991	)
Debt extinguishment costs (7)		(8,388	)		(120,954	)		(1,189	)		(12,093	)		(18,256	)
(Loss) gain on mark-to-market derivative contracts (8)		(2,879	)		81,981			(60,695	)		(7,017	)		1,555,917
Gain (loss) on investment measured at fair value (9)		206,552			(52,675	)		(1,551	)		-			-
Other income (expense)		694			3,356			15,942			27,968			(12,575	)
Income (Loss) Before Income Taxes		514,097			340,941			204,010			217,180			(1,153,629	)
Income tax benefit (expense)
Current		4,102			25,952			93,090			(45,091	)		(230,815	)
Deferred		(175,412	)		(160,214	)		(193,835	)		(35,784	)		675,350
Net Income (Loss)		342,787			206,679		$	103,265		$	136,305		$	(709,094	)
Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary		(36,367	)		(1,400	)
Net Income Attributable to Common Stockholders	$	306,420		$	205,279
Earnings (Loss) per Common Share
Basic	$	2.36		$	1.45		$	0.74		$	1.10		$	(6.52	)
Diluted	$	2.32		$	1.44		$	0.73		$	1.09		$	(6.52	)
Weighted Average Common Shares Outstanding
Basic		129,925			141,227			140,438			124,405			108,828
Diluted		131,867			142,999			141,897			125,288			108,828

Table continued on following page.

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	Year Ended December 31,
	2012 (1)			2011 (2)			2010 (3)			2009			2008 (4)
Cash Flow Data
Net cash provided by operating activities	$	1,330,791		$	1,110,755		$	912,470		$	499,046		$	1,371,409
Net cash used in investing activities		(7,703,255	)		(1,154,591	)		(1,575,308	)		(1,280,399	)		(227,790	)
Net cash provided by (used in) financing activities		6,133,931			456,500			667,413			471,337			(857,190	)
	As of December 31,
	2012 (1)			2011 (2)			2010 (3)			2009			2008 (4)
Balance Sheet Data
Assets
Cash and cash equivalents	$	180,565		$	419,098		$	6,434		$	1,859		$	311,875
Other current assets		1,659,165			1,022,279			396,453			304,776			1,164,566
Property and equipment, net		14,728,800			7,725,295			7,220,752			6,832,722			4,513,396
Goodwill		535,140			535,140			535,144			535,237			535,265
Investment (9)		-			-			664,346			-			-
Other assets		194,613			89,660			71,808			60,137			586,813
	$	17,298,283		$	9,791,472		$	8,894,937		$	7,734,731		$	7,111,915
Liabilities and Equity
Current liabilities	$	980,001		$	626,186		$	533,689		$	682,551		$	993,645
Long-term debt		9,979,369			3,760,952			3,344,717			2,649,689			2,805,000
Other long-term liabilities		611,904			247,205			278,516			269,762			191,534
Deferred income taxes		1,770,568			1,461,897			1,355,050			933,748			744,456
Stockholders’ equity		3,516,478			3,264,636			3,382,965			3,198,981			2,377,280
Noncontrolling interest Preferred stock of subsidiary		439,963			430,596			-			-			-
	$	17,298,283		$	9,791,472		$	8,894,937		$	7,734,731		$	7,111,915

(1) Reflects the November 2012 Gulf of Mexico Acquisition.

(2) Reflects the December 2011 divestiture of interests in our Texas Panhandle and South Texas conventional natural gas properties.

(3) Reflects the December 2010 divestiture of our interest in all of our Gulf of Mexico leasehold located in less than 500 feet of water and the acquisition of the oil and gas properties in the Eagle Ford Shale oil and gas condensate windows during the fourth quarter of 2010.

(4) Reflects the February 2008 divestiture of 50% of our working interest in the Permian and Piceance Basins and all of our working interests in the San Juan Basin and Barnett Shale, the April 2008 acquisition of the South Texas properties and the December 2008 divestiture of our remaining interests in the Permian and Piceance Basins.

(5) During 2010, the costs related to our Vietnam oil and gas properties not subject to amortization were transferred to our Vietnam full cost pool where they were subject to the ceiling limitation. Because our Vietnam full cost pool had no associated proved oil and gas reserves, we recorded a non-cash pre-tax impairment charge of $59.5 million. At December 31, 2008, our capitalized costs of oil and gas properties exceeded the full cost ceiling and we recorded an impairment of oil and gas properties.

(6) Represents the gain on the sale of our investment in Collbran Valley Gas Gathering, LLC.

(7) During 2011, we recognized $121.0 million of debt extinguishment costs, including $30.9 million in unamortized debt issue costs and original issue discount, in connection with our debt retirement transactions.

(8) The derivative instruments we have in place are not classified as hedges for accounting purposes. 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.

(9) Our investment is measured at fair value with gains and losses recognized on the income statement. Our investment was classified as a current asset at December 31, 2012 and December 31, 2011.

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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

Plains Exploration & Production Company, a Delaware corporation formed in 2002, is an independent energy company engaged in the upstream oil and gas business. The upstream business acquires, develops, explores for and produces oil and gas. Our upstream activities are located in the United States. We own oil and gas properties with principal operations in:

• Onshore California;

• Offshore California;

• the Gulf of Mexico;

• the Gulf Coast Region; and

• the Rocky Mountains.

Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities, as well as newer properties with development and exploration potential. We believe our balanced portfolio of assets and our ongoing risk management program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities, including the Eagle Ford Shale, Gulf of Mexico, California and Haynesville Shale. As of December 31, 2012, we had estimated proved reserves of 440.4 MMBOE, of which 82% was comprised of oil and 63% was proved developed. Our primary sources of liquidity are cash generated from our operations, our revolving line of credit and periodic public offerings of debt and equity.

Our assets include 51.0 million shares of McMoRan common stock, approximately 31.5% of its common shares outstanding. We measure our equity investment at fair value. Unrealized gains and losses on the investment are reported in our income statement and could result in volatility in our earnings. See Item 7A – Quantitative and Qualitative Disclosures About Market Risk – Equity Price Risk.

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 various derivative instruments to manage our exposure to commodity price risk. This practice may prevent us from receiving the full advantage of increases in oil and gas prices above the maximum fixed amount specified in the derivative contracts and subjects us to the credit risk of the counterparties to such contracts. Since all of our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in gains and losses on mark-to-market derivative contracts in our income statement as changes occur in the NYMEX and ICE price indices. The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy. See Item 7A – Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk.

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Recent Developments

Proposed Merger with Freeport-McMoRan

On December 5, 2012, the Company entered into the Freeport-McMoRan Merger Agreement with Freeport-McMoRan and the Merger Sub, pursuant to which Freeport-McMoRan will acquire the Company for approximately $6.9 billion in cash and stock, based on the closing price of Freeport-McMoRan stock on December 4, 2012.

The Freeport-McMoRan Merger Agreement provides that the Company will merge with and into the Merger Sub, with the Merger Sub continuing as the surviving company and a wholly owned subsidiary of Freeport-McMoRan. Subject to the terms and conditions of the Freeport-McMoRan Merger Agreement, PXP stockholders have the right to receive 0.6531 shares of Freeport-McMoRan common stock and $25.00 in cash, equivalent to total consideration of $50.00 per PXP share, based on the closing price of Freeport-McMoRan stock on December 4, 2012. PXP stockholders may elect to receive cash or stock consideration, subject to proration in the event of oversubscription, with the value of the cash and stock per share consideration to be equalized at closing.

The Freeport-McMoRan Merger Agreement provides that each share of restricted stock and each stock-settled restricted stock unit, or stock-settled RSU, including each stock-settled RSU that will become issuable or creditable in connection with the consummation of the merger pursuant to any employment agreement, RSU agreement or other written agreement, will become fully vested and be converted into the right to receive, at the election of the holder, cash consideration or stock consideration to be paid or provided at the time contemplated by the original award agreement, except for certain stock-settled RSUs held by the Company’s named executive vice presidents that will convert into stock consideration (with right to elect up to 25% as cash consideration), and certain stock-settled RSUs held by Mr. Flores that will automatically convert into stock consideration, in each case pursuant to the terms of the executive’s respective letter agreement among each named executive officer, Freeport-McMoRan and the Company. Each cash-settled restricted stock unit, or cash-settled RSU, will become fully vested in accordance with the terms of the applicable award agreement and be converted into the right to receive cash consideration, payable at such time as the cash per-share consideration is payable generally to PXP stockholders who elect to receive cash consideration. Stock appreciation rights, or SARs, relating to shares of PXP common stock outstanding and unexercised will become fully vested and be converted into SARs relating to shares of Freeport-McMoRan common stock.

The Freeport-McMoRan Merger Agreement provides that, upon termination of the Freeport-McMoRan Merger Agreement under certain circumstances, the Company may be required to reimburse Freeport-McMoRan for its expenses in an amount up to $69.0 million and/or pay Freeport-McMoRan a termination fee in an amount equal to $207.0 million less any expenses reimbursed by the Company.

Completion of the merger is subject to customary conditions, including approval by PXP stockholders and receipt of required regulatory approvals. The merger is expected to close in the second quarter of 2013.

On December 5, 2012, Freeport-McMoRan agreed to acquire McMoRan for per share consideration consisting of $14.75 in cash and 1.15 units of a royalty trust, which will hold a 5% overriding royalty interest in future production from McMoRan’s existing ultra-deep exploration properties. In connection with the MMR Merger, on December 5, 2012, we entered into the Support Agreement with Freeport-McMoRan, pursuant to which we are generally required to, in our capacity as a stockholder of McMoRan, vote all of our shares of McMoRan common stock in favor of the MMR Merger and against alternative transactions and we are generally prohibited from transferring our shares of McMoRan common stock

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prior to the consummation of the MMR Merger. The Support Agreement will terminate upon the earlier of (i) the Expiration Date (defined as the earlier of (A) the consummation of the MMR Merger and (B) the termination of the MMR Merger Agreement) and (ii) any breach by Freeport-McMoRan of its obligation under the Freeport-McMoRan Merger Agreement not to change the merger consideration in the MMR Merger Agreement, amend the covenant relating to standstill waivers in the MMR Merger Agreement or otherwise materially amend any material provision of the MMR Merger Agreement, or terminate the MMR Merger Agreement, without PXP’s prior written consent.

Gulf of Mexico Acquisition

During the fourth quarter of 2012, we completed the acquisition of certain oil and gas interests in and near the Holstein, Diana, Hoover, Horn Mountain, Marlin, Dorado, King and Ram Powell Fields located in the Gulf of Mexico from BP, subject to customary post-closing adjustments. After pre-closing adjustments from the effective date of October 1, 2012, which resulted in a reduction to the $5.55 billion purchase price of approximately $191.0 million, we paid $5.36 billion in cash, which included the deposit of $555.0 million previously paid to BP. In December 2012, we recorded a net reduction of approximately $45.0 million to the purchase price primarily associated with oil and gas revenues between the effective and closing dates.

During the fourth quarter of 2012, we also completed the acquisition of the 50% working interest in the Holstein Field located in the Gulf of Mexico from Shell, subject to customary post-closing adjustments. After pre-closing adjustments from the effective date of October 1, 2012, which resulted in a reduction to the $560.0 million purchase price of approximately $27.9 million, we paid $532.1 million in cash.

We funded the Gulf of Mexico Acquisition primarily with our revolving line of credit and term loan credit facilities, collectively the Amended Credit Facility, and the issuance of Senior Notes as described below.

6 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes

In October 2012, we issued (i) $1.5 billion of 6 ¹/₂% Senior Notes due 2020, or the 6 ¹/₂% Senior Notes, and (ii) $1.5 billion of 6 ⁷/₈% Senior Notes due 2023, or the 6 ⁷/₈% Senior Notes, both at par. We received approximately $2.95 billion of net proceeds, after deducting the underwriting discount and offering expenses. We used the net proceeds to pay a portion of the cash consideration for the Gulf of Mexico Acquisition and to reduce indebtedness outstanding under our revolving line of credit.

Derivatives

During the fourth quarter of 2012, we entered into Brent crude oil put option spread contracts on 59,000 BOPD for 2015 with a floor price of $90 per barrel, a limit of $70 per barrel and weighted average deferred premium and interest of $6.960 per barrel.

Offshore Morocco Exploration

In January 2013, we announced we entered into a definitive agreement to participate in an exploration program offshore the Kingdom of Morocco. Subject to customary closing conditions, including the receipt of Moroccan governmental approvals (expected in the first half of 2013), we will make a cash payment of $15.0 million to farm-in to Pura Vida Energy’s 75% working interest in the approximate 2.7 million acre Mazagan permit area in the Essaouira Basin offshore Morocco. We will earn a 52% working interest and act as operator in exchange for funding 100% of the costs of certain specified exploration activities that will include a commitment to fund and drill two wells, and if agreed,

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various additional exploration operations subject to a maximum of $215.0 million. The first exploration well is expected to be drilled in 2014.

General

We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration 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. The markets for oil and gas have historically 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 twelve-month average first-day-of-the-month reference prices as adjusted for location and quality differentials to determine a ceiling value of our properties. These prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including derivative contracts that qualify and are designated for hedge accounting treatment. The derivative instruments we have in place are not classified as hedges for accounting purposes. The rules require an impairment if our capitalized costs exceed the allowed “ceiling”. For further discussion, see Critical Accounting Policies and Estimates. At December 31, 2012, the ceiling with respect to our domestic oil and gas properties exceeded the net capitalized costs of those properties by approximately 19%.

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 in the future, impairments of our oil and gas properties could occur. Impairment charges required by these rules do not directly impact our cash flows from operating activities.

Our oil and gas production expenses include salaries and benefits of personnel involved in production activities (including stock-based compensation), steam gas costs, electricity costs, maintenance costs, production, ad valorem and severance taxes, gathering and transportation costs and other costs necessary to operate our producing properties. Depreciation, depletion and amortization, or DD&A, for producing oil and gas properties is calculated using the units of production method based upon estimated proved reserves. For the purposes of computing DD&A, estimated proved reserves are redetermined as of the end of each year and on an interim basis when deemed necessary.

General and administrative expense, or G&A, consists primarily of salaries and related benefits of administrative personnel (including stock-based compensation), office rent, systems costs and other administrative costs.

Results Overview

For the year ended December 31, 2012, we reported net income attributable to common stockholders of $306.4 million, on total revenues of $2,565.3 million. This compares to net income attributable to common stockholders of $205.3 million, on total revenues of $1,964.5 million for the year ended December 31, 2011, and net income of $103.3 million, on total revenues of $1,544.6 million for the year ended December 31, 2010.

Significant transactions that affect comparisons between the periods include the Gulf of Mexico Acquisition in the fourth quarter of 2012, the divestment of our Panhandle and South Texas properties in the fourth quarter of 2011, the divestment of our U.S. Gulf of Mexico shallow water shelf properties to McMoRan and the acquisition of our Eagle Ford Shale properties during the fourth quarter of 2010.

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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,
	2012		2011		2010
Sales Volumes
Oil and liquids sales (MBbls)		24,365		17,872		16,769
Gas (MMcf)
Production		88,472		111,577		95,047
Used as fuel		1,362		2,108		1,954
Sales		87,110		109,469		93,093
MBOE
Production		39,110		36,468		32,610
Sales		38,883		36,117		32,285
Daily Average Volumes
Oil and liquids sales (Bbls)		66,571		48,964		45,943
Gas (Mcf)
Production		241,726		305,691		260,402
Used as fuel		3,721		5,776		5,353
Sales		238,005		299,915		255,049
BOE
Production		106,859		99,912		89,343
Sales		106,239		98,950		88,451
Unit Economics (in dollars)
Average Index Prices
ICE Brent Price per Bbl	$	111.63	$	110.85	$	80.36
NYMEX Price per Bbl		94.15		95.11		79.61
NYMEX Price per Mcf		2.79		4.04		4.38
Average Realized Sales Price
Before Derivative Transactions
Oil (per Bbl)	$	95.46	$	85.53	$	68.14
Gas (per Mcf)		2.67		3.91		4.29
Per BOE		65.79		54.18		47.77
Costs and Expenses per BOE Production costs
Lease operating expenses	$	10.12	$	9.27	$	8.13
Steam gas costs		1.22		1.81		2.06
Electricity		1.13		1.14		1.33
Production and ad valorem taxes		1.90		1.53		0.91
Gathering and transportation		1.90		1.72		1.57
DD&A (oil and gas properties)		27.62		17.76		15.87

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

	Year Ended December 31,
	2012			2011			2010
Oil derivatives
Settlements	$	(8,060	)	$	(60,392	)	$	(67,917	)
Unwind of crude oil puts		-			(2,935	)		-
Natural gas derivatives		50,954			7,915			37,996
	$	42,894		$	(55,412	)	$	(29,921	)

Comparison of Year Ended December 31, 2012 to Year Ended December 31, 2011

Oil and gas revenues.    Oil and gas revenues increased $601.5 million, to $2,558.4 million for 2012 from $1,956.9 million for 2011, primarily due to higher oil sales volumes and average realized prices partially offset by lower average realized gas prices and sales volumes.

Oil revenues increased $797.2 million, to $2,325.9 million for 2012 from $1,528.7 million for 2011, reflecting higher sales volumes ($619.8 million) and average realized prices ($177.4 million). Oil sales volumes increased 17.6 MBbls per day to 66.6 MBbls per day in 2012 from 49.0 MBbls per day in 2011, primarily reflecting increased production from our Gulf of Mexico Acquisition in November 2012 and our Eagle Ford Shale properties, partially offset by a production decrease due to the divestment of our Panhandle properties in December 2011. Excluding the impact of our divestments, production increased 23.2 MBbls per day in 2012. This includes 1,878.6 MBbls attributable to our Gulf of Mexico Acquisition from November 30, 2012 through year end. Our average realized price for oil increased $9.93 per Bbl to $95.46 per Bbl for 2012 from $85.53 per Bbl for 2011. The increase was primarily attributable to our new marketing contract effective January 1, 2012 for our California crude oil production that replaces the percent of NYMEX index pricing with prices based upon regional benchmarks. The average ICE Brent index price for 2012 was $111.63 per Bbl compared to the average NYMEX index price of $95.11 per Bbl for 2011.

Gas revenues decreased $195.8 million, to $232.4 million in 2012 from $428.2 million in 2011, reflecting lower average realized prices ($136.1 million) and sales volumes ($59.7 million). Our average realized price for gas was $2.67 per Mcf in 2012 compared to $3.91 per Mcf in 2011. Gas sales volumes decreased 61.9 MMcf per day to 238.0 MMcf per day in 2012 from 299.9 MMcf per day in 2011, primarily reflecting our Panhandle and South Texas properties divested in December 2011, partially offset by increased production from our Eagle Ford Shale properties. Excluding the impact of our divestments, sales increased 10.9 MMcf per day in 2012. This includes 1,261.0 MMcf attributable to our Gulf of Mexico Acquisition from November 30, 2012 through year end.

Lease operating expenses.    Lease operating expenses increased $58.6 million, to $393.5 million in 2012 from $334.9 million in 2011, reflecting increased production primarily at our Eagle Ford Shale properties, our Gulf of Mexico Acquisition, increased well workover expense primarily at our California properties and increased diesel fuel cost at our Point Arguello platforms, partially offset by our Panhandle and South Texas properties divested in December 2011.

Steam gas costs.    Steam gas costs decreased $18.2 million, to $47.3 million in 2012 from $65.5 million in 2011, primarily reflecting lower cost of gas used in steam generation. In 2012, we burned approximately 16.4 Bcf of natural gas at a cost of approximately $2.88 per MMBtu compared to 16.5 Bcf at a cost of approximately $3.96 per MMBtu in 2011.

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Production and ad valorem taxes.    Production and ad valorem taxes increased $18.7 million, to $73.9 million in 2012 from $55.2 million in 2011, reflecting increased production taxes due to increased production from our Eagle Ford Shale properties, partially offset by our Panhandle and South Texas properties divested in December 2011.

Gathering and transportation expenses.    Gathering and transportation expenses increased $11.8 million, to $73.9 million in 2012 from $62.1 million in 2011, primarily reflecting an increase in production from our Eagle Ford Shale properties, partially offset by our Panhandle properties divested in December 2011.

General and administrative expense.    G&A expense increased $65.2 million, to $199.2 million in 2012 from $134.0 million in 2011, primarily due to costs associated with the Gulf of Mexico Acquisition and proposed merger with Freeport-McMoRan, increased headcount and related personnel costs and greater stock-based compensation expense resulting from an increase in the price of our common stock.

Depreciation, depletion and amortization.    DD&A expense increased $436.6 million, to $1,101.1 million in 2012 from $664.5 million in 2011. The increase is attributable to our oil and gas depletion, primarily due to a higher per unit rate ($359.6 million) and increased production ($73.0 million). Our oil and gas unit of production rate increased to $27.62 per BOE in 2012 compared to $17.76 per BOE in 2011.

The increased DD&A rate was primarily due to the prolonged decrease in natural gas prices as some of our proved undeveloped reserves are no longer classified as proved undeveloped reserves and was partially due to the impairment and transfer of certain unproved properties primarily associated with natural gas to costs subject to amortization. Our oil and gas DD&A rate for 2013, after the effect of the Gulf of Mexico Acquisition, is expected to be $33.81 per BOE.

Interest expense.    Interest expense increased $136.2 million, to $297.5 million in 2012 from $161.3 million in 2011, primarily due to a decrease in interest capitalized, greater average debt outstanding primarily in connection with the Gulf of Mexico Acquisition and the commitment fee associated with the unused bridge credit facility committed by lending entities as part of the financing of the Gulf of Mexico Acquisition, partially offset by lower average interest rates. Interest expense is net of interest capitalized on oil and natural gas properties not subject to amortization but in the process of development. We capitalized $51.2 million and $117.4 million of interest in 2012 and 2011, respectively. The decreased capitalized interest is primarily attributable to reduced exploration activity associated with certain unevaluated oil and gas properties combined with a lower overall average unevaluated property balance during the year.

(Loss) gain on mark-to-market derivative contracts.    The derivative instruments we have in place are not classified as hedges for accounting purposes. 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 in our income statement. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

We recognized a $2.9 million loss related to mark-to-market derivative contracts in 2012, which was primarily associated with a decrease in the fair value of our crude oil derivative contracts due to increased forward prices and a decrease in the fair value of our natural gas derivative contracts due to expirations of our 2012 contracts, partially offset by settlements received on our natural gas derivative contracts. In 2011, we recognized an $82.0 million gain related to mark-to-market derivative contracts.

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Gain (loss) on investment measured at fair value.    At December 31, 2012, we owned 51.0 million shares of McMoRan common stock. We are deemed to exercise significant influence over the operating and investing policies of McMoRan but do not have control. We have elected to measure our equity investment in McMoRan at fair value, and the change in fair value of our investment is recognized as gain on investment measured at fair value in our income statement.

We recognized a $206.6 million gain in 2012 related to our McMoRan investment, which was primarily associated with an increase in McMoRan’s stock price subsequent to the announcement of the MMR Merger and a lower implied discount.

Income taxes.    Our 2012 income tax expense was $171.3 million, reflecting an annual effective tax rate of 33%, as compared with an income tax expense of $134.3 million and an effective tax rate of 39% for 2011. Variances in our 2012 effective tax rate and the 35% federal statutory rate resulted from the tax effects of permanent differences, including expenses that are not deductible because of IRS limitations, state income taxes and changes to our balance of unrecognized tax positions. In 2012 we recorded a $31.5 million reduction to our deferred state income tax liabilities related to changes in state tax apportionment factors as a result of the Gulf of Mexico Acquisition. Variances in our 2011 effective tax rate and the 35% federal statutory rate resulted primarily from the tax effects of permanent differences including expenses that are not deductible because of IRS limitations, state income taxes and changes in our balance of unrecognized tax positions.

Comparison of Year Ended December 31, 2011 to Year Ended December 31, 2010

Oil and gas revenues.    Oil and gas revenues increased $414.5 million, to $1,956.9 million for 2011 from $1,542.4 million for 2010, primarily due to higher average realized oil prices and higher sales volumes partially offset by lower average realized gas prices.

Oil revenues increased $385.9 million, to $1,528.7 million for 2011 from $1,142.8 million for 2010, reflecting higher average realized prices ($291.6 million) and higher sales volumes ($94.3 million). Our average realized price for oil increased $17.39 per Bbl to $85.53 per Bbl for 2011 from $68.14 per Bbl for 2010. The increase was primarily attributable to an increase in the NYMEX oil price, which averaged $95.11 per Bbl in 2011 versus $79.61 per Bbl in 2010. Oil sales volumes increased 3.1 MBbls per day to 49.0 MBbls per day in 2011 from 45.9 MBbls per day in 2010, primarily reflecting increased production from our Eagle Ford Shale properties and our Panhandle properties divested in December 2011, partially offset by a production decrease due to the December 2010 divestment of our U.S. Gulf of Mexico shallow water properties. Excluding the impact of our divestments in 2010 and 2011, production increased 3.2 MBbls per day in 2011.

Gas revenues increased $28.6 million, to $428.2 million in 2011 from $399.6 million in 2010, reflecting higher sales volumes ($64.1 million), partially offset by lower average realized prices ($35.5 million). Gas sales volumes increased 44.9 MMcf per day to 299.9 MMcf per day in 2011 from 255.0 MMcf per day in 2010, primarily reflecting increased production from our Haynesville Shale properties and our Panhandle properties divested in December 2011 partially offset by a production decrease due to the December 2010 divestment of our U.S. Gulf of Mexico shallow water properties. Excluding the impact of our divestments in 2010 and 2011, sales increased 73.4 MMcf per day in 2011. Our average realized price for gas was $3.91 per Mcf in 2011 compared to $4.29 per Mcf in 2010.

Lease operating expenses.    Lease operating expenses increased $72.4 million, to $334.9 million in 2011 from $262.5 million in 2010, reflecting an increased number of producing wells at our Eagle Ford Shale properties and our Panhandle properties divested in December 2011 and higher scheduled repair and maintenance and well workovers primarily at our California properties.

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Production and ad valorem taxes.    Production and ad valorem taxes increased $25.8 million, to $55.2 million in 2011 from $29.4 million in 2010, reflecting increased production taxes in 2011 compared to 2010 due to increased production primarily from our Eagle Ford Shale properties and our Panhandle properties divested in December 2011 and production tax abatements recorded in 2010. The increase in ad valorem taxes was primarily at our California properties.

Gathering and transportation expenses.    Gathering and transportation expenses increased $11.4 million, to $62.1 million in 2011 from $50.7 million in 2010, primarily reflecting an increase in production from our Haynesville Shale properties, our Panhandle properties divested in December 2011 and our Eagle Ford Shale properties, partially offset by a decrease due to the December 2010 divestment of our U.S. Gulf of Mexico shallow water properties.

General and administrative expense.    G&A expense decreased $2.4 million, to $134.0 million in 2011 from $136.4 million in 2010, primarily due to lower franchise and other taxes and stock-based compensation expense, partially offset by costs attributable to increased headcount.

Depreciation, depletion and amortization.    DD&A expense increased $131.1 million, to $664.5 million in 2011 from $533.4 million in 2010. The increase was attributable to our oil and gas depletion, primarily due to increased production ($68.5 million) and a higher per unit rate ($61.7 million). Our oil and gas unit of production rate increased to $17.76 per BOE in 2011 compared to $15.87 per BOE in 2010.

Impairment of oil and gas properties.    During the second quarter of 2010, we completed our interpretation of seismic and drilling data from our two offshore Vietnam exploratory wells and decided not to pursue additional exploratory activities in this area. The costs related to our Vietnam oil and gas properties not subject to amortization were transferred to our Vietnam full cost pool where they were subject to the ceiling limitation. Because our Vietnam full cost pool had no associated proved oil and gas reserves, we recorded a non-cash pre-tax impairment charge of $59.5 million. At December 31, 2010, the ceiling with respect to our domestic oil and gas properties exceeded the net capitalized costs and we did not record an impairment.

Interest expense.    Interest expense increased $54.6 million, to $161.3 million in 2011 from $106.7 million in 2010, primarily due to greater average debt outstanding partially offset by lower average interest rates. Interest expense is net of interest capitalized on oil and natural gas properties not subject to amortization but in the process of development. We capitalized $117.4 million and $130.9 million of interest in 2011 and 2010, respectively.

Debt extinguishment costs.    During 2011, we recognized $121.0 million of debt extinguishment costs in connection with the retirement of portions of our 7 ³/₄% Senior Notes due 2015, or the 7 ³/₄% Senior Notes, 10% Senior Notes due 2016, or the 10% Senior Notes, and 7% Senior Notes due 2017, or the 7% Senior Notes. In connection with the reduction in the borrowing base on our revolving line of credit, we recorded $1.2 million of debt extinguishment costs in 2010.

(Loss) gain on mark-to-market derivative contracts.    The derivative instruments we have in place are not classified as hedges for accounting purposes. 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 in our income statement. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

We recognized an $82.0 million gain related to mark-to-market derivative contracts in 2011, which was primarily associated with an increase in fair value of our 2012 and 2013 natural gas derivative contracts and our 2012 crude oil derivative contracts due to lower forward prices. In 2010, we recognized a $60.7 million loss related to mark-to-market derivative contracts.

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Gain (loss) on investment measured at fair value.    At December 31, 2011, we owned 51.0 million shares of McMoRan common stock. We are deemed to exercise significant influence over the operating and investing policies of McMoRan but do not have control. We have elected to measure our equity investment in McMoRan at fair value, and the change in fair value of our investment is recognized as loss on investment measured at fair value in our income statement.

We recognized a $52.7 million loss in 2011 related to our McMoRan investment, which was primarily associated with a decrease in McMoRan’s stock price, partially offset by a lower discount to reflect certain limitations on the marketability of the shares.

Income taxes.    Our 2011 income tax expense was $134.3 million, reflecting an annual effective tax rate of 39%, as compared with an income tax expense of $100.7 million and an effective tax rate of 49% for 2010. Variances in our 2011 effective tax rate from the 35% federal statutory rate resulted primarily from the tax effects of permanent differences including expenses that are not deductible because of IRS limitations, state income taxes and changes to our balance of unrecognized tax positions. Variances in our 2010 effective tax rate from the 35% federal statutory rate resulted primarily from the tax effects of permanent differences including expenses that are not deductible because of IRS limitations, state income taxes, tax and financial reporting differences related to non-cash compensation, changes to our balance of unrecognized tax positions and foreign operations.

Liquidity and Capital Resources

Our liquidity may be affected by declines in oil and gas prices, an inability to access the capital and credit markets and the success of our commodity price risk management activities, which may subject us to the credit risk of the counterparties to these agreements. These situations may arise due to circumstances beyond our control, such as a general disruption of the financial markets and adverse economic conditions that cause substantial or extended declines in oil and gas prices. Volatility and disruption in the capital and credit markets may adversely affect the financial condition of lenders in our revolving line of credit, the counterparties to our commodity price risk management agreements, our insurers and our oil and natural gas purchasers, including those counterparties who may have exposure to certain European sovereign debt. In addition, new proposed regulations may require us to comply with certain margin requirements for our derivative contracts that could require us to enter into credit support documentation or post significant amounts of cash collateral. These market and regulatory conditions may adversely affect our liquidity by limiting our ability to access the capital and credit markets.

Our primary sources of liquidity are cash generated from our operations, our revolving line of credit and periodic public offerings of debt and equity. At December 31, 2012, we had approximately $1.3 billion available for future secured borrowings under our revolving line of credit. At December 31, 2012, Plains Offshore had $300 million available for future secured borrowings under its senior credit facility.

Under the terms of our Amended Credit Facility, the borrowing base is redetermined on an annual basis, with us and the lenders each having the right to one annual interim unscheduled redetermination and adjusted based on our oil and gas properties, reserves, other indebtedness and other relevant factors. Declines in oil and gas prices may adversely affect our liquidity by lowering the amount of the borrowing base that lenders are willing to extend.

The commitments of each lender to make loans to us are several and not joint under our revolving line of credit. Accordingly, if any lender fails to make loans to us, our available liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitments under the revolving line of credit. At December 31, 2012, the commitments under our revolving line of credit are from a diverse syndicate of 24 lenders and no single lender’s commitment represented more than 7% of the total commitments.

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Gulf of Mexico Acquisition.    On November 30 2012, we completed the Gulf of Mexico Acquisition for total cash consideration of $5.9 billion, as adjusted for working capital and other pre-closing adjustments. To finance the Gulf of Mexico Acquisition, we entered into the Amended Credit Facility providing for the five-year revolving line of credit, the five-year term loan and the seven-year term loan, increasing our borrowing base and commitments to $5.175 billion and $5.0 billion, respectively, and we issued $1.5 billion of 6 ¹/₂% Senior Notes and $1.5 billion of 6 ⁷/₈% Senior Notes, both at par. See Financing Activities. Further, we expensed transaction costs and interest related charges associated with the transaction of approximately $66.0 million during the year ended December 31, 2012. See Recent Developments.

As a result of our increased borrowings in connection with the Gulf of Mexico Acquisition, our interest expense increased beginning in the fourth quarter of 2012.

As part of our financing plan for the Gulf of Mexico Acquisition, we will continue to implement our crude oil hedging program. We plan to enter into derivative instruments for up to 90% of our crude oil production through 2015 to lock in cash flows and to provide downside commodity price protection through the use of swap contracts, three-way collars and put and call option spread contracts. As of December 31, 2012, we had entered into Brent crude oil swap contracts, put option spread contracts and three-way collars for 2013 and Brent crude oil put option spread contracts for 2014 and 2015, achieving our goal for 2013 and 2014 and making significant progress for 2015. See Item 7A – Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk for a listing of our commodity derivative contracts. In addition, production from the acquired deepwater Gulf of Mexico properties, continued growth from our onshore oil assets and volumes from the Lucius oil field in the deepwater Gulf of Mexico forecasted to come online in 2014 are expected to generate cash flow in excess of our capital expenditures and such excess cash flow may be applied to further reduce debt over the next several years.

Other Considerations.    Our 2013 capital budget is expected to be approximately $2.1 billion, including capitalized interest and general and administrative expenses. We intend to fund our 2013 capital budget from internally generated funds and borrowings under our revolving line of credit, with the portion of our 2013 budget related to Plains Offshore being funded with cash on hand and the Plains Offshore senior credit facility. In addition, we could curtail the portion of our capital expenditures that is discretionary if our cash flows decline from expected levels.

On December 5, 2012, the Company entered into the Freeport-McMoRan Merger Agreement with Freeport-McMoRan and the Merger Sub, pursuant to which Freeport-McMoRan will acquire the Company. Additionally, on December 5, 2012, Freeport-McMoRan agreed to acquire McMoRan. See Recent Developments. If the Freeport-McMoRan Merger Agreement is terminated, we may be required to reimburse Freeport-McMoRan for up to $69.0 million in expenses and/or to pay Freeport-McMoRan a termination fee of $207.0 million (less any amounts previously paid in respect of expenses). The MMR Merger provides an opportunity for us to liquidate our equity investment in McMoRan.

Without regard for the proposed merger, we believe that we have sufficient liquidity through our forecasted cash flow from operations and borrowing capacity under our revolving line of credit, cash on hand and the Plains Offshore senior credit facility to meet our short-term and long-term normal recurring operating needs, derivative obligations, debt service obligations, contingencies, anticipated capital expenditures and preferred stock dividends of Plains Offshore.

Working Capital

At December 31, 2012, we had working capital of approximately $859.7 million, primarily due to the current asset classification of our investment in the McMoRan common shares and cash on hand

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from the Plains Offshore preferred stock transaction in November 2011. Our working capital fluctuates for various reasons, including the fair value of our investment, commodity derivative instruments, deferred taxes and stock-based compensation.

Financing Activities

Amended Credit Facility.    In November 2012, we entered into the Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A. as administrative agent and the lenders party thereto, or the Amended Credit Agreement, which amended and restated our senior revolving credit facility. The Amended Credit Agreement provided for (i) a five-year revolving line of credit, a five-year term loan and a seven-year term loan and (ii) an initial borrowing base of $5.175 billion, which will be redetermined on an annual basis, with us and the lenders of the revolving line of credit each having the right to one annual interim unscheduled redetermination, and adjusted based on our oil and gas properties, reserves, other indebtedness (including the outstanding commitments under the credit agreement dated November 18, 2011 among Plains Offshore, JPMorgan Chase Bank, N.A. as administrative agent and the lenders party thereto from time to time) and other factors. Our next redetermination date will occur on or before May 1, 2013.

Revolving Line of Credit.    The aggregate commitments of the lenders under the revolving line of credit are $3.0 billion and can be increased to $3.6 billion if certain conditions are met. We are required, among other things, to make a mandatory prepayment if the combined total borrowings under our Amended Credit Facility and the Plains Offshore senior credit facility exceed the borrowing base. Additionally, our revolving line of credit contains a $750 million sub limit on letters of credit and a $100 million sub limit for swingline loans and matures on November 30, 2017. At December 31, 2012, we had $1.6 billion in outstanding borrowings and $2.2 million in letters of credit outstanding under our revolving line of credit. The daily average outstanding balance for the year ended December 31, 2012 was $631.0 million.

Amounts borrowed under our revolving line of credit bear an interest rate, at our election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus an additional variable amount ranging from 1.50% to 2.50%; (ii) a variable amount ranging from 0.50% to 1.50% plus the alternate base rate, or ABR, which is the greater of (1) the prime rate, as determined by JPMorgan Chase Bank, N.A., (2) the federal funds rate, plus 0.50%, and (3) the adjusted one-month LIBOR plus 1%; or (iii) the overnight federal funds rate plus an additional variable amount ranging from 1.50% to 2.50% for swingline loans. The Eurodollar rate and the ABR will be increased 0.25% while any term loans are outstanding. The additional variable amount of interest payable is based on the utilization rate as a percentage of the total amount of funds borrowed under our Amended Credit Facility and the Plains Offshore senior credit facility to the borrowing base. Letter of credit fees under our revolving line of credit are based on the utilization rate and range from 1.50% to 2.50% and will be increased by 0.25% while any term loans are outstanding. Commitment fees range from 0.375% to 0.50% of amounts available for borrowing. The effective interest rate on borrowings under our revolving line of credit was 2.55% at December 31, 2012.

Five-Year Term Loan and Seven-Year Term Loan.    In connection with the Amended Credit Agreement in November 2012, we entered into the $750.0 million five-year term loan due 2017 and the $1.25 billion seven-year term loan due 2019. We received approximately $730.3 million and $1.2 billion of net proceeds from the five-year term loan and seven-year term loan, respectively, after deducting the offering costs which are treated as discount on issuance. We used the net proceeds to pay a portion of the cash consideration for the Gulf of Mexico Acquisition, to pay fees and expenses incurred in connection with the Gulf of Mexico Acquisition and related financing and for general corporate purposes. The term loans bear an interest rate, at our election, equal to either: (i) the Eurodollar rate,

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which is based on LIBOR, plus 3.00% or (ii) 2.00% plus the ABR, which is the greater of (1) the prime rate, as determined by JPMorgan Chase Bank, N.A., (2) the federal funds rate, plus 0.50%, and (3) the adjusted one-month LIBOR plus 1.00%. In no event can LIBOR for the seven-year term loan be less than 1.00% per year.

The five-year term loan is payable in four annual installments each equal to 10% of the original principal balance due and payable on the last business day of December beginning on December 31, 2013 and the remaining balance due on its five-year maturity on November 30, 2017. The current portion of the five-year term loan is $75.0 million at December 31, 2012. The effective interest rate on our five-year term loan was 3.31% at December 31, 2012.

The seven-year term loan is payable in six annual installments each equal to 7.143% of the original principal balance due and payable on the last business day of December beginning on December 31, 2013 and the remaining balance due on its seven-year maturity on November 30, 2019. The current portion of the seven-year term loan is $89.3 million at December 31, 2012. The effective interest rate on our seven-year term loan was 4.00% at December 31, 2012.

Our Amended Credit Facility is secured by 100% of the shares of stock in certain of our domestic subsidiaries, 65% of the shares of stock in certain foreign subsidiaries and mortgages covering at least 75% of the total present value of our domestic proved oil and gas properties. Our Amended Credit Facility contains negative covenants that limit our ability, as well as the ability of our restricted subsidiaries to, among other things, incur additional debt or guarantee other indebtedness, 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, sell certain assets including capital stock of subsidiaries, enter into agreements that restrict dividends from subsidiaries, enter into certain types of swap agreements, enter into take-or-pay or other prepayment arrangements, merge or consolidate and enter into transactions with affiliates. In addition, we are required to maintain a ratio of debt to EBITDAX (as defined) of no greater than 4.50 to 1.

Plains Offshore Senior Credit Facility.    The aggregate commitments of the lenders under the Plains Offshore senior credit facility are $300 million. The Plains Offshore senior credit facility contains a $50 million limit on letters of credit and matures on November 18, 2016. At December 31, 2012, Plains Offshore had no borrowings or letters of credit outstanding under its senior credit facility.

Amounts borrowed under the Plains Offshore senior credit facility bear an interest rate, at Plains Offshore’s election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus an additional variable amount ranging from 1.50% to 2.50%; or (ii) a variable amount ranging from 0.50% to 1.50% plus the greater of (1) the prime rate, as determined by JPMorgan Chase Bank, (2) the federal funds rate, plus 0.50%, and (3) the adjusted LIBOR plus 1.00%. The additional variable amount of interest payable is based on the utilization rate as a percentage of the total amount of funds borrowed under both our revolving line of credit and the Plains Offshore senior credit facility and the borrowing base under the Amended Credit Facility. Letter of credit fees under the Plains Offshore senior credit facility are based on the utilization rate and range from 1.50% to 2.50%. Commitment fees range from 0.375% to 0.50% of amounts available for borrowing.

The borrowings under the Plains Offshore senior credit facility are guaranteed on a senior basis by PXP and certain of our subsidiaries, and are secured on a pari passu basis by liens on the same collateral that secures PXP’s Amended Credit Facility. The Plains Offshore senior credit facility contains certain affirmative and negative covenants, including limiting Plains Offshore’s ability, among other things, to create liens, incur other indebtedness, make dividends (excluding dividends on preferred stock) or other distributions, make investments, change the nature of Plains Offshore’s business and merge or consolidate, sell assets, enter into certain types of swap agreements and enter

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into certain transactions with affiliates, as well as other customary events of default, including a cross-default to PXP’s Amended Credit Facility. If an event of default (as defined in our Amended Credit Facility) has occurred and is continuing under our Amended Credit Facility that has not been cured or waived by the lenders thereunder then the Plains Offshore lenders could accelerate and demand repayment of the Plains Offshore senior credit facility.

Short-term Credit Facility.    We have an uncommitted short-term unsecured credit facility, or short-term facility, under which we may make borrowings from time to time, until June 1, 2013, not to exceed at any time the maximum principal amount of $75.0 million. No advance under the short-term facility may have a term exceeding 14 days and all amounts outstanding are due and payable no later than June 1, 2013. Each advance under the short-term facility bears interest at a rate per annum mutually agreed on by the bank and us.

We borrow under our short-term facility to fund our working capital needs. The funding requirements are typically generated due to the timing differences between payments and receipts associated with our oil and gas production. We generally pay off the short-term facility with receipts from the sales of our oil and gas production or borrowings under our revolving line of credit. No amounts were outstanding under the short-term facility at December 31, 2012. The daily average outstanding balance for the quarter and year ended December 31, 2012 was $22.7 million and $41.5 million, respectively. The weighted average interest rate on borrowings under our short-term facility was 1.5% for the years ended December 31, 2012 and 2011.

6  ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes.    In October 2012, we issued (i) $1.5 billion of 6 ¹/₂% Senior Notes, and (ii) $1.5 billion of 6 ⁷/₈% Senior Notes, both at par. We received approximately $2.95 billion of net proceeds, after deducting the underwriting discount and offering expenses. We used the net proceeds to pay a portion of the cash consideration for the Gulf of Mexico Acquisition and to reduce indebtedness outstanding under our revolving line of credit. We may redeem all or part of the 6 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes on or after November 15, 2015 and February 15, 2018, respectively, at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to November 15, 2015 we may at our option, redeem up to 35% of the 6 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes with the proceeds of certain equity offerings.

6 ¹/₈% Senior Notes.    In April 2012, we issued $750 million of 6 ¹/₈% Senior Notes due 2019, or the 6 ¹/₈% Senior Notes, at par. We received approximately $737.5 million of net proceeds, after deducting the underwriting discount and offering expenses. We used the net proceeds to reduce indebtedness outstanding under our revolving line of credit and for general corporate purposes, including the redemption of $79.3 million aggregate principal amount of the 7 ³/₄% Senior Notes and $76.9 million aggregate principal amount of the 7% Senior Notes. We may redeem all or part of the 6 ¹/₈% Senior Notes on or after June 15, 2016 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to June 15, 2015 we may at our option, redeem up to 35% of the 6 ¹/₈% Senior Notes with the proceeds of certain equity offerings.

Senior Notes.    The 10% Senior Notes, 7 ⁵/₈% Senior Notes due 2018, 6 ¹/₈% Senior Notes, 8 ⁵/₈% Senior Notes, 7 ⁵/₈% Senior Notes due 2020, 6 ¹/₂% Senior Notes, 6 ⁵/₈% Senior Notes, 6 ³/₄% Senior Notes and 6 ⁷/₈% Senior Notes (together, the Senior Notes) are our general unsecured senior obligations. The Senior Notes are jointly and severally guaranteed by certain of our existing domestic subsidiaries. In the future, a subsidiary guarantor’s guarantee may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the assets of that subsidiary guarantor; (ii) in connection with any sale or other disposition of all the capital stock of that subsidiary guarantor; (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation or dissolution

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of that subsidiary guarantor provided no default or event of default has occurred or is continuing; or (vi) at such time as that subsidiary guarantor does not have outstanding any guarantee of any of our or any of our other subsidiary guarantors’ indebtedness (other than the notes) in excess of $10.0 million in aggregate principal amount. The Senior Notes rank senior in right of payment to all of our existing and future subordinated indebtedness; pari passu in right of payment with any of our existing and future unsecured indebtedness that is not by its terms subordinated to the Senior Notes; effectively junior to our existing and future secured indebtedness, including indebtedness under our Amended Credit Facility and the Plains Offshore’s senior credit facility, to the extent of our assets constituting collateral securing that indebtedness; and effectively subordinate to all existing and future indebtedness and other liabilities (other than indebtedness and liabilities owed to us) of our non-guarantor subsidiaries. In the event of a change of control coupled with a ratings downgrade, as defined in the indentures, we will be required to make an offer to repurchase the Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

The indentures governing the Senior Notes contain covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to incur additional debt; make certain investments or pay dividends or distributions on our capital stock or purchase or redeem or retire capital stock; sell assets, including capital stock of our restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries; create liens that secure debt; enter into transactions with affiliates; and merge or consolidate with another company.

Redemption of 10% Senior Notes.    On February 20, 2013, we called for redemption of the remaining $184.9 million aggregate principal amount of our outstanding 10% Senior Notes at 105% of the principal amount. We expect to make payments totaling $195.2 million to retire the 10% Senior Notes in March 2013. We expect to recognize approximately $18.0 million of debt extinguishment costs, including $8.8 million of unamortized original issue discount and debt issue costs upon retirement of these Senior Notes.

Redemption of 7 ³/₄% Senior Notes and 7% Senior Notes.    During the second quarter of 2012, we redeemed the remaining $79.3 million aggregate principal amount of our 7 ³/₄% Senior Notes at 101.938% of the principal amount and the remaining $76.9 million aggregate principal amount of our 7% Senior Notes at 103.500% of the principal amount. We made payments totaling $80.8 million and $79.6 million to retire the 7 ³/₄% Senior Notes and the 7% Senior Notes, respectively. During 2012, we recognized $5.2 million of debt extinguishment costs, including $0.9 million of unamortized debt issue costs in connection with the retirement of these Senior Notes.

Cash Flows

	Year Ended December 31,
	2012			2011			2010
	(in millions)
Cash provided by (used in):
Operating activities	$	1,330.8		$	1,110.8		$	912.5
Investing activities		(7,703.3	)		(1,154.6	)		(1,575.3	)
Financing activities		6,133.9			456.5			667.4

Net cash provided by operating activities was $1.3 billion in 2012, $1.1 billion in 2011 and $912.5 million in 2010. The increase in net cash provided by operating activities in 2012 primarily reflects higher oil sales volumes and average realized oil prices. The increase in net cash provided by operating activities in 2011 primarily reflects higher operating income in 2011 as a result of higher average realized oil prices and a $63.9 million refund of income tax paid in prior years.

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Net cash used in investing activities of $7.7 billion in 2012 primarily reflects the Gulf of Mexico Acquisition for $5.9 billion and additions to oil and gas properties of approximately $1.9 billion. Net cash used in investing activities of $1.2 billion in 2011 primarily reflects additions to oil and gas properties of approximately $1.8 billion partially offset by the divestment of our Panhandle and South Texas properties of approximately $735.8 million. Net cash used in investing activities of $1.6 billion in 2010 primarily reflects additions to oil and gas properties of $1.0 billion and the acquisition of our Eagle Ford Shale properties for $596.3 million, partially offset by a $35.4 million net cash inflow primarily associated with an adjustment to the final settlement of the $1.1 billion payment to Chesapeake in September 2009 related to the prepayment of drilling and completion costs for future Haynesville Shale wells.

Net cash provided by financing activities of $6.1 billion in 2012 primarily reflects the $3.75 billion of proceeds from the 6 ¹/₂% Senior Notes, the 6 ⁷/₈% Senior Notes and the 6 ¹/₈% Senior Notes offerings, the $1.95 billion of net proceeds from the five-year and seven-year term loans and the net increase in borrowings under our revolving line of credit of $835.0 million, partially offset by the $156.2 million redemption of our 7 ³/₄% Senior Notes and our 7% Senior Notes. Net cash provided by financing activities of $456.5 million in 2011 primarily reflects the $1.6 billion of net proceeds from the 6 ³/₄% Senior Notes and the 6 ⁵/₈% Senior Notes offerings, the $430.2 million in net proceeds from the issuance of Plains Offshore preferred stock and the net increase in borrowings under our revolving line of credit of $115.0 million, partially offset by the $1.3 billion redemption of long-term debt and $361.7 million for treasury stock purchases. Net cash provided by financing activities of $667.4 million in 2010 primarily reflects the net increase in borrowings under our revolving line of credit of $390.0 million and the net proceeds from the $300 million offering of 7 ⁵/₈% Senior Notes due 2020.

Capital Requirements

We have made and will continue to make substantial capital expenditures for the acquisition, development, exploration and production of oil and gas. Our capital budget for 2013, excluding acquisitions, is expected to be approximately $2.1 billion, including capitalized interest and general and administrative expenses. We believe that we have sufficient liquidity through our forecasted cash flow from operations, borrowing capacity under our revolving line of credit, cash on hand and the Plains Offshore senior credit facility to meet our short-term and long-term normal recurring operating needs, derivative obligations, debt service obligations, contingencies, anticipated capital expenditures and preferred stock dividends of Plains Offshore. In addition, because approximately 80% of our 2013 capital budget is allocated to properties we operate, we could curtail the portion of our capital expenditures that is discretionary if our cash flows decline from expected levels.

Stock Repurchase Program

Our Board of Directors has authorized the repurchase of shares of our common stock. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions at our discretion, subject to market conditions and other factors. In January 2012, we repurchased 2.4 million common shares at an average cost of $37.02 per share totaling $88.5 million. Subsequent to these repurchases, our Board of Directors reset the authorization to $1.0 billion of PXP common stock, all of which is available for repurchase, and extended the program until January 2016.

During the year ended December 31, 2011, we repurchased 10.4 million common shares at an average cost of $34.73 per share totaling $361.7 million.

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Commitments and Contingencies

We had the following obligations at December 31, 2012 (in thousands):

	Total		2013		2014 and 2015		2016 and 2017		Thereafter
Long-term debt	$	10,204,892	$	164,288	$	328,575	$	2,458,467	$	7,253,562
Interest on debt		4,375,330		567,602		1,147,422		1,089,067		1,571,239
Operating leases		112,593		18,015		35,430		28,467		30,681
Asset retirement obligation		584,501		18,512		32,854		6,954		526,181
Oil and gas and related activities		567,930		247,938		105,954		75,436		138,602
Commodity derivative contracts		519,056		65,030		436,088		17,938		-
Cash-settled stock compensation awards		83,449		35,216		31,501		16,732		-
Other obligations		36,842		21,619		5,395		2,214		7,614
	$	16,484,593	$	1,138,220	$	2,123,219	$	3,695,275	$	9,527,879

The long-term debt and interest on debt amounts consist of amounts due under our revolving line of credit, term loans and Senior Notes and interest payments to maturity. The principal amount under our revolving line of credit varies based on our cash inflows and outflows and the amounts reflected in this table assume the principal amount outstanding at December 31, 2012 remains outstanding to maturity with interest and commitment fees calculated at the rates in effect at December 31, 2012. The interest rates on our term loans vary and are calculated at the rates in effect at December 31, 2012.

Operating leases relate primarily to obligations associated with our office facilities and aircraft.

Asset retirement obligations represent the estimated liability 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 are unknown because they are subject to, among other things, federal, state and local regulation and economic factors.

Oil and gas and related activities represent long-term obligations associated with exploration, development and production activities. We have entered into commitments for oil and gas gathering and transportation, drilling rig and oilfield services and the design, construction and operation of a produced water reclamation facility totaling approximately $567.9 million. Through our ownership in Lucius, we have a commitment of approximately $201.9 million for our share of certain costs for construction and installation of the production facility and subsea infrastructure, long lead equipment orders and detailed engineering work.

The obligation for commodity derivative contracts represents the deferred premium cost and interest on our crude oil put options that will be paid when such options are settled.

Cash-settled stock compensation awards represent the obligations for our cash-settled RSUs and SARs. The obligations at December 31, 2012 are calculated based on our closing stock price and other factors known at December 31, 2012. The ultimate settlement amount of such obligations is unknown because settlements will be based on the market price of our common stock at the time the cash-settled RSUs are vested and SARs are exercised. See Critical Accounting Policies and Estimates – Stock-based Compensation. Upon the closing of the merger, an event constituting a

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change in control will have occurred. See Recent Developments. The obligations at December 31, 2012 are based on the existing terms of our stock-based compensation awards and do not reflect any impact of the Freeport-McMoRan Merger Agreement.

Other obligations primarily represent our commitments for various service contracts, including $9.5 million of tax uncertainties, which represent the potential cash payments related to uncertain tax positions taken or expected to be taken in a tax return and include the interest related to uncertain tax positions.

Environmental Matters.    As discussed under Items 1 and 2 – Business and Properties – Regulation – Environmental, as an owner or lessee and operator of oil and gas properties, we are subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. 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 100 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 California, the CARB has developed regulations pursuant to Assembly Bill 32 that are intended to achieve an overall reduction in greenhouse gas emissions to 1990 levels, a 15% reduction by 2020. Because several of our operations emit greenhouse gases in excess of 25,000 metric tons per year, various operations in California are subject to the requirements of this program. In October 2011 CARB adopted the final Cap and Trade regulation which is intended to implement the Cap and Trade Program under Assembly Bill 32. The regulation established three separate three year compliance periods as follows: 2012 to 2014, 2015 to 2017 and 2018 to 2020. The regulation required regulated entities to “true up” their emission offset obligations by the end of each three-year obligation period. Due to time constraints on implementing the Cap and Trade Program, the regulation included a provision which would forego the requirement of regulated entities to surrender compliance instruments for their emissions the first year of the first compliance period. The first year which will require regulated entities to surrender compliance instruments will be for 2013 emissions. Compliance with these regulations will require companies to periodically secure instruments known as offsets and allowances, each of which is equal to one metric ton of emissions under the Cap and Trade program. The price of these instruments will vary in accordance with market conditions. The total amount of instruments we owe will vary annually based on the total greenhouse gas emissions registered in any one year and the number of “free allowances” issued by CARB annually. In November 2012 CARB held the first public auction of allowance instruments for regulated entities to begin meeting their compliance obligations. The settling price in the auction placed the price at $10.09 per allowance.

In 2011 our California properties subject to regulation under Assembly Bill 32 emitted 955,000 metric tons of greenhouse gas emissions. In 2012 we were issued 644,000 free allowances by CARB based on estimated emissions using our 2011 verified emissions data. Based on these figures we will be required to secure an estimated 311,000 instruments to meet our 2013 obligations by the end of the first compliance period. We are in the process of acquiring our required allowances and do not believe that the cost of acquiring such allowances will be material. Certain aspects of Assembly Bill 32, including the Cap and Trade program, are the subject of pending litigation and may be changed based on the outcome of such litigation.

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

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working interest owners plug and abandon non-producing wellbores, remove platforms, tanks, production equipment and flow lines and restore the wellsite. We estimate our 2013 cash expenditures related to plugging, abandonment and remediation will be approximately $18.5 million. Typically, when producing oil and gas assets are purchased, the purchaser assumes the obligation to plug and abandon wells and facilities that are part of such assets. However, in some instances, we have received an indemnity with respect to those costs. We cannot be assured that we will be able to collect on these indemnities.

In connection with our Gulf of Mexico Acquisition in November 2012, we assumed responsibility for our share of abandonment costs, including (1) removing, dismantling and disposing of the existing offshore platforms; (2) removing and disposing of certain existing subsea infrastructure; and (3) well bore abandonments. The present value of such abandonment costs, $337.7 million ($665.3 million undiscounted), was included in our asset retirement obligation as reflected on our balance sheet.

Although we obtained environmental studies on our properties in California and we believe that such properties have been operated in accordance with standard oil and gas industry practices in effect at the time, certain of those properties have been in operation for over 100 years, and current or future local, state and federal environmental laws and regulations may require substantial expenditures to comply with such rules and regulations related to environmental remediation and restoration. 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 and gas 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.

Although our offshore California properties have a shorter reserve life, third parties have retained the majority of the obligations for abandoning these properties, which include the Point Arguello Unit, offshore California, where the companies from which we purchased our interests retained responsibility for: (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 abandonments, conductor removals and site cleanup and preparation.

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, $74.3 million ($151.3 million undiscounted), is included in our asset retirement obligation as reflected on our 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 $84.3 million). To secure its abandonment obligations, the purchaser of the properties is required to periodically deposit funds into an escrow account. At December 31, 2012, the escrow account had a balance of $20.9 million. The fair value of our guarantee at December 31, 2012, $0.3 million, considers the payment/performance risk of the purchaser and is included in other long-term liabilities in our 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

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population density of southern California. 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. 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 are self-insured for named windstorms in the Gulf of Mexico. 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.

In the event we make a claim under our insurance policies, we will be subject to the credit risk of the insurers. Volatility and disruption in the financial and credit markets may adversely affect the credit quality of our insurers and impact their ability to pay out claims.

Firm Delivery Commitments.    Beginning in December 2012, we have oil and gas production volume delivery commitments. If we are unable to meet the commitments to deliver this production, our maximum financial commitment at December 31, 2012 would be $50.6 million over the remaining contract term. We currently have sufficient reserves and production capacity to fulfill this commitment. In December 2012, we were producing 12.4 MBbls per day at these properties. As of December 31, 2012, our delivery commitments for the next five years and thereafter were as follows:

	Total		2013		2014 and 2015		2016 and 2017		Thereafter
Oil (MBbls)		23,826		3,378		9,948		10,500		-

Offshore Morocco Exploration. In January 2013, we announced we entered into a definitive agreement to participate in an exploration program offshore the Kingdom of Morocco. Subject to customary closing conditions, including the receipt of Moroccan governmental approvals (expected in the first half of 2013), we will make a cash payment of $15.0 million to farm-in to Pura Vida Energy’s 75% working interest in the approximate 2.7 million acre Mazagan permit area in the Essaouira Basin offshore Morocco. We will earn a 52% working interest and act as operator in exchange for funding 100% of the costs of certain specified exploration activities that will include a commitment to fund and drill two wells, and if agreed, various additional exploration operations subject to a maximum of $215.0 million. The first exploration well is expected to be drilled in 2014.

Shareholder Class Actions.    Beginning on December 5, 2012, 26 purported shareholder class actions were filed challenging the merger of the Company with Freeport-McMoRan and the MMR Merger. The lawsuits were filed against PXP, Freeport-McMoRan and McMoRan and the boards of these companies as well as certain other named individuals. The shareholder class actions generally allege that the boards of these companies breached fiduciary duties and adversely affected shareholders by approving the merger and the MMR Merger. We believe these purported shareholder class actions are without merit and we intend to defend against them vigorously.

Concentration of Credit Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of accounts receivable with respect to our oil and gas operations and derivative instruments. For a description of purchasers of our oil and gas production that accounted for 10% or more of our total revenues for the three preceding calendar years, see Items 1 and 2 – Business and Properties – Product Markets and Major Customers.

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The ten financial institutions that are counterparties for our derivative commodity contracts had a Standard & Poor’s rating of A- or better as of December 31, 2012. Certain of our counterparties to our derivative agreements or their affiliates are also lenders under our Amended Credit Facility. As a result, the counterparties to our derivative agreements share in the collateral supporting our Amended Credit Facility. Therefore, we are not generally required to post additional collateral under our derivative agreements.

The commitments under our revolving line of credit and the Plains Offshore senior credit facility are from a diverse syndicate of 25 lenders. At December 31, 2012, no single lender’s commitments under both credit facilities combined represented more than 8% of our total commitments. However, if banks continue to consolidate, we may experience a more concentrated credit risk.

Critical Accounting Policies and Estimates

Management makes many estimates and assumptions in the application of generally accepted accounting principles that may have a material impact on our consolidated financial statements and related disclosures and on the comparability of such information over different reporting periods. All such estimates and assumptions affect reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingent assets and liabilities. Estimates and assumptions are based on information available prior to the issuance of the financial statements. Changes in facts and circumstances or discovery of new information may result in revised estimates and actual results may differ from these estimates.

Certain accounting estimates are considered to be critical if (a) the nature of the estimates and assumptions is material due to the level of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to changes; and (b) the impact of the estimates and assumptions on financial condition or operating performance is material. The areas of accounting and the associated critical estimates and assumptions made are discussed below.

Oil and Gas Reserves.    Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including DD&A and the full cost ceiling limitation.

There are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the amount and timing of development expenditures, including many factors beyond our control. Future development and abandonment costs are determined annually for each of our properties based upon its geographic location, type of production structure, water depth, reservoir depth and characteristics, currently available procedures and consultations with engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. 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 subjective, 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. All of our 2012 proved reserve information is based on estimates prepared by outside engineering firms. Estimates prepared by others may be higher or lower than these estimates.

The standardized measure 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

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SEC requirements, the estimated discounted future net revenues from proved reserves are generally based on average oil and gas prices in effect for the prior twelve months and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the average prices and costs as of the date of the estimate.

Impairments of Oil and Gas Properties.    Under the SEC’s full cost accounting rules, we review the carrying value of our oil and gas properties each quarter. Under these rules, for each cost center, capitalized costs of oil and gas properties (net of accumulated depreciation, depletion, amortization and related deferred income taxes) may not exceed a “ceiling” equal to:

• the present value, discounted at 10%, of estimated future net cash flows from proved oil and gas reserves, net of estimated future income taxes; plus

• the cost of unproved properties not being amortized; plus

• the lower of cost or estimated fair value of unproved properties included in the costs being amortized (net of related tax effects).

The rules generally require that we price our future oil and gas production at the twelve-month average of the first-day-of-the-month reference prices adjusted for location and quality differentials. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including derivative contracts that qualify and are designated for hedge accounting treatment. The derivative instruments we have in place are not classified as hedges for accounting purposes. An impairment is required if our capitalized costs exceed this “ceiling”. The pricing in ceiling test impairment calculations may cause results that are not indicated by market conditions existing at the end of an accounting period. For example, in periods of increasing oil and gas prices, the use of a twelve-month average price in the ceiling test calculation may result in an impairment. Conversely, in times of declining prices, ceiling test calculations may not result in an impairment.

At December 31, 2012, the ceiling with respect to our domestic oil and gas properties exceeded the net capitalized costs by 19% and we did not record an impairment.

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 in the future, impairments of our oil and gas properties could occur. Impairments required by these rules do not impact our cash flows from operating activities.

Oil and Natural Gas Properties Not Subject to Amortization.    The cost of unproved oil and natural gas properties are excluded from amortization until the properties are evaluated. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Unproved properties are assessed periodically, at least annually, to determine whether impairment has occurred. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment considers the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. The transfer of costs into the amortization base involves a significant amount of judgment and may be subject to changes over time based on our drilling plans and results, geological and geophysical evaluations, the assignment of proved reserves, availability of capital, and other factors. As of

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December 31, 2012, we had approximately $3.6 billion of costs excluded from amortization for our U.S. cost center. These costs consist primarily of costs incurred for undeveloped acreage and wells in progress pending determination, together with capitalized interest costs for these projects. Due to the nature of the reserves, the ultimate evaluation of the properties will occur over a period of several years. We expect that 58% of the costs not subject to amortization at December 31, 2012 will be transferred to the amortization base over the next five years and the remainder in the next seven to ten years. The timing of these transfers into our amortization base impacts our DD&A rate and full cost ceiling test.

DD&A. Our rate for 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. See Oil and Gas Reserves. 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 full cost ceiling test previously discussed. 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 development program, as well as future economic conditions.

Our oil and gas DD&A rate for 2013, after the effect of the Gulf of Mexico Acquisition in the fourth quarter of 2012, is expected to be $33.81 per BOE. Based on our estimated proved reserves and our net oil and gas properties subject to amortization at December 31, 2012: (i) a 5.0% increase in our costs subject to amortization would increase our DD&A rate by approximately $1.70 per BOE and (ii) a 5.0% negative revision to proved reserves would increase our DD&A rate by approximately $1.78 per BOE.

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. Any substantial or extended decline in the price of oil and gas below current levels 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. A variety of derivative instruments may be utilized such as swaps, collars, puts, calls and various combinations of these. The type of instrument we select is a function of market conditions, available derivative prices and our operating strategy. 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. These contracts also expose us to credit risk of nonperformance by the counterparties.

The derivative instruments we have in place are not classified as hedges for accounting purposes. These derivative contracts are reflected at fair value on our balance sheet and 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 and ICE indices. Cash flow is only impacted to the extent the actual settlements under the contracts result in making or receiving a payment from the counterparty.

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The estimation of fair values of derivative instruments requires substantial judgment. The fair value amounts of our put and collar derivative instruments are estimated using an option-pricing model, which uses various inputs including ICE price quotations, volatilities, interest rates and contract terms. The fair value of our swap derivative instruments are estimated using a pricing model which has various inputs including NYMEX and ICE price quotations, interest rates and contract terms. We adjust the valuations from the model for credit quality, using the counterparties’ credit quality for asset balances and our credit quality for liability balances. For asset balances, we use the credit default swap value for counterparties when available or the spread between the risk-free interest rate and the yield on the counterparties’ publicly traded debt for similar maturities. We consider the impact of netting agreements on counterparty credit risk, including whether the position with the counterparty is a net asset or net liability. We determine whether the market for our derivative instruments is active or inactive based on transaction volume for such instruments. We value the instruments using similar instruments and by extrapolating and/or interpolating data between data points for the thinly traded instruments. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts and interest rates.

For a further discussion concerning our risks related to oil and gas prices and our derivative contracts, see Item 7A – Quantitative and Qualitative Disclosures about Market Risk – Commodity Price Risk.

Investment.    We have elected to measure our equity investment in McMoRan at fair value, and the change in fair value of our investment is recognized as a gain or loss on investment measured at fair value in our income statement. Historically, we have determined the fair value of our investment by applying a discount factor for lack of marketability at the reporting date. As of December 31, 2011, the discount factor for lack of marketability was determined by utilizing both Protective put and Asian put option models. Both of these options are valued using a Black-Scholes option-pricing model which utilizes various inputs including the closing price of the McMoRan common stock, implied volatility of the instrument, number of shares being valued, length of time that would be necessary to dispose of our investment, expected dividend and risk-free interest rates.

The use of above models requires substantial judgment with respect to the inputs used to determine fair value.

On December 5, 2012, PXP and Freeport-McMoRan entered into the Support Agreement with respect to the MMR Merger Agreement among McMoRan, Freeport-McMoRan and the MMR Merger Sub, pursuant to the MMR Merger, with McMoRan continuing as the surviving company and a wholly owned subsidiary of Freeport-McMoRan. Under the Support Agreement we, in our capacity as a stockholder of McMoRan, are generally prohibited from transferring our shares of McMoRan common stock prior to the consummation of the merger. Therefore, on December 31, 2012, we determined the fair value of our investment by utilizing a time value of money analysis. The implied discount to reflect the time value of money is determined by utilizing a risk-free interest rate based on the U.S. Treasury Strip rate with a maturity date corresponding to the expected close of the merger.

At December 31, 2012, the McMoRan shares were valued at approximately $818.2 million, based on McMoRan’s closing stock price of $16.05 on December 31, 2012, discounted to reflect the time value of money.

For a further discussion concerning our risks related to equity prices and our equity investment in McMoRan, see Item 7A – Quantitative and Qualitative Disclosures about Market Risk – Equity Price Risk.

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Stock-based Compensation.    Our stock-based compensation cost is measured based on the fair value of the award on the grant date and remeasured each reporting period for liability-classified awards. The compensation cost is recognized net of estimated forfeitures over the requisite service period.

We utilize the Black-Scholes option pricing model to measure the fair value of our stock appreciation rights. In the case of stock-settled RSU grants that include common stock price based performance targets and cash-settled RSU grants that are contingent upon the achievement of total shareholder return targets comparing PXP common stock to an average of peer indices, we utilize Monte-Carlo simulation models to estimate the fair value and the number of stock-settled or cash-settled RSUs, respectively, expected to be issued in the future. Expected volatility is based on the historical volatility of our common stock and other factors. We use historical experience for exercises to determine expected life. The use of such models requires substantial judgment with respect to expected life, volatility, expected returns and other factors.

We recognized $60 million, $49 million and $51 million of stock-based compensation expense for the years ended December 31, 2012, 2011 and 2010, respectively.

Business Combinations.    Accounting for business combinations requires that the various assets acquired and liabilities assumed in a business combination be recorded at their respective fair values. The most significant estimates to us typically relate to the value assigned to future recoverable oil and gas reserves and unproved properties. Deferred taxes are recorded for any differences between fair value and tax basis of assets acquired and liabilities assumed. To the extent the purchase price plus the liabilities assumed (including deferred income taxes recorded in connection with the transaction) exceeds the fair value of the net assets acquired, we are required to record the excess as goodwill. As the fair value of assets acquired and liabilities assumed is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. The value assigned to recoverable oil and gas reserves is subject to the full cost ceiling limitation, and the value assigned to unproved properties is assessed at least annually to ascertain whether impairment has occurred.

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. At December 31, 2012, goodwill totaled $535 million and represented approximately 3% of our total assets.

Goodwill is not amortized; instead it is tested at least annually for impairment at a level of reporting referred to as a reporting unit. Impairment occurs when the carrying amount of goodwill exceeds its implied fair value. Companies are permitted to make a qualitative assessment of a reporting unit’s fair value prior to performing the two-step goodwill impairment test, which is used to identify potential goodwill impairment and measure the amount of goodwill impairment loss to be recognized, if any. If it is determined through the qualitative assessment that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step impairment test is unnecessary. The qualitative assessment is optional, allowing companies to go directly to the quantitative assessment.

The first step of the quantitative goodwill impairment test 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 to be 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 the reporting unit’s goodwill with the carrying amount of that goodwill. If the carrying amount of that reporting unit’s 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.

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We elected to continue performing our annual goodwill impairment assessment under the quantitative two-step impairment test. We follow the full cost method of accounting for oil and gas activities and all of our producing properties are located in the United States. We have determined that for the purpose of performing an impairment test, we have one reporting unit.

The first step of the goodwill impairment test requires that we make an estimate of the fair value of the reporting unit. Quoted market prices in active markets are the best evidence of fair value. Historically, we have estimated the fair value of the reporting unit by applying a control premium to the quoted market price of our common stock. The control premium was determined through reference to control premiums in merger and acquisition transactions for our industry and other comparable industries. This requires that we make certain judgments about the selection of merger and acquisition transactions and transaction premiums.

We perform our goodwill impairment test annually as of December 31 and have recorded no impairment. We also perform interim impairment tests if events occur or circumstances change that would indicate the fair value of our reporting unit may be below its carrying amount.

Events affecting oil and gas prices may cause a decrease in the fair value of the reporting unit, and we could have an impairment of our goodwill in future periods. Additionally, failure to complete the merger could result in changes to the fair value of the reporting unit and result in an impairment of our goodwill. 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 equity.

Income Taxes.    The amount of income taxes recorded by us requires interpretations of complex rules and regulations of various tax jurisdictions. We recognize deferred tax assets and liabilities for temporary differences, operating losses and tax credit carryforwards. Also, we routinely assess the realizability of our deferred tax assets and reduce such assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. We routinely assess potential uncertain tax positions and, if required, establish accruals for such amounts. The accruals for deferred tax assets and liabilities are subject to a significant amount of judgment and are reviewed and adjusted routinely based on changes in facts and circumstances. Although we consider our tax accruals adequate, material changes in these accruals may occur in the future, based on the progress of ongoing tax audits, changes in legislation and resolution of other pending tax matters.

Recent Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board, or FASB, issued authoritative guidance requiring entities to disclose both gross and net information about financial instruments and transactions eligible for offset in the statement of financial position as well as financial instruments and transactions subject to agreements similar to master netting arrangements. The additional disclosures will enable users of the financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. In January 2013, the FASB issued further authoritative guidance clarifying the scope of these disclosure requirements to include bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that either have a right of offset or are subject to an enforceable master netting arrangement or similar agreements. These disclosure requirements are effective for interim and annual periods beginning after January 1, 2013, and will primarily impact our disclosures associated with our commodity derivative instruments. We do not expect this guidance to have a significant impact on our consolidated financial position, results of operations or cash flows.

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ITEM 7A.  Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Our primary market risk is oil and gas commodity prices. The markets for oil and gas have historically been volatile and are likely to continue to be volatile in the future. 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 a gain or loss on mark-to-market derivative contracts. Cash flows are only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty. The derivative instruments we have in place are not classified as hedges for accounting purposes.

The fair value amounts of our put and collar derivative instruments are estimated using an option-pricing model, which uses various inputs including ICE price quotations, volatilities, interest rates and contract terms. The fair value of our swap derivative instruments are estimated using a pricing model which has various inputs including NYMEX and ICE price quotations, interest rates and contract terms. We adjust the valuations from the model for credit quality, using the counterparties’ credit quality for asset balances and our credit quality for liability balances. For asset balances, we use the credit default swap value for counterparties when available or the spread between the risk-free interest rate and the yield on the counterparties’ publicly traded debt for similar maturities. We consider the impact of netting agreements on counterparty credit risk, including whether the position with the counterparty is a net asset or net liability. Our Level 3 commodity derivative contracts represent 6% of the total commodity derivative contracts assets and liabilities’ fair value.

The significant unobservable inputs used in the fair value measurement of our commodity derivative contracts are implied volatilities. Significant increases (decreases) in implied volatilities in isolation would result in a significantly higher (lower) fair value measurement.

See Note 7 – Commodity Derivative Contracts and Note 9 – Fair Value Measurements of Assets and Liabilities in the accompanying financial statements for a discussion of our derivative activities and fair value measurements.

In 2012, we entered into the following derivative contracts:

• Henry Hub natural gas swap contracts on 80,000 MMBtu for 2012 with an average price of $2.72 per MMBtu.

• Brent crude oil swap contracts on 40,000 BOPD for 2013 with an average price of $109.23 per barrel.

• Brent three-way collars on 25,000 BOPD for 2013 with a floor price of $100 per barrel, a limit of $80 per barrel and a weighted average ceiling price of $124.29.

• Brent crude oil put option spread contracts on 13,000 BOPD for 2013 with a floor price of $100 per barrel, a limit of $80 per barrel and weighted average deferred premium and interest of $6.800 per barrel.

• Brent crude oil put option spread contracts on 5,000 BOPD for 2014 with a floor price of $100 per barrel, a limit of $80 per barrel and weighted average deferred premium and interest of $7.110 per barrel.

• Brent crude oil put option spread contracts on 30,000 BOPD for 2014 with a floor price of $95 per barrel, a limit of $75 per barrel and weighted average deferred premium and interest of $6.091 per barrel.

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• Brent crude oil put option spread contracts on 75,000 BOPD for 2014 with a floor price of $90 per barrel, a limit of $70 per barrel and weighted average deferred premium and interest of $5.739 per barrel.

• Henry Hub natural gas swap contracts on 100,000 MMBtu for 2014 with an average price of $4.09 per MMBtu.

• Brent crude oil put option spread contracts on 84,000 BOPD for 2015 with a floor price of $90 per barrel, a limit of $70 per barrel and weighted average deferred premium and interest of $6.889 per barrel.

Additionally, we converted 5,000 BOPD of Brent crude oil put option contracts for 2013 to three-way collars. These modified three-way collars have a floor price of $90 per barrel with a limit of $70 per barrel and a weighted average ceiling price of $126.08, and we eliminated approximately $11.3 million of deferred premiums.

As of February 20, 2013, we had the following outstanding commodity derivative contracts, all of which settle monthly:

Period	Instrument Type	Daily Volumes	Average Price (1)	Average Deferred Premium	Index
Sales of Crude Oil Production
2013
Feb - Dec	Swap contracts (2)	40,000 Bbls	$109.23	-	Brent
Feb - Dec	Put options (3)	13,000 Bbls	$100.00 Floor with an $80.00 Limit	$6.800 per Bbl	Brent
Feb - Dec	Three-way collars (4)	25,000 Bbls	$100.00 Floor with an $80.00 Limit	-	Brent
			$124.29 Ceiling
Feb - Dec	Three-way collars (4)	5,000 Bbls	$90.00 Floor with a $70.00 Limit	-	Brent
			$126.08 Ceiling
Feb - Dec	Put options (3)	17,000 Bbls	$90.00 Floor with a $70.00 Limit	$6.253 per Bbl	Brent
2014
Jan - Dec	Put options (3)	5,000 Bbls	$100.00 Floor with an $80.00 Limit	$7.110 per Bbl	Brent
Jan - Dec	Put options (3)	30,000 Bbls	$95.00 Floor with a $75.00 Limit	$6.091 per Bbl	Brent
Jan - Dec	Put options (3)	75,000 Bbls	$90.00 Floor with a $70.00 Limit	$5.739 per Bbl	Brent
2015
Jan - Dec	Put options (3)	84,000 Bbls	$90.00 Floor with a $70.00 Limit	$6.889 per Bbl	Brent
Sales of Natural Gas Production
2013
Feb - Dec	Swap contracts (2)	110,000 MMBtu	$4.27	-	Henry Hub
2014
Jan - Dec	Swap contracts (2)	100,000 MMBtu	$4.09	-	Henry Hub

(1) The average strike prices do not reflect any premiums to purchase the put options.

(2) If the index price is less than the fixed price, we receive the difference between the fixed price and the index price. We pay the difference between the index price and the fixed price if the index price is greater than the fixed price.

(3) If the index price is less than the per barrel floor, we receive the difference between the per barrel floor and the index price up to a maximum of $20 per barrel less the option premium. If the index price is at or above the per barrel floor, we pay only the option premium.

(4) If the index price is less than the per barrel floor, we receive the difference between the per barrel floor and the index price up to a maximum of $20 per barrel. We pay the difference between the index price and the per barrel ceiling if the index price is greater than the per barrel ceiling. If the index price is at or above the per barrel floor but at or below the per barrel ceiling, no cash settlement is required.

For put options, we typically pay a premium to the counterparty in exchange for the sale of the instrument. If the index price is below the floor price of the put option, we receive the difference between the floor price and the index price multiplied by the contract volumes less the option premium. If the index price settles at or above the floor price of the put option, we pay only the option premium.

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In a typical collar transaction, if the floating price based on a market index is below the floor price in the derivative contract, we receive from the counterparty an amount equal to this difference multiplied by the specified volume. If the floating price exceeds the ceiling price, we must pay the counterparty an amount equal to the difference multiplied by the specified volume. We may pay a premium to the counterparty in exchange for a certain floor or ceiling. Any premium reduces amounts we would receive under the floor or increases amounts we would pay above the ceiling. If the floating price exceeds the floor price and is less than the ceiling price, then no payment, other than the premium, is required. If we have less production than the volumes specified under the collar transaction when the floating price exceeds the ceiling price, we must make payments against which there are no offsetting revenues from production.

Under a swap contract, the counterparty is required to make a payment to us if the index price for any settlement period is less than the fixed price, and we are required to make a payment to the counterparty if the index price for any settlement period is greater than the fixed price. The amount we receive or pay is the difference between the index price and the fixed price multiplied by the contract volumes. If we have less production than the volumes specified under the swap transaction when the index price exceeds the fixed price, we must make payments against which there are no offsetting revenues from production.

The fair value of outstanding crude oil and natural gas commodity derivative instruments at December 31, 2012 and the change in fair value that would be expected from a 10% price increase or decrease is shown below (in millions):

	Fair Value Asset		Effect of 10%
			Price Increase			Price Decrease
Crude oil puts	$	441	$	(131	)	$	176
Crude oil collars		17		(47	)		44
Crude oil swaps		34		(156	)		155
Natural gas swaps		31		(28	)		28
	$	523	$	(362	)	$	403

None of our offsetting physical positions are included in the above table. Price risk sensitivities were calculated by assuming an across-the-board 10% increase or decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price.

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 revenue on the volumes than we would receive in the absence of derivatives.

Price Differentials.    Our realized wellhead oil prices and gas prices are lower than the ICE index level and the NYMEX index level, respectively. See Items 1 and 2 – Business and Properties – Product Markets and Major Customers.

Approximately 99% of our 2012 crude oil production was sold under contracts with prices based upon regional benchmarks that are not linked to NYMEX with the remainder sold under contracts that provide for NYMEX less a fixed price differential (as of December 31, 2012 the fixed price differential averaged $3.41 per barrel).

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Approximately 50% of our gas production is sold monthly using 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 are exposed to market risk due to the floating interest rates on our revolving line of credit, the term loans, the Plains Offshore senior credit facility and our short-term credit facility. At December 31, 2012, $1.6 billion aggregate principal amount was outstanding under our revolving line of credit at an effective interest rate of 2.55%. At December 31, 2012, $750.0 million and $1.25 billion were outstanding under our five-year term loan and seven-year term loan, respectively, at effective interest rates of 3.31% and 4.00%, respectively. Based on the $1.6 billion outstanding under our revolving line of credit at December 31, 2012, on an annualized basis a 1% change in the effective interest rate would result in a $15.7 million change in our interest costs. Based on the $750.0 million and $1.25 billion aggregate principal amount outstanding under our five-year term loan and seven-year term loan at December 31, 2012, on an annualized basis a 1% change in the effective interest rate would result in a $20.0 million change in our interest costs. At December 31, 2012, no amounts were outstanding under the Plains Offshore senior credit facility or our short-term facility.

Equity Price Risk

We are exposed to market risk because we own an equity investment in McMoRan common stock. See Note 8 – Investment and Note 9 – Fair Value Measurements of Assets and Liabilities in the accompanying financial statements for a discussion of our equity investment. At December 31, 2012, the investment, comprised of 51.0 million shares of McMoRan common stock, was valued at approximately $818.2 million. A 10% change in the underlying equity market price per share would result in a $81.8 million increase or decrease in the fair value of our investment, recognized in the income statement.

Historically, we have determined the fair value of our investment by applying a discount factor for lack of marketability at the reporting date. As of December 31, 2011, the discount factor for lack of marketability was determined by utilizing both Protective put and Asian put option models. Both of these options are valued using a Black-Scholes option-pricing model which utilizes various inputs including the closing price of the McMoRan common stock, implied volatility of the instrument, number of shares being valued, length of time that would be necessary to dispose of our investment, expected dividend and risk-free interest rates.

In connection with the MMR Merger, on December 5, 2012, we entered into the Support Agreement with Freeport-McMoRan, pursuant to which we, in our capacity as a stockholder of McMoRan, are generally prohibited from transferring our shares of McMoRan common stock prior to the consummation of the merger. On December 31, 2012, we determined the fair value of our investment using McMoRan’s closing stock price of $16.05, which we believe is consistent with the exit price notion and is representative of what a market participant would pay for McMoRan’s common stock in an arm’s length transaction. Additionally, we utilized a time value of money analysis to determine an implied discount rate. The implied discount is determined by utilizing a risk-free interest rate based on the U.S. Treasury Strip rate with a maturity date corresponding to the expected close of the merger. Failure to complete the merger could result in changes to the method we use to determine fair value of our investment, which may result in the use of other significant unobservable inputs.

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During 2012, the increase in the fair value of our equity investment in McMoRan common stock is primarily attributable to the increase in McMoRan’s stock price subsequent to the announcement of the MMR Merger.

As of December 31, 2012 and 2011, our investment in McMoRan has been classified as Level 3 since the fair value is determined by utilizing significant inputs that are unobservable.

Item 8. Financial Statements and Supplementary Data

The information required here is included in this report as set forth in the Index to Consolidated 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 Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, or 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, 2012 were effective to ensure that information we are required to disclose in the reports that we file or submit under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) accumulated and communicated to our management, including our principal executive and financial officers, as appropriate to allow timely decisions regarding required disclosure.

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, 2012. The Company excluded PXP Offshore LLC from its assessment of internal control over financial reporting as of December 31, 2012. PXP Offshore LLC was formed in connection with the Gulf of Mexico Acquisition on November 30, 2012. PXP Offshore LLC is a wholly owned subsidiary of the Company whose total assets and total revenues represent 37% and 8%, respectively, of the related consolidated financial statement amounts, as of and for the year ended December 31, 2012.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2012 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

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Changes in Internal Control Over Financial Reporting

Except for the potential changes noted in the following paragraph relating to PXP Offshore LLC, there were no changes in our internal control over financial reporting during the quarter ended December 31, 2012 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

On November 30, 2012, PXP Offshore LLC was formed in connection with the Gulf of Mexico Acquisition. Management continues to integrate PXP Offshore LLC’s internal control over financial reporting with the Company’s internal control over financial reporting. This integration may lead to changes in these controls in future fiscal periods but management does not yet know whether these changes will materially affect our internal control over financial reporting. Management expects the integration process to be completed during 2013.

Item 9B.  Other Information

Not Applicable.

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PART III

Item 10.  Directors, Executive Officers and Corporate Governance

Information regarding our directors, executive officers and certain corporate governance items will be included in the proxy statement for the 2013 annual meeting of stockholders and incorporated by reference to this report or, in the event we do not prepare and file such proxy statement, such information shall be filed as an amendment to this Form 10-K. Such information will be filed within 120 days after December 31, 2012.

Directors and Executive Officers of Plains Exploration & Production Company

Listed below are our directors and executive officers, their age as of January 31, 2013 and their business experience for the last five years.

Directors

James C. Flores, age 53, Chairman of the Board, President and Chief Executive Officer and a Director since September 2002.    He has been Chairman of the Board and Chief Executive Officer of PXP since December 2002, and President since March 2004. He was also Chairman of the Board of Plains Resources, Inc., or Plains Resources (now owned by Vulcan Energy Corporation), from May 2001 to June 2004 and is currently a director of Vulcan Energy and McMoRan Exploration Co. He was 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.

Isaac Arnold, Jr., age 77, Director since May 2004.    He was also a director of Nuevo Energy Company from 1990 to May 2004. He has been a director of Legacy Holding Company since 1989 and Legacy Trust Company since 1997 and is currently Director Emeritus of both. He became a director of Cullen Frost Bankers, Inc. (formerly Cullen Center Bank & Trust) at its inception in 1969. He became a director of The Frost National Bank in 1994. He served as a director of the boards of Cullen Frost Bankers, Inc. and The Frost National Bank until he retired from both in 2006 and is currently Director Emeritus of both. Mr. Arnold also served on the Audit and Strategic Planning Committees for Cullen Frost Bankers, Inc. from 1995 to 2006. Mr. Arnold is a trustee of the Museum of Fine Arts Houston and The Texas Heart Institute.

Alan R. Buckwalter, III, age 65, Director since March 2003.    He retired in January 2003 as Chairman of JPMorgan Chase Bank, South Region, a position he had held since 1998. From 1990 to 1998 he was President of Texas Commerce Bank-Houston, the predecessor entity of JPMorgan Chase Bank. Prior to 1990 Mr. Buckwalter held various executive management positions within the organization. Mr. Buckwalter currently serves on the boards of Service Corporation International, the Texas Medical Center and the Greater Houston Area Red Cross and is Vice Chairman of Torch Securities LLC. He sits on the Nominating and Governance Committee, the Audit Committee and is Chairman of the Compensation Committee for Service Corporation International. Mr. Buckwalter previously served on the board of BCM Technologies, Inc. from 2003 to 2009.

Jerry L. Dees, age 72, Director since September 2002.    He was also a director of Plains Resources from 1997 to December 2002. Mr. Dees has been a director of Geotrace Technologies, Inc. since 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.

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Tom H. Delimitros, age 72, Director since September 2002.    He was also 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, and is the Chairman of the Audit Committee as well as member of the Management and Compensation Committee and the Reserves Committee. He currently serves as a director for three privately owned companies. Previously, he has served as President and CEO for Magna Corporation, (now Baker Petrolite, a unit of Baker Hughes). Mr. Delimitros currently serves on two Development Committees for the College of Engineering at the University of Washington in Seattle and is a member of the University of Washington Foundation Board.

Thomas A. Fry, III, age 68, Director since November 2007.    He was also a director of Pogo Producing Company, or Pogo, from 2004 to November 2007. He was the President of National Ocean Industries Association, or NOIA, from December 2000 until January 2010. Before joining NOIA, Mr. Fry served as the Director of the Department of Interior’s Bureau of Land Management and has also served as the Director of the Minerals Management Service. He has served as a director of the National Energy Education and Development Project as well as the National Marine Sanctuary Foundation, where he was head of the Audit Committee.

Charles G. Groat, age 72, Director since November 2007.    He was also a director of Pogo from 2005 to November 2007. Dr. Groat currently serves as a director and President and Chief Executive Officer of the Water Institute of the Gulf. Prior to joining the Water Institute of the Gulf, Mr. Groat was Director of both the Center for International Energy and Environment Policy and the Energy and Earth Resources Graduate Program at the University of Texas at Austin from May 2005 to November 2012. He also served as Associate Director of the University’s Energy Institute from June 2010 to November 2012 and was a professor of Geological Sciences and Public Affairs at the University of Texas at Austin from May 2005 to November 2012. Before joining the University of Texas at Austin, Dr. Groat served for more than six years as Director of the U.S. Geological Survey, having been appointed by President Clinton and retained by President Bush.

John H. Lollar, age 74, Director since September 2002.    He was also 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 Chairman of the Compensation Committee and a member 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 53, Chairman of the Board, President and Chief Executive Officer and a Director since September 2002.    He has been Chairman of the Board and Chief Executive Officer of PXP since December 2002, and President since March 2004. He was also Chairman of the Board of Plains Resources, Inc. (now owned by Vulcan Energy Corporation), from May 2001 to June 2004 and is currently a director of Vulcan Energy and McMoRan Exploration Co. He was 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.

Doss R. Bourgeois, age 55, Executive Vice President—Exploration and Production since June 2006.    He was PXP’s Vice President of Development from April 2006 to June 2006. He was also PXP’s Vice President Eastern Development Unit from May 2003 to April 2006. Prior to that time, Mr. Bourgeois was Vice President from August 1993 to May 2003 at Ocean Energy, Inc.

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Winston M. Talbert, age 50, Executive Vice President and Chief Financial Officer since June 2006.    He joined PXP in May 2003 as Vice President Finance & Investor Relations and in May 2004, Mr. Talbert became Vice President Finance & Treasurer. Prior to joining PXP, Mr. Talbert was Vice President and Treasurer at Ocean Energy, Inc. from August 2001 to May 2003 and Assistant Treasurer from October 1999 to August 2001.

John F. Wombwell, age 51, 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. Mr. Wombwell serves on the board of McMoRan Exploration Co. He was previously a partner at the law firm of Andrews Kurth LLP with a practice focused on representing public companies and an executive officer with two New York Stock Exchange traded companies.

Item 11.  Executive Compensation

Information regarding executive compensation will be included in the proxy statement for the 2013 annual meeting of stockholders and incorporated by reference to this report or, in the event we do not prepare and file such proxy statement, such information shall be filed as an amendment to this Form 10-K. Such information will be filed within 120 days after December 31, 2012.

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

Information regarding beneficial ownership will be included in the proxy statement for the 2013 annual meeting of stockholders and incorporated by reference to this report or, in the event we do not prepare and file such proxy statement, such information shall be filed as an amendment to this Form 10-K. Such information will be filed within 120 days after December 31, 2012.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information regarding certain relationships and related transactions and director independence will be included in the proxy statement for the 2013 annual meeting of stockholders and incorporated by reference to this report or, in the event we do not prepare and file such proxy statement, such information shall be filed as an amendment to this Form 10-K. Such information will be filed within 120 days after December 31, 2012.

Item 14.  Principal Accounting Fees and Services

Information regarding principal accounting fees and services will be included in the proxy statement for the 2013 annual meeting of stockholders and incorporated by reference to this report or, in the event we do not prepare and file such proxy statement, such information shall be filed as an amendment to this Form 10-K. Such information will be filed within 120 days after December 31, 2012.

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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

See exhibits listed in the Exhibit Index, which appears below.

(c) Financial statements of McMoRan Exploration Co. will be filed by amendment to this Annual Report on Form 10-K no later than March 1, 2013, in accordance with Rule 3-09 of Regulation S-X.

EXHIBIT INDEX

Exhibit Number	Description
2.1	Agreement and Plan of Merger, dated as of December 5, 2012, by and among Plains Exploration & Production Company, Freeport-McMoRan Copper & Gold Inc. and IMONC LLC (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed December 6, 2012, File No. 1-31470, or the December 6, 2012 Form 8-K).
2.2	Purchase and Sale Agreement dated as of September 4, 2012, and effective as of October 1, 2012, by and among BP Exploration & Production Inc., BP America Production Company and Plains Exploration & Production Company (incorporated by reference to Exhibit 2.1 to the Company’s Quarterly Report on Form 10-Q for the period ending September 30, 2012, File No. 1-31470, or the September 30, 2012 Form 10-Q).
2.3	Purchase and Sale Agreement dated as of September 7, 2012, and effective as of October 1, 2012, by and among Shell Offshore Inc. and Plains Exploration & Production Company (incorporated by reference to Exhibit 2.2 to the September 30, 2012 Form 10-Q).
2.4	Purchase and Sale Agreement dated as of November 3, 2011, and effective as of November 1, 2011, by and among Plains Exploration & Production Company, Pogo Producing Company LLC, Latigo Petroleum, Inc. and Linn Energy Holdings, LLC (incorporated by reference to Exhibit 2.5 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2011, File No. 1-31470, or the 2011 10-K).
2.5	Agreement and Plan of Merger, dated September 19, 2010, by and among Plains Exploration & Production Company, PXP Gulf Properties LLC, PXP Offshore LLC and McMoRan Exploration Co., McMoRan Oil & Gas LLC, McMoRan GOM, LLC and McMoRan Offshore LLC (incorporated by reference to Exhibit 2.1 to the Company’s Quarterly Report on Form 10-Q for the period ending September 30, 2010, File No. 1-31470).
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).

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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 Quarterly Report on Form 10-Q for the period ending June 30, 2004, File No. 1-31470).
3.3	Certificate of Amendment to the Certificate of Incorporation of Plains Exploration & Production Company dated November 6, 2007 (incorporated by reference to Exhibit 3.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-31470, or the 2007 10-K).
3.4	Second Amended and Restated Bylaws of Plains Exploration & Production Company, adopted as of September 14, 2011 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed September 16, 2011, File No. 1-31470).
4.1	Indenture, dated as of March 13, 2007, among Plains Exploration & Production Company, the Subsidiary Guarantors parties thereto, and Wells Fargo Bank, N.A., as Trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed March 13, 2007, File No. 1-31470, or the March 13, 2007 Form 8-K).
4.2	Fourth Supplemental Indenture, dated as of November 14, 2007, to the Indenture dated as of March 13, 2007, among Plains Exploration & Production Company, Laramie Land & Cattle Company, LLC, the Subsidiary Guarantors parties thereto and Wells Fargo Bank, N.A., as Trustee (incorporated by reference to Exhibit 4.5 to the 2007 10-K).
4.3	Fifth Supplemental Indenture, dated as of January 29, 2008, to the Indenture dated as of March 13, 2007, among Plains Exploration & Production Company, Latigo Gas Group, LLC, Latigo Gas Holdings, LLC, Latigo Gas Services, LP, Latigo Holding (Texas), LLC, Latigo Investments, LLC, Latigo Petroleum, Inc., Latigo Petroleum Texas LP, Pogo Energy, Inc., Pogo Panhandle 2004, L.P., Pogo Producing Company LLC, Pogo Producing (Texas Panhandle) Company, PXP Aircraft LLC, the Subsidiary Guarantors parties thereto and Wells Fargo Bank, N.A., as Trustee (incorporated by reference to Exhibit 4.6 to the 2007 10-K).
4.4	Sixth Supplemental Indenture, dated as of February 13, 2008, to the Indenture dated as of March 13, 2007, among Plains Exploration & Production Company, Pogo Partners, Inc., Pogo Producing (San Juan) Company, the Subsidiary Guarantors parties thereto and Wells Fargo Bank, N.A., as Trustee (incorporated by reference to Exhibit 4.5 to the 2007 10-K).
4.5	Seventh Supplemental Indenture, dated as of May 23, 2008 to the Indenture dated as of March 13, 2007, among Plains Exploration & Production Company, the Subsidiary Guarantors parties thereto and Wells Fargo Bank, N.A., as Trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed May 23, 2008, File No. 1-31470).
4.6	Eighth Supplemental Indenture, dated July 10, 2008, to the Indenture dated as of March 13, 2007, among Plains Exploration & Production Company, PXP Louisiana Operations LLC, the Subsidiary Guarantors parties thereto and Wells Fargo Bank, N.A. as Trustees (incorporated by reference to Exhibit 4.2 to the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2008, File No. 1-31470).
4.7	Ninth Supplemental Indenture, dated March 6, 2009, to Indenture, dated as of March 13, 2007, among Plains Exploration & Production Company, the Subsidiary Guarantors parties thereto and Wells Fargo Bank, N.A., as Trustee (including form of the 10% Senior Notes) (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed March 6, 2009, File No. 1-31470).

93

4.8	Tenth Supplemental Indenture, dated as of September 11, 2009, to Indenture dated as of March 13, 2007, among Plains Exploration & Production Company, the Subsidiary Guarantors parties thereto and Wells Fargo Bank, N.A., as Trustee (including form of the 8 5/8% Senior Notes) (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed September 11, 2009, File No. 1-31470).
4.9	Eleventh Supplemental Indenture, dated as of March 29, 2010, to Indenture dated as of March 13, 2007, among Plains Exploration & Production Company, the Subsidiary Guarantors parties thereto and Wells Fargo Bank, N.A., as Trustee (including form of the 7 5/8% Senior Notes) (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed March 29, 2010, File No. 1-31470).
4.10	Twelfth Supplemental Indenture, dated as of March 29, 2011, to the Indenture, dated as of March 13, 2007, among Plains Exploration & Production Company, the Subsidiary Guarantors parties thereto and Wells Fargo Bank, N.A., as Trustee (including form of the 6 5/8% Senior Notes) (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed March 29, 2011, File No. 1-31470).
4.11	Thirteenth Supplemental Indenture, dated as of November 21, 2011, to the Indenture, dated as of March 13, 2007, among Plains Exploration & Production Company, the Subsidiary Guarantors parties thereto and Wells Fargo Bank, N.A., as Trustee (including form of the 6 3/4% Senior Notes) (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed November 21, 2011, File No. 1-31470).
4.12	Fourteenth Supplemental Indenture, dated as of April 27, 2012, to the Indenture, dated as of March 13, 2007, among Plains Exploration & Production Company, the Subsidiary Guarantors parties thereto and Wells Fargo Bank, N.A., as Trustee (including form of the 6 1/8% Senior Notes) (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed April 27, 2012, File No. 1-31470).
4.13*	Fifteenth Supplemental Indenture, dated as of October 26, 2012, to the Indenture, dated as of March 13, 2007, among Plains Exploration & Production Company, the Subsidiary Guarantors parties thereto and Wells Fargo Bank, N.A., as Trustee.
4.14	Sixteenth Supplemental Indenture, dated as of October 26, 2012, to the Indenture, dated as of March 13, 2007, among Plains Exploration & Production Company, the Subsidiary Guarantors parties thereto and Wells Fargo Bank, N.A., as trustee (including form of the 6 1/2% Senior Notes) (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed October 26, 2012, File No. 1-31470, or the October 26, 2012 Form 8-K).
4.15	Seventeenth Supplemental Indenture, dated as of October 26, 2012, to the Indenture, dated as of March 13, 2007, among Plains Exploration & Production Company, the Subsidiary Guarantors parties thereto and Wells Fargo Bank, N.A., as trustee (including form of the 6 7/8% Senior Notes) (incorporated by reference to Exhibit 4.2 to the October 26, 2012 Form 8-K).
4.16	Amended and Restated Credit Agreement, dated as of November 30, 2012, among Plains Exploration & Production Company, as borrower, each of the lenders signatory thereto, and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed November 30, 2012, File No. 001-31470).

94

4.17	Form of Credit Agreement, dated November 18, 2011, among Plains Offshore Operations Inc., as borrower, each of the lenders that is a signatory thereto, and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Exhibit 4.20 to the 2011 10-K).
10.1	Consulting Agreement, dated as of January 19, 2006, between Montebello Land Company LLC and Cook Hill Properties LLC (incorporated by reference to Exhibit 10.3 to the Company’s Form 10-K for the year ended December 31, 2005, File No. 1-31470, or the 2005 10-K).
10.2	Consulting Agreement, dated as of January 19, 2006, between Lompoc Land Company LLC and Cook Hill Properties LLC (incorporated by reference to Exhibit 10.4 to the 2005 10-K).
10.3	Consulting Agreement, dated as of January 19, 2006, between Arroyo Grande Land Company LLC and Cook Hill Properties LLC (incorporated by reference to Exhibit 10.5 to the 2005 10-K).
10.4+	Amended and Restated Plains Exploration & Production Company 2004 Stock Incentive Plan (incorporated by reference to Exhibit 4.1 to the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2007, File No. 1-31470).
10.5+	Form of Plains Restricted Stock Award Agreement under the 2004 Incentive Plan (incorporated by reference to Exhibit 10.36 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2006, File No. 1-31470).
10.6+	Form of Restricted Stock Unit Agreement under the 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.10 to the 2011 10-K).
10.7+	Form of Plains Stock Appreciation Rights Agreement under the 2004 Incentive Plan (incorporated by reference to Exhibit 10.9 to the September 30, 2006 Form 10-Q).
10.8+	Amended and Restated Plains Exploration & Production Company Executives’ Long-Term Retention and Deferred Compensation Agreement effective as of February 10, 2006 (incorporated by reference to Exhibit 10.15 to the 2007 10-K).
10.9+	Amended and Restated Plains Exploration & Production Company Long-Term Retention and Deferral Agreement for James C. Flores (incorporated by reference to Exhibit 10.16 to the 2007 10-K).
10.10+	Amended and Restated Plains Exploration & Production Company Long-Term Retention and Deferral Agreement for John F. Wombwell (incorporated by reference to Exhibit 10.17 to the 2007 10-K).
10.11+	Amended and Restated Employment Agreement, effective as of June 9, 2004, between Plains Exploration & Production Company and James C. Flores (incorporated by reference to Exhibit 10.18 to the 2007 10-K).
10.12+	Amendment to Plains Exploration & Production Company Amended and Restated Employment Agreement, effective as of March 12, 2008, by and between Plains Exploration & Production Company and James C. Flores (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed March 12, 2008, File No. 1-31470).
10.13+	Amended and Restated Employment Agreement, effective as of June 9, 2004, between Plains Exploration & Production Company and John F. Wombwell (incorporated by reference to Exhibit 10.19 to the 2007 10-K).

95

10.14+	Amended and Restated Employment Agreement, effective as of November 8, 2006, between Plains Exploration & Production Company and Winston M. Talbert (incorporated by reference to Exhibit 10.20 to the 2007 10-K).
10.15+	Amended and Restated Employment Agreement, effective as of November 8, 2006, between Plains Exploration & Production Company and Doss R. Bourgeois (incorporated by reference to Exhibit 10.21 to the 2007 10-K).
10.16	Form of Election for Director Deferral of Restricted Stock Awards (incorporated by reference to Exhibit 10.23 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-31470).
10.17	Summary of Director Compensation Program (incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2006, File No. 1-31470).
10.18+	Plains Exploration & Production Company 2010 Incentive Award Plan (incorporated by reference to Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A filed on March 30, 2010, File No. 1-31470).
10.19+	Form of Plains Stock Appreciation Rights Agreement under the 2010 Incentive Plan (incorporated by reference to Exhibit 10.24 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2010, File No. 1-31470, or the 2010 10-K).
10.20+	Form of Plains Restricted Stock Award Agreement under the 2010 Incentive Plan (incorporated by reference to Exhibit 10.25 to the 2010 10-K).
10.21+	Form of Restricted Stock Unit Agreement under the 2010 Incentive Award Plan (incorporated by reference to Exhibit 10.25 to the 2011 10-K).
10.22+	Restricted Stock Unit Agreement, effective as of November 4, 2010, between Plains Exploration & Production Company and James C. Flores (incorporated by reference to Exhibit 10.27 to the 2010 10-K).
10.23	Registration Rights Agreement, dated December 30, 2010, by and between Plains Exploration & Production Company and McMoRan Exploration Co. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed January 6, 2011, File No. 1-31470, or the January 6, 2011 Form 8-K).
10.24	Stockholder Agreement, dated December 30, 2010, by and between Plains Exploration & Production Company and McMoRan Exploration Co. (incorporated by reference to Exhibit 10.2 to the January 6, 2011 Form 8-K).
10.25#	Crude Oil Purchase Agreement dated January 1, 2012, between Plains Exploration & Production Company and ConocoPhillips Company (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q/A for the period ended June 30, 2011, File No. 1-31470).
10.26	Plains Exploration & Production Company 2006 Incentive Plan (incorporated by reference to Exhibit 10.30 to the 2011 10-K).
10.27+	Form of Plains Restricted Stock Unit Agreement under the 2006 Incentive Plan (incorporated by reference to Exhibit 10.31 to the 2011 10-K).
10.28	Voting and Support Agreement dated as of December 5, 2012, by and between Plains Exploration & Production Company and Freeport-McMoRan Copper & Gold Inc. (incorporated by reference to Exhibit 10.1 to the December 6, 2012 Form 8-K).

96

10.29+	Letter Agreement dated as of December 5, 2012, by and among James C. Flores, Plains Exploration & Production Company and Freeport-McMoRan Copper & Gold Inc. (incorporated by reference to Exhibit 10.2 to the December 6, 2012 Form 8-K).
10.30+	Letter Agreement dated as of December 5, 2012, by and among Doss R. Bourgeois, Plains Exploration & Production Company and Freeport-McMoRan Copper & Gold Inc. (incorporated by reference to Exhibit 10.3 to the December 6, 2012 Form 8-K).
10.31+	Letter Agreement dated as of December 5, 2012, by and among Winston M. Talbert, Plains Exploration & Production Company and Freeport-McMoRan Copper & Gold Inc. (incorporated by reference to Exhibit 10.4 to the December 6, 2012 Form 8-K).
10.32+	Letter Agreement dated as of December 5, 2012, by and among John F. Wombwell, Plains Exploration & Production Company and Freeport-McMoRan Copper & Gold Inc. (incorporated by reference to Exhibit 10.5 to the December 6, 2012 Form 8-K).
10.33+*	Annual Performance Incentive Plan for Named Executive Officers.
21.1*	List of Subsidiaries of Plains Exploration & Production Company.
23.1*	Consent of PricewaterhouseCoopers LLP.
23.2*	Consent of Netherland, Sewell & Associates, Inc.
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.
99.1*	Report of Netherland, Sewell & Associates, Inc., United States locations.
99.2*	Report of Netherland, Sewell & Associates, Inc., Haynesville Shale of Louisiana and Texas.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document

* Filed herewith.

** Furnished herewith.

+ Management contracts or compensatory plans or arrangements.

# Pursuant to a request for confidential treatment, portions of this exhibit have been redacted from the publicly filed document and have been furnished separately to the SEC.

97

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: February 21, 2013	/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: February 21, 2013	/s/ James C. Flores
	James C. Flores, Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer)
Date: February 21, 2013	/s/ Isaac Arnold, Jr.
	Isaac Arnold, Jr., Director
Date: February 21, 2013	/s/ Alan R. Buckwalter, III
	Alan R. Buckwalter, III, Director
Date: February 21, 2013	/s/ Jerry L. Dees
	Jerry L. Dees, Director
Date: February 21, 2013	/s/ Tom H. Delimitros
	Tom H. Delimitros, Director
Date: February 21, 2013	/s/ Thomas A. Fry, III
	Thomas A. Fry, III, Director
Date: February 21, 2013	/s/ Charles G. Groat
	Charles G. Groat, Director
Date: February 21, 2013	/s/ John H. Lollar
	John H. Lollar, Director
Date: February 21, 2013	/s/ Winston M. Talbert
	Winston M. Talbert, Executive Vice President and Chief Financial Officer (Principal Financial Officer)
Date: February 21, 2013	/s/ Nancy I. Williams
	Nancy I. Williams, Vice President / Controller and Chief Accounting Officer (Principal Accounting Officer)

98

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, 2012 and 2011		F-3
Consolidated Statements of Income
For the years ended December 31, 2012, 2011 and 2010		F-4
Consolidated Statements of Cash Flows
For the years ended December 31, 2012, 2011 and 2010		F-5
Consolidated Statements of Equity
For the years ended December 31, 2012, 2011 and 2010		F-6
Notes to Consolidated Financial Statements		F-7

Financial statements of 50-percent-or-less-owned investees are listed in Item 15.(c). 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:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, equity and cash flows present fairly, in all material respects, the financial position of Plains Exploration & Production Company and its subsidiaries (the Company) at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Annual Report on Internal Control Over Financial Reporting appearing under Item 9A – Controls and Procedures. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we consider necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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.

As described in Management’s Annual Report on Internal Control Over Financial Reporting, management has excluded PXP Offshore LLC from its assessment of internal control over financial reporting as of December 31, 2012 because it was formed in connection with the Gulf of Mexico Acquisition on November 30, 2012. We have also excluded PXP Offshore LLC from our audit of internal control over financial reporting. PXP Offshore LLC is a wholly owned subsidiary of the Company whose total assets and total revenues represent 37% and 8%, respectively, of the related consolidated financial statement amounts, as of and for the year ended December 31, 2012.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 21, 2013

F-2

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS

(in thousands of dollars)

	December 31,
	2012			2011
ASSETS
Current Assets
Cash and cash equivalents	$	180,565		$	419,098
Accounts receivable		584,722			302,675
Commodity derivative contracts		56,208			50,964
Inventories		27,672			20,173
Investment		818,223			611,671
Deferred income taxes		150,876			20,723
Prepaid expenses and other current assets		21,464			16,073
		1,839,730			1,441,377
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		18,814,337			12,016,252
Not subject to amortization		3,631,475			2,409,449
Other property and equipment		153,344			145,959
		22,599,156			14,571,660
Less allowance for depreciation, depletion, amortization and impairment		(7,870,356	)		(6,846,365	)
		14,728,800			7,725,295
Goodwill		535,140			535,140
Commodity Derivative Contracts		903			12,678
Other Assets		193,710			76,982
	$	17,298,283		$	9,791,472
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	431,422		$	385,231
Commodity derivative contracts		18,942			3,761
Royalties and revenues payable		139,717			97,095
Stock-based compensation		31,275			21,676
Interest payable		105,440			39,342
Other current liabilities		88,917			79,081
Current maturities of long-term debt		164,288			-
		980,001			626,186
Long-Term Debt		9,979,369			3,760,952
Other Long-Term Liabilities
Asset retirement obligation		565,989			230,633
Commodity derivative contracts		26,810			823
Other		19,105			15,749
		611,904			247,205
Deferred Income Taxes		1,770,568			1,461,897
Commitments and Contingencies (Note 13)
Equity
Stockholders’ equity
Common stock, $0.01 par value, 250.0 million shares authorized, 143.9 million shares issued at December 31, 2012 and 2011		1,439			1,439
Additional paid-in capital		3,437,826			3,434,928
Retained earnings		637,411			337,991
Treasury stock, at cost, 15.0 million shares and 13.3 million shares at December 31, 2012 and 2011, respectively		(560,198	)		(509,722	)
		3,516,478			3,264,636
Noncontrolling interest
Preferred stock of subsidiary		439,963			430,596
		3,956,441			3,695,232
	$	17,298,283		$	9,791,472

See notes to consolidated financial statements.

F-3

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per share data)

	Year Ended December 31,
	2012			2011			2010
Revenues
Oil sales	$	2,325,922		$	1,528,656		$	1,142,760
Gas sales		232,441			428,220			399,607
Other operating revenues		6,944			7,612			2,228
		2,565,307			1,964,488			1,544,595
Costs and Expenses
Lease operating expenses		393,460			334,923			262,533
Steam gas costs		47,317			65,482			66,449
Electricity		43,950			41,242			42,794
Production and ad valorem taxes		73,873			55,225			29,446
Gathering and transportation expenses		73,852			62,103			50,680
General and administrative G&A		157,022			134,044			136,437
Acquisition and merger related costs		42,151			-			-
Depreciation, depletion and amortization		1,101,108			664,478			533,416
Impairment of oil and gas properties		-			-			59,475
Accretion		16,944			17,177			17,702
Legal recovery		-			-			(8,423	)
Other operating income		(27	)		(735	)		(4,130	)
		1,949,650			1,373,939			1,186,379
Income from Operations		615,657			590,549			358,216
Other (Expense) Income
Interest expense		(297,539	)		(161,316	)		(106,713	)
Debt extinguishment costs		(8,388	)		(120,954	)		(1,189	)
(Loss) gain on mark-to-market derivative contracts		(2,879	)		81,981			(60,695	)
Gain (loss) on investment measured at fair value		206,552			(52,675	)		(1,551	)
Other income		694			3,356			15,942
Income Before Income Taxes		514,097			340,941			204,010
Income tax benefit (expense)
Current		4,102			25,952			93,090
Deferred		(175,412	)		(160,214	)		(193,835	)
Net Income		342,787			206,679		$	103,265
Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary		(36,367	)		(1,400	)
Net Income Attributable to Common Stockholders	$	306,420		$	205,279
Earnings per Common Share
Basic	$	2.36		$	1.45		$	0.74
Diluted	$	2.32		$	1.44		$	0.73
Weighted Average Common Shares Outstanding
Basic		129,925			141,227			140,438
Diluted		131,867			142,999			141,897

See notes to consolidated financial statements.

F-4

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands of dollars)

	Year Ended December 31,
	2012			2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	342,787		$	206,679		$	103,265
Items not affecting cash flows from operating activities
Depreciation, depletion and amortization		1,101,108			664,478			533,416
Impairment of oil and gas properties		-			-			59,475
Accretion		16,944			17,177			17,702
Deferred income tax expense		175,412			160,214			193,835
Debt extinguishment costs		4,160			2,844			1,189
Loss (gain) on mark-to-market derivative contracts		2,879			(81,981	)		60,695
(Gain) loss on investment measured at fair value		(206,552	)		52,675			1,551
Non-cash compensation		60,247			49,193			50,875
Other non-cash items		8,270			(5,559	)		1,043
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(245,570	)		(62,389	)		(41,604	)
Inventories		960			4,660			(4,502	)
Accounts payable and other liabilities		85,638			62,008			(30,785	)
Stock-based compensation		(18,652	)		(2,922	)		(566	)
Income taxes receivable/payable		3,160			43,678			(33,119	)
Net cash provided by operating activities		1,330,791			1,110,755			912,470
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(1,854,255	)		(1,783,304	)		(1,048,858	)
Acquisition of oil and gas properties		(51,051	)		(40,515	)		(554,685	)
Gulf of Mexico Acquisition		(5,895,878	)		-			-
Proceeds from sales of oil and gas properties and related assets, net of costs and expenses		67,619			736,228			73,965
Derivative settlements		42,894			(55,412	)		(29,921	)
Additions to other property and equipment		(12,584	)		(13,140	)		(15,809	)
Other		-			1,552			-
Net cash used in investing activities		(7,703,255	)		(1,154,591	)		(1,575,308	)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		9,479,075			6,305,300			3,332,610
Repayments of revolving credit facilities		(8,644,075	)		(6,190,300	)		(2,942,610	)
Proceeds from five-year term loan		730,331			-			-
Proceeds from seven-year term loan		1,220,533			-			-
Principal payments of long-term debt		(156,182	)		(1,295,737	)		-
Proceeds from issuance of Senior Notes		3,750,000			1,600,000			300,000
Costs incurred in connection with financing arrangements		(130,261	)		(30,239	)		(22,771	)
Purchase of treasury stock		(88,490	)		(361,729	)		-
Net proceeds from issuance of noncontrolling interest in the form of preferred stock of subsidiary		-			430,246			-
Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary		(27,000	)		(1,050	)		-
Other		-			9			184
Net cash provided by financing activities		6,133,931			456,500			667,413
Net (decrease) increase in cash and cash equivalents		(238,533	)		412,664			4,575
Cash and cash equivalents, beginning of period		419,098			6,434			1,859
Cash and cash equivalents, end of period	$	180,565		$	419,098		$	6,434

See notes to consolidated financial statements.

F-5

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF EQUITY

(share and dollar amounts in thousands)

					Additional Paid-in Capital			Retained Earnings									Total Stockholders’ Equity			Noncontrolling Interest in the Form of Preferred Stock of Subsidiary			Total Equity
	Common Stock										Treasury Stock
	Shares		Amount								Shares			Amount
Balance at December 31, 2009		143,924	$	1,439	$	3,381,566		$	51,204			(4,512	)	$	(235,228	)	$	3,198,981					$	3,198,981
Net income		-		-		-			103,265			-			-			103,265						103,265
Restricted stock awards		-		-		80,515			-			-			-			80,515						80,515
Issuance of treasury stock for restricted stock awards		-		-		(34,209	)		(4,954	)		728			39,163			-						-
Exercise of stock options and other		-		-		(3	)		(895	)		20			1,102			204						204
Balance at December 31, 2010		143,924		1,439		3,427,869			148,620			(3,764	)		(194,963	)		3,382,965						3,382,965
Net income		-		-		-			205,279			-			-			205,279		$	1,400			206,679
Restricted stock awards		-		-		38,092			-			-			-			38,092						38,092
Treasury stock purchases		-		-		-			-			(10,415	)		(361,729	)		(361,729	)		-			(361,729	)
Issuance of treasury stock for restricted stock awards		-		-		(31,033	)		(15,857	)		876			46,890			-			-			-
Issuance of noncontrolling interest in the form of preferred stock of subsidiary		-		-		-			-			-			-			-			430,246			430,246
Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary		-		-		-			-			-			-			-			(1,050	)		(1,050	)
Exercise of stock options and other		-		-		-			(51	)		1			80			29			-			29
Balance at December 31, 2011		143,924		1,439		3,434,928			337,991			(13,302	)		(509,722	)		3,264,636			430,596			3,695,232
Net income		-		-		-			306,420			-			-			306,420			36,367			342,787
Restricted stock awards		-		-		33,892			-			-			-			33,892						33,892
Treasury stock purchases		-		-		-			-			(2,390	)		(88,490	)		(88,490	)					(88,490	)
Issuance of treasury stock for restricted stock awards		-		-		(30,994	)		(6,994	)		733			37,988			-						-
Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary		-		-		-			-			-			-			-			(27,000	)		(27,000	)
Exercise of stock options and other		-		-		-			(6	)		-			26			20			-			20
Balance at December 31, 2012		143,924	$	1,439	$	3,437,826		$	637,411			(14,959	)	$	(560,198	)	$	3,516,478		$	439,963		$	3,956,441

See notes to consolidated financial statements.

F-6

PLAINS EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Summary of Significant Accounting Policies

General. Plains Exploration & Production Company, a Delaware corporation formed in 2002 (“PXP”, the “Company”, “us”, “our”, or “we”), is an independent energy company engaged in the upstream oil and gas business. The upstream business acquires, develops, explores for and produces oil and gas. Our upstream activities are located in the United States.

Our consolidated financial statements include the accounts of all our consolidated subsidiaries. We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to prior year statements to conform to the current year presentation.

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; (3) timing of transfers from oil and gas properties not subject to amortization; (4) valuation of our investment; (5) determination of fair value of assets acquired and liabilities assumed and recording of goodwill and deferred taxes, if any, in connection with business combinations; (6) noncontrolling interest in the form of preferred stock of subsidiary; (7) income taxes; (8) accrued assets and liabilities; (9) stock-based compensation; (10) asset retirement obligations and (11) valuation of derivative instruments. Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates, and actual results may differ from these estimates.

Oil and Gas Properties. We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration 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 and development activities. General and administrative costs associated with production, operations, marketing and general corporate activities are expensed as incurred. Capitalized costs, along with our estimated future costs to develop proved reserves and asset retirement costs which are not already included in oil and gas properties, net of related salvage value, are amortized to expense by the unit-of-production method using engineers’ estimates of proved oil and natural gas reserves. The costs of unproved oil and gas 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. See Note 19 – Oil and Natural Gas Activities – Capitalized Costs. Proceeds from the sale of oil and natural gas properties are accounted for as reductions to capitalized costs unless such sales cause a significant change in the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center, in which case a gain or loss is recognized.

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Under the SEC’s full cost accounting rules, we review the carrying value of our oil and gas properties each quarter on a country-by-country basis. Under these rules, for each cost center, capitalized costs of oil and gas properties (net of accumulated depreciation, depletion and amortization and related deferred income taxes) may not exceed a “ceiling” equal to:

• the present value, discounted at 10%, of estimated future net cash flows from proved oil and gas reserves, net of estimated future income taxes; plus

• the cost of unproved properties not being amortized; plus

• the lower of cost or estimated fair value of unproved properties 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 twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. Our reference prices are the West Texas Intermediate, or WTI, for oil and the Henry Hub spot price for gas. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. The reserve estimates exclude the effect of any derivatives we have in place. The rules require an impairment if our capitalized costs exceed this “ceiling”.

During the first quarter of 2012, due to low natural gas prices, our assessment of the unproved property in the Haynesville Shale area indicated an impairment and accumulated costs of approximately $483 million were transferred to the full cost pool.

During the third quarter of 2011, we determined not to develop the Friesian prospect and the lease terminated by its terms. The accumulated costs of approximately $460 million associated with the project were transferred to the full cost pool.

During the second quarter of 2010, we completed our interpretation of seismic and drilling data from our two offshore Vietnam exploratory wells and decided not to pursue additional exploratory activities in this area. We terminated our production sharing contract in accordance with its terms. The costs related to our Vietnam oil and gas properties not subject to amortization were transferred to our Vietnam full cost pool where they were subject to the ceiling limitation. Because our Vietnam full cost pool had no associated proved oil and gas reserves, we recorded a non-cash pre-tax impairment charge of $59.5 million. We also recorded a corresponding tax benefit of $23.0 million.

Asset Retirement Obligation. We record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with an offsetting increase to proved oil and gas properties. For oil and gas properties, this is the period in which the well is drilled or acquired. 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. Each period we accrete the liability to its then present value and depreciate the capitalized cost over the useful life of the related asset.

Other Property and Equipment. Other property and equipment is recorded at cost and consists primarily of land and real estate development costs, aircraft, office furniture and fixtures and computer hardware and software. Acquisitions, renewals, and betterments are capitalized; maintenance and repairs are expensed. Depreciation is calculated using the straight-line method over estimated useful lives of three to twenty years. Net gains or losses on property and equipment disposed of are included in operating income in the period in which the transaction occurs.

Cash and Cash Equivalents. Cash and cash equivalents consist primarily of highly liquid money market mutual funds that hold U.S. government securities and demand deposits with financial

F-8

institutions. The mutual funds are available to us upon demand. There were no outstanding checks that had not been presented for payment in accounts payable at December 31, 2012. At December 31, 2011, accounts payable included $7.0 million 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. At December 31, 2012 and 2011, inventory consisted of the following (in thousands):

	December 31,
	2012		2011
Oil	$	11,394	$	7,075
Materials and supplies		16,278		13,098
	$	27,672	$	20,173

Federal and State Income Taxes. We recognize deferred tax liabilities and assets for expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax bases of assets and liabilities using tax rates in effect for the year in which the differences are expected to reverse. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that some portion or all of the related tax benefits will not be realized.

We have also established a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not, based on the technical merits of the position, that the position will be sustained on examination by the taxing authorities. Additionally, the amount of the tax benefit recognized is the largest amount of benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. Furthermore, we recognize potential penalties and interest related to unrecognized tax benefits as a component of income tax expense. See Note 12 – Income Taxes.

Revenue Recognition. Oil and gas revenue from our interests in producing wells is recognized upon delivery and passage of title using the sales method for gas imbalances, net of any royalty interests or other profit interests in the produced product. If our sales of production volumes for a well exceed our portion of the estimated remaining recoverable reserves of the well, a liability is recorded. No receivables are recorded for those wells on which we have taken less than our ownership share of production unless the amount taken by other parties exceeds the estimate of their remaining reserves. We had no material gas imbalances at December 31, 2012 or 2011.

Derivative Financial Instruments. We use various derivative instruments to manage our exposure to commodity price risk on sales of oil and gas production. We do not enter into derivative instruments for speculative trading purposes. We present the fair value of our derivative contracts on a net basis where the right of offset is provided for in our counterparty agreements. See Note 7 – Commodity Derivative Contracts.

Investment. We have elected to measure our investment at fair value with changes in fair value included in our income statement. If we had not elected the fair value method, the investment would have qualified for the equity method of accounting, under which our proportionate share of the investee’s income would have been reported in our income statement. See Note 8 – Investment and Note 9 – Fair Value Measurements of Assets and Liabilities.

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Fair Value. Fair value is the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants. The authoritative guidance characterizes inputs used in determining fair value according to a hierarchy that prioritizes inputs based upon the degree to which they are observable. The three levels of the fair value hierarchy are as follows:

• Level 1 – Valuations utilizing quoted, unadjusted prices for assets or liabilities in active markets for identical assets or liabilities as of the reporting date. This is the most reliable evidence of fair value and does not require a significant amount of judgment.

• Level 2 – Valuations utilizing market-based inputs that are directly or indirectly observable but not considered Level 1 quoted prices, including quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; or valuation techniques whose inputs are observable. If the asset or liability has a specified contractual term, the Level 2 input must be observable for substantially the full term of the asset or liability.

• Level 3 – Valuations utilizing techniques whose significant inputs are unobservable. This provides the least objective evidence of fair value and requires a significant degree of judgment.

A financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. We estimate the fair values of our derivative instruments and investment and determine their placement within the fair value hierarchy levels as described above. See Note 9 – Fair Value Measurements of Assets and Liabilities.

Goodwill. In a purchase transaction, goodwill represents the excess of the purchase price plus the fair value of liabilities assumed (including deferred income taxes recorded in connection with the transaction) over the fair value of the assets acquired. At December 31, 2012, goodwill totaled $535 million and represented approximately 3% of our total assets.

Goodwill is not amortized; instead it is tested at least annually for impairment at a level of reporting referred to as a reporting unit. Impairment occurs when the carrying amount of goodwill exceeds its implied fair value. Companies are permitted to make a qualitative assessment of a reporting unit’s fair value prior to performing the two-step goodwill impairment test, which is used to identify potential goodwill impairment and measure the amount of goodwill impairment loss to be recognized, if any. If it is determined through the qualitative assessment that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step impairment test is unnecessary. The qualitative assessment is optional, allowing companies to go directly to the quantitative assessment.

The first step of the quantitative goodwill impairment test 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 to be 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 the reporting unit’s goodwill with the carrying amount of that goodwill. If the carrying amount of that reporting unit’s 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.

F-10

We elected to continue performing our annual goodwill impairment assessment under the quantitative two-step impairment test. We follow the full cost method of accounting for oil and gas activities and all of our producing properties are located in the United States. We have determined that for the purpose of performing an impairment test, we have one reporting unit.

The first step of the goodwill impairment test requires that we make an estimate of the fair value of the reporting unit. Quoted market prices in active markets are the best evidence of fair value. Historically, we have estimated the fair value of the reporting unit by applying a control premium to the quoted market price of our common stock. The control premium was determined through reference to control premiums in merger and acquisition transactions for our industry and other comparable industries. This requires that we make certain judgments about the selection of merger and acquisition transactions and transaction premiums. On December 5, 2012, the Company entered into an Agreement and Plan of Merger, or the Freeport-McMoRan Merger Agreement, with Freeport-McMoRan and IMONC LLC, a wholly owned subsidiary of Freeport-McMoRan, or the Merger Sub, pursuant to which Freeport-McMoRan will acquire the Company. See Note 2 – Proposed Merger with Freeport-McMoRan Copper & Gold Inc. Subsequently, our stock has been trading at a premium that represents fair value of the reporting unit as a whole. Consequently, no additional control premium was applied.

We perform our goodwill impairment test annually as of December 31 and have recorded no impairment. We also perform interim impairment tests if events occur or circumstances change that would indicate the fair value of our reporting unit may be below its carrying amount.

Events affecting oil and gas prices may cause a decrease in the fair value of the reporting unit, and we could have an impairment of our goodwill in future periods. Additionally, failure to complete the merger could result in changes to the fair value of the reporting unit and result in an impairment of our goodwill. 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 equity.

Noncontrolling Interest in the Form of Preferred Stock of Subsidiary. Noncontrolling interest in the form of preferred stock of subsidiary represents third-party ownership in the net assets of our consolidated subsidiary Plains Offshore Operations Inc., or Plains Offshore, in the form of convertible perpetual preferred stock and associated non-detachable warrants, which are classified as permanent equity in our consolidated balance sheet since redemption for cash of the preferred stock is within our control. See Note 5 – Noncontrolling Interest in the Form of Preferred Stock of Subsidiary.

Business Segment Information. We acquire, develop, explore for and produce oil and gas in the United States. We allocate capital resources on a project-by-project basis across our entire asset base to maximize profitability and measure financial performance as a single enterprise and not on an area-by-area basis. Accordingly, we have one operating segment, our oil and gas operations.

Stock-Based Compensation. Our stock-based compensation cost is measured based on the fair value of the award on the grant date and remeasured each reporting period for liability-classified awards. The compensation cost is recognized net of estimated forfeitures over the requisite service period. See Note 11 – Stock-Based and Other Compensation Plans.

Recent Accounting Pronouncements. In December 2011, the Financial Accounting Standards Board, or FASB, issued authoritative guidance requiring entities to disclose both gross and net information about financial instruments and transactions eligible for offset in the statement of financial position as well as financial instruments and transactions subject to agreements similar to master netting arrangements. The additional disclosures will enable users of the financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. In

F-11

January 2013, the FASB issued further authoritative guidance clarifying the scope of these disclosure requirements to include bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that either have a right of offset or are subject to an enforceable master netting arrangement or similar agreements. These disclosure requirements are effective for interim and annual periods beginning after January 1, 2013, and will primarily impact our disclosures associated with our commodity derivative instruments. We do not expect this guidance to have a significant impact on our consolidated financial position, results of operations or cash flows.

Note 2 — Proposed Merger with Freeport-McMoRan Copper & Gold Inc.

On December 5, 2012, the Company entered into the Freeport-McMoRan Merger Agreement with Freeport-McMoRan and the Merger Sub, pursuant to which Freeport-McMoRan will acquire the Company for approximately $6.9 billion in cash and stock, based on the closing price of Freeport-McMoRan stock on December 4, 2012.

The Freeport-McMoRan Merger Agreement provides that the Company will merge with and into the Merger Sub, with the Merger Sub continuing as the surviving company and a wholly owned subsidiary of Freeport-McMoRan. Subject to the terms and conditions of the Freeport-McMoRan Merger Agreement, PXP stockholders have the right to receive 0.6531 shares of Freeport-McMoRan common stock and $25.00 in cash, equivalent to total consideration of $50.00 per PXP share, based on the closing price of Freeport-McMoRan stock on December 4, 2012. PXP stockholders may elect to receive cash or stock consideration, subject to proration in the event of oversubscription, with the value of the cash and stock per share consideration to be equalized at closing.

The Freeport-McMoRan Merger Agreement provides that each share of restricted stock and each stock-settled restricted stock unit, or stock-settled RSU, including each stock-settled RSU that will become issuable or creditable in connection with the consummation of the merger pursuant to any employment agreement, RSU agreement or other written agreement, will become fully vested and be converted into the right to receive, at the election of the holder, cash consideration or stock consideration to be paid or provided at the time contemplated by the original award agreement, except for certain stock-settled RSUs held by the Company’s named executive vice presidents that will convert into stock consideration (with right to elect up to 25% as cash consideration), and certain stock-settled RSUs held by Mr. Flores that will automatically convert into stock consideration, in each case pursuant to the terms of the executive’s respective letter agreement among each named executive officer, Freeport-McMoRan and the Company. Each cash-settled restricted stock unit, or cash-settled RSU, will become fully vested in accordance with the terms of the applicable award agreement and be converted into the right to receive cash consideration, payable at such time as the cash per-share consideration is payable generally to PXP stockholders who elect to receive cash consideration. Stock appreciation rights, or SARs, relating to shares of PXP common stock outstanding and unexercised will become fully vested and be converted into SARs relating to shares of Freeport-McMoRan common stock.

The Freeport-McMoRan Merger Agreement provides that, upon termination of the Freeport-McMoRan Merger Agreement under certain circumstances, the Company may be required to reimburse Freeport-McMoRan for its expenses in an amount up to $69.0 million and/or pay Freeport-McMoRan a termination fee in an amount equal to $207.0 million less any expenses reimbursed by the Company.

Completion of the merger is subject to customary conditions, including approval by PXP stockholders and receipt of required regulatory approvals. The merger is expected to close in the second quarter of 2013.

F-12

On December 5, 2012, Freeport-McMoRan entered into an Agreement and Plan of Merger, or the MMR Merger Agreement, with McMoRan and INAVN Corp., a wholly owned subsidiary of Freeport-McMoRan, or the MMR Merger Sub, pursuant to which MMR Merger Sub will be merged with and into McMoRan, or the MMR Merger, with McMoRan continuing as the surviving company and a wholly owned subsidiary of Freeport-McMoRan. The per share consideration consists of $14.75 in cash and 1.15 units of a royalty trust, which will hold a 5% overriding royalty interest in future production from McMoRan’s existing ultra-deep exploration properties. In connection with the MMR Merger, on December 5, 2012, PXP and Freeport-McMoRan entered into a Voting and Support Agreement, or the Support Agreement. The Support Agreement generally requires that the Company, in its capacity as a stockholder of 31.5% of McMoRan, vote all of its shares of McMoRan common stock in favor of the MMR Merger and against alternative transactions and generally prohibits us from transferring our shares of McMoRan common stock prior to the consummation of the MMR Merger. The Support Agreement will terminate upon the earlier of (i) the Expiration Date (defined as the earlier of (A) the consummation of the MMR Merger and (B) the termination of the MMR Merger Agreement) and (ii) any breach by Freeport-McMoRan of its obligation under the Freeport-McMoRan Merger Agreement not to change the merger consideration in the MMR Merger Agreement, amend the covenant relating to standstill waivers in the MMR Merger Agreement or otherwise materially amend any material provision of the MMR Merger Agreement, or terminate the MMR Merger Agreement, without PXP’s prior written consent. The MMR Merger is subject to the approval of the shareholders of McMoRan, including the approval of an amendment to McMoRan’s certificate of incorporation, receipt of regulatory approvals and customary closing conditions.

Note 3 — Acquisitions

Gulf of Mexico

During the fourth quarter of 2012, we completed the acquisition of certain oil and gas interests in and near the Holstein, Diana, Hoover, Horn Mountain, Marlin, Dorado, King and Ram Powell Fields located in the Gulf of Mexico from BP, subject to customary post-closing adjustments. After pre-closing adjustments from the effective date of October 1, 2012, which resulted in a reduction to the $5.55 billion purchase price of approximately $191.0 million, PXP paid $5.36 billion in cash, which included the deposit of $555.0 million previously paid to BP. In December 2012, we recorded a net reduction of approximately $45.0 million to the purchase price primarily associated with oil and gas revenues between the effective and closing dates.

During the fourth quarter of 2012, we also completed the acquisition of the 50% working interest in the Holstein Field located in the Gulf of Mexico from Shell Offshore, Inc., or Shell, subject to customary post-closing adjustments. After pre-closing adjustments from the effective date of October 1, 2012, which resulted in a reduction to the $560.0 million purchase price of approximately $27.9 million, PXP paid $532.1 million in cash.

We funded the Gulf of Mexico Acquisition primarily with our revolving line of credit and term loan credit facilities, collectively the Amended Credit Facility, and the issuance of Senior Notes. Transaction costs of approximately $66.0 million, including (i) $31.8 million of commitment fees and related expenses associated with a new senior unsecured bridge credit facility, or Bridge Credit Facility, which was recorded as interest expense because we did not borrow under the Bridge Credit Facility, (ii) a $20.0 million fee that we paid in connection with an amendment to our existing stockholders agreements with the preferred investors of Plains Offshore to limit certain exclusivity provisions and (iii) certain investment, advisory, legal and other acquisition related fees, have been expensed.

We accounted for the Gulf of Mexico Acquisition, effective October 1, 2012, as acquisitions of businesses under purchase accounting rules. The assets acquired and liabilities assumed related to

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the Gulf of Mexico Acquisition were recorded at their fair values as of the closing date of the Gulf of Mexico Acquisition on November 30, 2012. The fair values below are preliminary subject to our determination of asset retirement obligations and fair values of assets acquired and liabilities assumed that have not been completed as of December 31, 2012. These and other estimates are subject to change as additional information becomes available and is assessed by us and BP and Shell, respectively, and agreement is reached on the respective final settlement statements. The consideration paid for the Gulf of Mexico Acquisition and the assets acquired and liabilities assumed recognized at the acquisition date is shown below (in thousands):

	BP			Shell			Total
Cash consideration	$	5,363,300		$	532,578		$	5,895,878
Fair value of assets acquired and liabilities assumed:
Accounts receivable	$	41,186		$	-		$	41,186
Inventories		7,754			-			7,754
Other current assets		-			2,410			2,410
Oil and natural gas properties
Subject to amortization		3,836,558			298,615			4,135,173
Not subject to amortization		1,768,348			278,709			2,047,057
Asset retirement obligation		(290,546	)		(47,156	)		(337,702	)
Net assets acquired	$	5,363,300		$	532,578		$	5,895,878

Under the acquisition method of accounting, the purchase price is allocated to the assets acquired and liabilities assumed based on their estimated fair values, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. Based on the purchase price allocation, no goodwill was recognized.

We recorded revenues and expenses attributable to the Gulf of Mexico Acquisition beginning on the closing date of November 30, 2012. Revenues and earnings attributable to the Gulf of Mexico Acquisition included in our consolidated statement of income for the year ended December 31, 2012 were $196.2 million and $39.4 million, respectively.

Unaudited Pro Forma Impact of Gulf of Mexico Acquisition

The following unaudited pro forma information shows the pro forma effect of the Gulf of Mexico Acquisition, the issuance of Senior Notes and the use of proceeds from the Amended Credit Facility. We believe the assumptions used provide a reasonable basis for representing the pro forma significant effects directly attributable to the Gulf of Mexico Acquisition and its associated financing. The unaudited pro forma information assumes such transaction occurred on January 1, 2011. The unaudited pro forma information does not purport to represent what our results of operations would have been if such transactions had occurred on such dates (in thousands, except per share data):

	Year Ended December 31,
	2012		2011
Revenues	$	4,328,678	$	4,038,033
Net income from continuing operations		881,078		808,818
Net income attributable to common stockholders		844,711		807,418

Eagle Ford Shale

During the fourth quarter of 2010, we completed the acquisition of approximately 60,000 net acres in the Eagle Ford Shale oil and gas condensate windows in South Texas for approximately $596.3 million in cash. We funded the acquisition primarily with borrowings under our revolving line of credit.

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Note 4 — Divestments

Panhandle and South Texas Properties

In December 2011, we divested our Texas Panhandle properties to Linn Energy, LLC. After the exercise of third party preferential rights and preliminary closing adjustments, we received approximately $554.8 million in cash. The cash proceeds received, net of approximately $6.2 million in transaction costs, were primarily used to reduce indebtedness. Our aggregate working interest in the Texas Panhandle properties generated total sales volumes of approximately 84 MMcfe per day during the third quarter of 2011 and had 263 Bcfe of estimated proved reserves as of December 31, 2010. Additionally, during the first quarter of 2012, we completed the divestment of our interests in approximately 2,000 gross leasehold acres in our Texas Panhandle properties to Linn Energy, LLC. After the exercise of third party preferential rights and closing adjustments, we received approximately $43.4 million in cash. The Texas Panhandle divestment was effective November 1, 2011.

At December 31, 2012, we continue to have interests in approximately 40,000 gross leasehold acres in the Texas Panhandle. We expect to receive additional proceeds from future closings, as may be further modified for additional post-closing adjustments.

In December 2011, we completed the divestment of all our working interests in our South Texas conventional natural gas properties to a third party. After preliminary closing adjustments, we received $181.0 million in cash. The cash proceeds received were primarily used to reduce indebtedness. The transaction was effective September 1, 2011.

The proceeds from the 2012 and 2011 sales of oil and gas properties were recorded as reductions to capitalized costs pursuant to full cost accounting rules.

Gulf of Mexico

In December 2010, we completed the divestment of our Gulf of Mexico shallow water shelf properties to McMoRan Exploration Co. At closing and after preliminary closing adjustments, we received approximately $86.1 million in cash, which included $11.1 million in working capital adjustments, and 51.0 million shares of McMoRan common stock in exchange for all our interests in our Gulf of Mexico leasehold located in less than 500 feet of water. The transaction was completed pursuant to an Agreement and Plan of Merger dated as of September 19, 2010, and effective as of August 1, 2010, between us and certain of our subsidiaries and McMoRan and certain of its subsidiaries. The McMoRan shares were valued at approximately $665.9 million based on McMoRan’s closing stock price of $17.18 on December 30, 2010 discounted to reflect certain limitations on the marketability of the McMoRan shares under the registration rights agreement and stockholder agreement entered into by us and McMoRan at the closing of the transaction. The cash proceeds received, net of approximately $8.8 million in transaction costs, were primarily used to repay outstanding borrowings under our credit facilities. The proceeds were recorded as reductions to capitalized costs pursuant to full cost accounting rules.

Note 5 — Noncontrolling Interest in the Form of Preferred Stock of Subsidiary

In October 2011, we entered into a securities purchase agreement with EIG Global Energy Partners, or EIG, pursuant to which we received $430.2 million of net cash proceeds in November 2011, upon closing of the transaction, in exchange for a 20% equity interest in Plains Offshore. Plains Offshore holds certain of our oil and natural gas properties and assets located in the United States Gulf of Mexico in water depths of 500 feet or more, including the Lucius oil field and the Phobos exploration

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prospect and excluding the properties acquired from BP and Shell (see Note 3 – Acquisitions – Gulf of Mexico). The proceeds raised are expected to be used to fund Plains Offshore’s share of capital investment in the Lucius oil field, which is expected to commence production in 2014, and the Phobos prospect exploratory drilling, for which results are expected in 2013 and other activities. Under the agreement and upon closing of the transaction, Plains Offshore issued to EIG managed funds and accounts, or the EIG Funds (i) 450,000 shares of Plains Offshore 8% convertible perpetual preferred stock and (ii) non-detachable warrants to purchase in aggregate 9,121,000 shares of Plains Offshore’s common stock with an exercise price of $20 per share. In addition, Plains Offshore issued 87 million shares of Plains Offshore Class A common stock, which will be held in escrow until the conversion and cancellation of the preferred stock or the exercise of the warrants held by EIG. The preferred stock pays quarterly cash dividends of 6% per annum and an additional 2% per annum dividend. The 2% dividend may be deferred and accumulated quarterly until paid. The shares of preferred stock also fully participate, on an as-converted basis at four times, in cash dividends distributed to any class of common stockholders of Plains Offshore.

The preferred holders have the right, at any time at their option, to convert any or all of such holder’s preferred stock and exercise any of the associated non-detachable warrants into shares of Class A common stock of Plains Offshore, at an initial conversion/exercise price of $20 per share; the conversion price is subject to adjustment as a result of certain events. Furthermore, under the terms of the securities purchase agreement, Plains Offshore has the right to convert all or a portion of the outstanding shares of preferred stock if certain events occur more than 180 days after an initial public offering or a qualified public offering of Plains Offshore. We have a right to purchase shares of preferred stock, common stock and warrants under certain circumstances in order to permit the consolidation of Plains Offshore for federal income tax purposes. Additionally, at any time on or after the fifth anniversary of the closing date, we may exercise a call right to purchase all, but not less than all, of the outstanding preferred stock and associated non-detachable warrants for cash, at a price equal to the liquidation preference described below.

At any time after the fourth anniversary of the closing date, a majority of the preferred holders may cause Plains Offshore to use its commercially reasonable efforts to consummate an exit event. An exit event, as defined in the stockholders agreement, means, at the sole option of Plains Offshore (i) the purchase by us or the redemption by Plains Offshore of all the preferred stock, warrants and common stock held by the EIG Funds for the aggregate fair value thereof, or the repurchase option; (ii) a sale of Plains Offshore or a sale of all or substantially all of its assets, in each case in an arms’ length transaction with a third party, at the highest price available after reasonable marketing efforts by Plains Offshore; or (iii) a qualified initial public offering. Under the repurchase option, the form of consideration shall be at our sole discretion, which could be (a) cash, (b) our shares of registered, freely-tradable common stock (valued at 95% of the average closing sale price) or (c) a combination of (a) and (b) above. In the event that Plains Offshore fails to consummate an exit event prior to the applicable exit event deadline, the conversion price of the preferred stock and the exercise price of the warrants will immediately and automatically be adjusted such that all issued and outstanding shares of preferred stock on an as-converted basis taken together with shares of common stock issuable upon exercise of the warrants, in the aggregate, will constitute 49% of the common equity securities of Plains Offshore on a fully diluted basis. In addition, we will be required to purchase $300 million of junior preferred stock in Plains Offshore. If this occurs, our cash expenditures relating to the assets of Plains Offshore will approximate the cash contribution made by EIG to Plains Offshore. Plains Offshore must use the proceeds to repay its senior credit facility. See Note 6 – Long-Term Debt.

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The preferred holders are entitled to vote on all matters on which common stockholders are entitled to vote. Each holder is entitled to one vote for each share that such holder would be entitled to receive if such holder’s shares of preferred stock were converted into common shares on the record date set by the board of directors for such vote. Prior to an initial public offering, the holders have preemptive rights with respect to certain issuances of equity securities of Plains Offshore. In the event that we or any of our affiliates intend to transfer any of their common shares to an unaffiliated third party purchaser, each other equity holder will have certain tag along rights.

In the event of liquidation of Plains Offshore, each preferred holder is entitled to receive the liquidation preference before any payment or distribution is made on any junior or common stock. A liquidation event includes any of the following events: (i) the liquidation, dissolution or winding up of Plains Offshore, whether voluntary or involuntary, (ii) a sale, consolidation or merger of Plains Offshore in which the stockholders immediately prior to such event do not own at least a majority of the outstanding shares of the surviving entity, or (iii) a sale or other disposition of all or substantially all of Plains Offshore’s assets to a person other than us or our affiliates. The liquidation preference is equal to (i) the greater of (a) 1.25 times the initial offering price and (b) the sum of (1) the fair market value of the shares of common stock issuable upon conversion of the preferred stock and (2) the applicable tax adjustment amount, plus (ii) any accrued dividends and accumulated dividends.

The non-detachable warrants may be exercised at any time on the earlier of (i) the eighth anniversary of the original issue date or (ii) a termination event. Under the terms of the securities purchase agreement, a termination event is defined as the occurrence of any of (a) the conversion of the preferred stock, (b) the redemption of the preferred stock, (c) the repurchase by us or any of our affiliates of the preferred stock or (d) a liquidation event described above. The non-detachable warrants are considered to be embedded instruments for accounting purposes as the instrument cannot be both legally detached and separately exercised from the host preferred stock, nor can the non-detachable warrants be transferred or sold without also transferring the ownership in the preferred stock.

The preferred stock of Plains Offshore is classified as permanent equity in our consolidated balance sheet since redemption for cash of the preferred interests is within our and Plains Offshore’s control.

During the year ended December 31, 2012, Plains Offshore declared quarterly dividends of approximately $36.4 million, or $80.67 per share of preferred stock, $60.00 per share of which was paid in cash with the remaining deferred. During the year ended December 31, 2011, Plains Offshore declared a quarterly dividend of $1.4 million, or $3.11 per share of preferred stock, $2.33 per share of which was paid in cash with the remaining deferred. As of December 31, 2012, Plains Offshore deferred a total of $9.7 million of preferred stock dividends.

In connection with the Gulf of Mexico Acquisition, we paid and expensed a $20.0 million fee associated with an amendment to our existing stockholders agreements with the preferred investors of Plains Offshore to limit certain exclusivity provisions.

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Note 6 — Long-Term Debt

At December 31, 2012 and 2011, long-term debt consisted of (in thousands):

	December 31,
	2012			2011
Amended Credit Facility
Revolving line of credit	$	1,570,000		$	735,000
Five-year term loan due 2017 (1)		730,638			-
Seven-year term loan due 2019 (2)		1,220,844			-
Plains Offshore senior credit facility		-			-
7 3/4% Senior Notes due 2015		-			79,281
10% Senior Notes due 2016 (3)		177,266			175,385
7% Senior Notes due 2017		-			76,901
7 5/8% Senior Notes due 2018		400,000			400,000
6 1/8% Senior Notes due 2019		750,000			-
8 5/8% Senior Notes due 2019 (4)		394,909			394,385
7 5/8% Senior Notes due 2020		300,000			300,000
6 1/2% Senior Notes due 2020		1,500,000			-
6 5/8% Senior Notes due 2021		600,000			600,000
6 3/4% Senior Notes due 2022		1,000,000			1,000,000
6 7/8% Senior Notes due 2023		1,500,000			-
		10,143,657			3,760,952
Current maturities of long-term debt		(164,288	)		-
	$	9,979,369		$	3,760,952

(1) The amount is net of unamortized issue costs of $19.4 million at December 31, 2012.

(2) The amount is net of unamortized issue costs of $29.2 million at December 31, 2012.

(3) The amount is net of unamortized discount of $7.6 million and $9.5 million at December 31, 2012 and December 31, 2011, respectively.

(4) The amount is net of unamortized discount of $5.1 million and $5.6 million at December 31, 2012 and December 31, 2011, respectively.

As of December 31, 2012, aggregate total maturities of long-term debt in the next five years are $3.0 billion, including $164.3 million in each of the years 2013 through 2015, $349.2 million in 2016 and $2.1 billion in 2017.

Amended Credit Facility. In November 2012, we entered into the Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A. as administrative agent and the lenders party thereto, or the Amended Credit Agreement, which amended and restated our senior revolving credit facility. The Amended Credit Agreement provided for (i) a five-year revolving line of credit, a five-year term loan and a seven-year term loan and (ii) an initial borrowing base of $5.175 billion, which will be redetermined on an annual basis, with us and the lenders of the revolving line of credit each having the right to one annual interim unscheduled redetermination, and adjusted based on our oil and gas properties, reserves, other indebtedness (including the outstanding commitments under the credit agreement dated November 18, 2011 among Plains Offshore, JPMorgan Chase Bank, N.A. as administrative agent and the lenders party thereto from time to time) and other factors. Our next redetermination date will occur on or before May 1, 2013.

Revolving Line of Credit. The aggregate commitments of the lenders under the revolving line of credit are $3.0 billion and can be increased to $3.6 billion if certain conditions are met. We are required, among other things, to make a mandatory prepayment if the combined total borrowings under our Amended Credit Facility and the Plains Offshore senior credit facility exceed the borrowing base.

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Additionally, our revolving line of credit contains a $750 million sub limit on letters of credit and a $100 million sub limit for swingline loans and matures on November 30, 2017. At December 31, 2012, we had $2.2 million in letters of credit outstanding under our revolving line of credit.

Amounts borrowed under our revolving line of credit bear an interest rate, at our election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus an additional variable amount ranging from 1.50% to 2.50%; (ii) a variable amount ranging from 0.50% to 1.50% plus the alternate base rate, or ABR, which is the greater of (1) the prime rate, as determined by JPMorgan Chase Bank, N.A., (2) the federal funds rate, plus 0.50%, and (3) the adjusted one-month LIBOR plus 1%; or (iii) the overnight federal funds rate plus an additional variable amount ranging from 1.50% to 2.50% for swingline loans. The Eurodollar rate and the ABR will be increased 0.25% while any term loans are outstanding. The additional variable amount of interest payable is based on the utilization rate as a percentage of the total amount of funds borrowed under our Amended Credit Facility and the Plains Offshore senior credit facility to the borrowing base. Letter of credit fees under our revolving line of credit are based on the utilization rate and range from 1.50% to 2.50% and will be increased by 0.25% while any term loans are outstanding. Commitment fees range from 0.375% to 0.50% of amounts available for borrowing. The effective interest rate on borrowings under our revolving line of credit was 2.55% at December 31, 2012.

Five-Year Term Loan and Seven-Year Term Loan. In connection with the Amended Credit Agreement in November 2012, we entered into the $750.0 million five-year term loan due 2017 and the $1.25 billion seven-year term loan due 2019. We received approximately $730.3 million and $1.2 billion of net proceeds from the five-year term loan and seven-year term loan, respectively, after deducting the offering costs which are treated as discount on issuance. We used the net proceeds to pay a portion of the cash consideration for the Gulf of Mexico Acquisition, to pay fees and expenses incurred in connection with the Gulf of Mexico Acquisition and related financing and for general corporate purposes. The term loans bear an interest rate, at our election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus 3.00% or (ii) 2.00% plus the ABR, which is the greater of (1) the prime rate, as determined by JPMorgan Chase Bank, N.A., (2) the federal funds rate, plus 0.50%, and (3) the adjusted one-month LIBOR plus 1.00%. In no event can LIBOR for the seven-year term loan be less than 1.00% per year.

The five-year term loan is payable in four annual installments each equal to 10% of the original principal balance due and payable on the last business day of December beginning on December 31, 2013 and the remaining balance due on its five-year maturity on November 30, 2017. The current portion of the five-year term loan is $75.0 million at December 31, 2012. The effective interest rate on our five-year term loan was 3.31% at December 31, 2012.

The seven-year term loan is payable in six annual installments each equal to 7.143% of the original principal balance due and payable on the last business day of December beginning on December 31, 2013 and the remaining balance due on its seven-year maturity on November 30, 2019. The current portion of the seven-year term loan is $89.3 million at December 31, 2012. The effective interest rate on our seven-year term loan was 4.00% at December 31, 2012.

Our Amended Credit Facility is secured by 100% of the shares of stock in certain of our domestic subsidiaries, 65% of the shares of stock in certain foreign subsidiaries and mortgages covering at least 75% of the total present value of our domestic proved oil and gas properties. Our Amended Credit Facility contains negative covenants that limit our ability, as well as the ability of our restricted subsidiaries to, among other things, incur additional debt or guarantee other indebtedness, 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, sell certain assets including capital stock of subsidiaries, enter into agreements that restrict dividends from

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subsidiaries, enter into certain types of swap agreements, enter into take-or-pay or other prepayment arrangements, merge or consolidate and enter into transactions with affiliates. In addition, we are required to maintain a ratio of debt to EBITDAX (as defined) of no greater than 4.50 to 1.

Plains Offshore Senior Credit Facility. The aggregate commitments of the lenders under the Plains Offshore senior credit facility are $300 million. The Plains Offshore senior credit facility contains a $50 million limit on letters of credit and matures on November 18, 2016. At December 31, 2012, Plains Offshore had no letters of credit outstanding under its senior credit facility.

Amounts borrowed under the Plains Offshore senior credit facility bear an interest rate, at Plains Offshore’s election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus an additional variable amount ranging from 1.50% to 2.50%; of (ii) a variable amount ranging from 0.50% to 1.50% plus the greater of (1) the prime rate, as determined by JPMorgan Chase Bank, (2) the federal funds rate, plus 0.50%, and (3) the adjusted LIBOR plus 1.00%. The additional variable amount of interest payable is based on the utilization rate as a percentage of the total amount of funds borrowed under both our revolving line of credit and the Plains Offshore senior credit facility and the borrowing base under our Amended Credit Facility. Letter of credit fees under the Plains Offshore senior credit facility are based on the utilization rate and range from 1.50% to 2.50%. Commitment fees range from 0.375% to 0.50% of amounts available for borrowing.

The borrowings under the Plains Offshore senior credit facility are guaranteed on a senior basis by PXP and certain of our subsidiaries, and are secured on a pari passu basis by liens on the same collateral that secures PXP’s Amended Credit Facility. The Plains Offshore senior credit facility contains certain affirmative and negative covenants, including limiting Plains Offshore’s ability, among other things, to create liens, incur other indebtedness, make dividends (excluding dividends on preferred stock) or other distributions, make investments, change the nature of Plains Offshore’s business and merge or consolidate, sell assets, enter into certain types of swap agreements and enter into certain transactions with affiliates, as well as other customary events of default, including a cross-default to PXP’s Amended Credit Facility. If an event of default (as defined in our Amended Credit Facility) has occurred and is continuing under our Amended Credit Facility that has not been cured or waived by the lenders thereunder then the Plains Offshore lenders could accelerate and demand repayment of the Plains Offshore senior credit facility.

Short-term Credit Facility. We have an uncommitted short-term unsecured credit facility, or short-term facility, under which we may make borrowings from time to time until June 1, 2013, not to exceed at any time the maximum principal amount of $75.0 million. No advance under the short-term facility may have a term exceeding 14 days and all amounts outstanding are due and payable no later than June 1, 2013. Each advance under the short-term facility bears interest at a rate per annum mutually agreed on by the bank and us.

We borrow under our short-term facility to fund our working capital needs. The funding requirements are typically generated due to the timing differences between payments and receipts associated with our oil and gas production. We generally pay off the short-term facility with receipts from the sales of our oil and gas production or borrowings under our revolving line of credit. No amounts were outstanding under the short-term facility at December 31, 2012. The daily average outstanding balance for the quarter and year ended December 31, 2012 was $22.7 million and $41.5 million, respectively. The weighted average interest rate on borrowings under our short-term facility was 1.5% for the years ended December 31, 2012 and 2011.

6  ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes. In October 2012, we issued (i) $1.5 billion of 6 ¹/₂% Senior Notes due 2020, or the 6 ¹/₂% Senior Notes, and (ii) $1.5 billion of 6 ⁷/₈% Senior Notes due 2023, or the 6 ⁷/₈% Senior Notes, both at par. We received approximately $2.95 billion of net proceeds,

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after deducting the underwriting discount and offering expenses. We used the net proceeds to pay a portion of the cash consideration for the Gulf of Mexico Acquisition and to reduce indebtedness outstanding under our revolving line of credit. We may redeem all or part of the 6 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes on or after November 15, 2015 and February 15, 2018, respectively, at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to November 15, 2015 we may at our option, redeem up to 35% of the 6 ¹/₂% Senior Notes and 6 ⁷/₈% Senior Notes with the proceeds of certain equity offerings.

6  ¹/₈% Senior Notes. In April 2012, we issued $750 million of 6 ¹/₈% Senior Notes due 2019, or the 6 ¹/₈% Senior Notes, at par. We received approximately $737.5 million of net proceeds, after deducting the underwriting discount and offering expenses. We used the net proceeds to reduce indebtedness outstanding under our revolving line of credit and for general corporate purposes, including the redemption of $79.3 million aggregate principal amount of our 7 ³/₄% Senior Notes due 2015, or the 7 ³/₄% Senior Notes, and $76.9 million aggregate principal amount of our 7% Senior Notes due 2017, or the 7% Senior Notes. We may redeem all or part of the 6 ¹/₈% Senior Notes on or after June 15, 2016 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to June 15, 2015 we may at our option, redeem up to 35% of the 6 ¹/₈% Senior Notes with the proceeds of certain equity offerings.

6 ³/₄% Senior Notes. In November 2011, we issued $1 billion of 6 ³/₄% Senior Notes due 2022, or the 6 ³/₄% Senior Notes, at par. We received approximately $984 million of net proceeds, after deducting the underwriting discount and offering expenses. We used the net proceeds to reduce indebtedness outstanding under our revolving line of credit and for general corporate purposes. We may redeem all or part of the 6 ³/₄% Senior Notes on or after February 1, 2017 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to February 1, 2015 we may, at our option, redeem up to 35% of the 6 ³/₄% Senior Notes with the proceeds of certain equity offerings.

6  ⁵/₈% Senior Notes. In March 2011, we issued $600 million of 6 ⁵/₈% Senior Notes due 2021, or the 6 ⁵/₈% Senior Notes, at par. We received approximately $590 million of net proceeds, after deducting the underwriting discount and offering expenses. We used the net proceeds to reduce indebtedness outstanding under our revolving line of credit and for general corporate purposes. We may redeem all or part of the 6 ⁵/₈% Senior Notes on or after May 1, 2016 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to May 1, 2014 we may, at our option, redeem up to 35% of the 6 ⁵/₈% Senior Notes with the proceeds of certain equity offerings.

7 ⁵/₈% Senior Notes due 2020. In March 2010, we issued $300 million of 7 ⁵/₈% Senior Notes due 2020, at par. We received approximately $294 million of net proceeds, after deducting the underwriting discount and offering expenses. We used the net proceeds to reduce indebtedness outstanding under our revolving line of credit and for general corporate purposes. We may redeem all or part of the 7 ⁵/₈% Senior Notes due 2020 on or after April 1, 2015 at specified redemption prices and prior to such date at a “make-whole” redemption price. In addition, prior to April 1, 2013 we may, at our option, redeem up to 35% of the 7 ⁵/₈% Senior Notes due 2020 with the proceeds of certain equity offerings.

8  ⁵/₈% Senior Notes. In September 2009, we issued $400 million of 8 ⁵/₈% Senior Notes due 2019, or the 8 ⁵/₈% Senior Notes, at 98.335% of the face value to yield 8.875% to maturity. We may redeem all or part of the 8  ⁵/₈% Senior Notes on or after October 15, 2014 at specified redemption prices and prior to such date at a “make-whole” redemption price.

10% Senior Notes. In March 2009, we issued $365 million of 10% Senior Notes due 2016, or the 10% Senior Notes, at 92.373% of the face value to yield 11.625% to maturity. In April 2009, an

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additional $200 million of 10% Senior Notes were sold to the public at 92.969% of the face value, plus interest accrued from March 6, 2009, to yield 11.5% to maturity. We may redeem all or part of the 10% Senior Notes on or after March 1, 2013 at specified redemption prices and prior to such date at a “make-whole” redemption price. In December 2011, we made payments totaling $429.5 million to retire $380.1 million of the $565 million outstanding principal amount of our 10% Senior Notes.

7 ⁵/₈% Senior Notes due 2018. In May 2008, we issued $400 million of 7 ⁵/₈% Senior Notes due 2018, at par. We may redeem all or part of the 7 ⁵/₈% Senior Notes due 2018 on or after June 1, 2013 at specified redemption prices and prior to such date at a “make-whole” redemption price.

7  ³/₄% Senior Notes. In June 2007, we issued $600 million principal amount of 7 ³/₄% Senior Notes, at par. In December 2011, we made payments totaling $542.2 million to retire $520.7 million of the $600 million outstanding principal amount of our 7 ³/₄% Senior Notes. In the second quarter of 2012, we made payments totaling $80.8 million to retire the remaining $79.3 million outstanding principal amount of our 7 ³/₄% Senior Notes.

7% Senior Notes. In March 2007, we issued $500 million principal amount of the 7% Senior Notes, at par. In December 2011, we made payments totaling $442.1 million to retire $423.1 million of the $500 million outstanding principal amount of our 7% Senior Notes. In the second quarter of 2012, we made payments totaling $79.6 million to retire the remaining $76.9 million outstanding principal amount of our 7% Senior Notes.

The 10% Senior Notes, 7 ⁵/₈% Senior Notes due 2018, 6 ¹/₈% Senior Notes, 8 ⁵/₈% Senior Notes, 7 ⁵/₈% Senior Notes due 2020, 6 ¹/₂% Senior Notes, 6 ⁵/₈% Senior Notes, 6 ³/₄% Senior Notes and 6 ⁷/₈% Senior Notes (together, the Senior Notes) are our general unsecured senior obligations. The Senior Notes are jointly and severally guaranteed by certain of our existing domestic subsidiaries. In the future, a subsidiary guarantor’s guarantee may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the assets of that subsidiary guarantor; (ii) in connection with any sale or other disposition of all the capital stock of that subsidiary guarantor; (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation or dissolution of that subsidiary guarantor provided no default or event of default has occurred or is continuing; or (vi) at such time as that subsidiary guarantor does not have outstanding any guarantee of any of our or any of our other subsidiary guarantors’ indebtedness (other than the notes) in excess of $10.0 million in aggregate principal amount. The Senior Notes rank senior in right of payment to all of our existing and future subordinated indebtedness; pari passu in right of payment with any of our existing and future unsecured indebtedness that is not by its terms subordinated to the Senior Notes; effectively junior to our existing and future secured indebtedness, including indebtedness under our Amended Credit Facility and the Plains Offshore’s senior credit facility, to the extent of our assets constituting collateral securing that indebtedness; and effectively subordinate to all existing and future indebtedness and other liabilities (other than indebtedness and liabilities owed to us) of our non-guarantor subsidiaries. In the event of a change of control coupled with a ratings downgrade, as defined in the indentures, we will be required to make an offer to repurchase the Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

The indentures governing the Senior Notes contain covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to incur additional debt; make certain investments or pay dividends or distributions on our capital stock or purchase or redeem or retire capital stock; sell assets, including capital stock of our restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries; create liens that secure debt; enter into transactions with affiliates; and merge or consolidate with another company.

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Debt Extinguishment Costs. During 2012, we recognized $8.4 million of debt extinguishment costs, including $5.2 million in connection with the retirement of the remaining aggregate principal amounts of our 7 ³/₄% Senior Notes and 7% Senior Notes and $3.2 million in connection with the Amended Credit Facility. During 2011, we recognized $121.0 million of debt extinguishment costs, including $30.9 million of unamortized debt issue costs and original issue discount, in connection with the retirement of a portion of our 7 ³/₄% Senior Notes, 10% Senior Notes and 7% Senior Notes. During 2010, we recognized $1.2 million of debt extinguishment costs in connection with reductions in our borrowing base and commitments under our revolving line of credit.

Subsequent Event. On February 20, 2013, we called for redemption of the remaining $184.9 million aggregate principal amount of our outstanding 10% Senior Notes at 105% of the principal amount. We expect to make payments totaling $195.2 million to retire the 10% Senior Notes in March 2013. We expect to recognize approximately $18.0 million of debt extinguishment costs, including $8.8 million of unamortized original issue discount and debt issue costs upon retirement of these Senior Notes.

Note 7 — Commodity Derivative Contracts

General

We are exposed to various market risks, including volatility in oil and gas commodity prices and interest rates. The level of derivative activity we engage in depends on our view of market conditions, available derivative prices and operating strategy. A variety of derivative instruments, such as swaps, collars, puts, calls and various combinations of these instruments, may be utilized to manage our exposure to the volatility of oil and gas commodity prices. Currently, we do not use derivatives to manage our interest rate risk. The interest rate on our revolving line of credit, term loans and Plains Offshore’s senior credit facility is variable, while our senior notes are at fixed rates.

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 in our income statement as a gain or loss on mark-to-market derivative contracts. Cash flows are only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty. The derivative instruments we have in place are not classified as hedges for accounting purposes.

Cash settlements with respect to derivatives that are not accounted for under hedge accounting and do not have a significant financing element are reflected as investing activities in the statement of cash flows. Cash settlements with respect to derivatives that contain a significant financing element are reflected as financing activities in the statement of cash flows.

For put options, we typically pay a premium to the counterparty in exchange for the sale of the instrument. If the index price is below the floor price of the put option, we receive the difference between the floor price and the index price multiplied by the contract volumes less the option premium. If the index price settles at or above the floor price of the put option, we pay only the option premium.

In a typical collar transaction, if the floating price based on a market index is below the floor price in the derivative contract, we receive from the counterparty an amount equal to this difference multiplied by the specified volume. If the floating price exceeds the ceiling price, we must pay the counterparty an amount equal to the difference multiplied by the specified volume. We may pay a premium to the counterparty in exchange for a certain floor or ceiling. Any premium reduces amounts we would receive under the floor or increases amounts we would pay above the ceiling. If the floating price exceeds the floor price and is less than the ceiling price, then no payment, other than the

F-23

premium, is required. If we have less production than the volumes specified under the collar transaction when the floating price exceeds the ceiling price, we must make payments against which there are no offsetting revenues from production.

Under a swap contract, the counterparty is required to make a payment to us if the index price for any settlement period is less than the fixed price, and we are required to make a payment to the counterparty if the index price for any settlement period is greater than the fixed price. The amount we receive or pay is the difference between the index price and the fixed price multiplied by the contract volumes. If we have less production than the volumes specified under the swap transaction when the index price exceeds the fixed price, we must make payments against which there are no offsetting revenues from production.

In 2012, we entered into the following derivative contracts:

• Henry Hub natural gas swap contracts on 80,000 MMBtu for 2012 with an average price of $2.72 per MMBtu.

• Brent crude oil swap contracts on 40,000 BOPD for 2013 with an average price of $109.23 per barrel.

• Brent three-way collars on 25,000 BOPD for 2013 with a floor price of $100 per barrel, a limit of $80 per barrel and a weighted average ceiling price of $124.29.

• Brent crude oil put option spread contracts on 13,000 BOPD for 2013 with a floor price of $100 per barrel, a limit of $80 per barrel and weighted average deferred premium and interest of $6.800 per barrel.

• Brent crude oil put option spread contracts on 5,000 BOPD for 2014 with a floor price of $100 per barrel, a limit of $80 per barrel and weighted average deferred premium and interest of $7.110 per barrel.

• Brent crude oil put option spread contracts on 30,000 BOPD for 2014 with a floor price of $95 per barrel, a limit of $75 per barrel and weighted average deferred premium and interest of $6.091 per barrel.

• Brent crude oil put option spread contracts on 75,000 BOPD for 2014 with a floor price of $90 per barrel, a limit of $70 per barrel and weighted average deferred premium and interest of $5.739 per barrel.

• Henry Hub natural gas swap contracts on 100,000 MMBtu for 2014 with an average price of $4.09 per MMBtu.

• Brent crude oil put option spread contracts on 84,000 BOPD for 2015 with a floor price of $90 per barrel, a limit of $70 per barrel and weighted average deferred premium and interest of $6.889 per barrel.

Additionally, we converted 5,000 BOPD of Brent crude oil put option contracts for 2013 to three-way collars. These modified three-way collars have a floor price of $90 per barrel with a limit of $70 per barrel and a weighted average ceiling price of $126.08, and we eliminated approximately $11.3 million of deferred premiums.

In December 2011, we entered into natural gas swap contracts at a weighted average price of $4.27 per MMBtu on 110,000 MMBtu per day for 2013. In September 2011, and in response to our higher priced marketing contracts, we realigned our existing 2012 WTI crude oil put option spread contracts that had an $80 per barrel floor price with a $60 per barrel limit on 40,000 BOPD by acquiring 2012 Brent crude oil three-way collars that have a $100 per barrel floor price with an $80 per barrel limit and a weighted average ceiling price of $120 per barrel. The realignment eliminated $89.1 million of deferred premiums and interest associated with the previous 2012 WTI crude oil put option spread contracts. We also paid net upfront premiums of approximately $2.6 million to enter into the 2012 Brent three-way collars. Additionally, we converted 40,000 of the 160,000 MMBtu per day 2012 natural gas

F-24

put option spread contracts that had a $4.30 per MMBtu floor price with a $3.00 per MMBtu limit to natural gas three-way collars that have a $4.30 per MMBtu floor price with a $3.00 per MMBtu limit and a weighted average ceiling price of $4.86 per MMBtu and reduced 2012 deferred premiums and interest by approximately $4.1 million. We also acquired 2013 Brent crude oil put option spread contracts that have a $90 per barrel floor price with a $70 per barrel limit and weighted average deferred premium and interest of $6.237 per barrel on 22,000 BOPD.

In April 2010, we entered into crude oil put option spread contracts on 31,000 BOPD for 2011 and 40,000 BOPD for 2012. Additionally, during April 2010 we acquired crude oil three-way collars on 9,000 BOPD for 2011. In November 2010, we acquired natural gas three-way collars on 200,000 MMBtu per day for 2011 and natural gas put options on 160,000 MMBtu per day for 2012.

See Note 9 – Fair Value Measurements of Assets and Liabilities, for additional discussion on the fair value measurement of our derivative contracts.

As of December 31, 2012, we had the following outstanding commodity derivative contracts, all of which settle monthly:

Period	Instrument Type	Daily Volumes	Average Price (1)	Average Deferred Premium	Index
Sales of Crude Oil Production
2013
Jan - Dec	Swap contracts (2)	40,000 Bbls	$109.23	-	Brent
Jan - Dec	Put options (3)	13,000 Bbls	$100.00 Floor with an $80.00 Limit	$6.800 per Bbl	Brent
Jan - Dec	Three-way collars (4)	25,000 Bbls	$100.00 Floor with an $80.00 Limit	-	Brent
			$124.29 Ceiling
Jan - Dec	Three-way collars (4)	5,000 Bbls	$90.00 Floor with a $70.00 Limit	-	Brent
			$126.08 Ceiling
Jan - Dec	Put options (3)	17,000 Bbls	$90.00 Floor with a $70.00 Limit	$6.253 per Bbl	Brent
2014
Jan - Dec	Put options (3)	5,000 Bbls	$100.00 Floor with an $80.00 Limit	$7.110 per Bbl	Brent
Jan - Dec	Put options (3)	30,000 Bbls	$95.00 Floor with a $75.00 Limit	$6.091 per Bbl	Brent
Jan - Dec	Put options (3)	75,000 Bbls	$90.00 Floor with a $70.00 Limit	$5.739 per Bbl	Brent
2015
Jan - Dec	Put options (3)	84,000 Bbls	$90.00 Floor with a $70.00 Limit	$6.889 per Bbl	Brent
Sales of Natural Gas Production
2013
Jan - Dec	Swap contracts (2)	110,000 MMBtu	$4.27	-	Henry Hub
2014
Jan - Dec	Swap contracts (2)	100,000 MMBtu	$4.09	-	Henry Hub

(1) The average strike prices do not reflect any premiums to purchase the put options.

(2) If the index price is less than the fixed price, we receive the difference between the fixed price and the index price. We pay the difference between the index price and the fixed price if the index price is greater than the fixed price.

(3) If the index price is less than the per barrel floor, we receive the difference between the per barrel floor and the index price up to a maximum of $20 per barrel less the option premium. If the index price is at or above the per barrel floor, we pay only the option premium.

(4) If the index price is less than the per barrel floor, we receive the difference between the per barrel floor and the index price up to a maximum of $20 per barrel. We pay the difference between the index price and the per barrel ceiling if the index price is greater than the per barrel ceiling. If the index price is at or above the per barrel floor but at or below the per barrel ceiling, no cash settlement is required.

F-25

Balance Sheet

At December 31, 2012 and 2011, we had the following outstanding commodity derivative contracts recorded in our balance sheet (in thousands):

		Estimated Fair Value Year Ended December 31,
Instrument Type	Balance Sheet Classification	2012		2011
Crude oil puts	Commodity derivative contracts - current assets	$	28,348	$	-
Crude oil collars	Commodity derivative contracts - current assets		17,263		10,623
Crude oil swaps	Commodity derivative contracts - current assets		33,416		-
Natural gas puts	Commodity derivative contracts - current assets		-		41,335
Natural gas collars	Commodity derivative contracts - current assets		-		13,163
Natural gas swaps	Commodity derivative contracts - current assets		29,052		-
Crude oil puts	Commodity derivative contracts - non-current assets		412,348		48,306
Natural gas swaps	Commodity derivative contracts - non-current assets		2,170		12,951
Total derivative instruments		$	522,597	$	126,378

The following table provides supplemental information to reconcile the fair value of our derivative contracts to our balance sheet at December 31, 2012 and 2011, considering the deferred premiums, accrued interest and related settlement payable/receivable amounts which are not included in the fair value amounts disclosed in the table above (in thousands):

	Year Ended December 31,
	2012			2011
Net fair value asset	$	522,597		$	126,378
Deferred premium and accrued interest on derivative contracts		(511,255	)		(62,430	)
Settlement payable		-			(5,106	)
Settlement receivable		17			216
Net commodity derivative asset	$	11,359		$	59,058
Commodity derivative contracts - current asset	$	56,208		$	50,964
Commodity derivative contracts - non-current asset		903			12,678
Commodity derivative contracts - current liability		(18,942	)		(3,761	)
Commodity derivative contracts - non-current liability		(26,810	)		(823	)
	$	11,359		$	59,058

We present the fair value of our derivative contracts on a net basis where the right of offset is provided for in our counterparty agreements.

Income Statement

During the years ended December 31, 2012, 2011 and 2010, pre-tax amounts recognized in our income statements for derivative transactions were as follows (in thousands):

	Year Ended December 31,
	2012		2011		2010
(Loss) gain on mark-to-market derivative contracts	$	(2,879)	$	81,981	$	(60,695)

F-26

Cash Payments and Receipts

During the years ended December 31, 2012, 2011 and 2010 cash (payments) receipts for derivatives were as follows (in thousands):

	Year Ended December 31,
	2012			2011			2010
Oil derivatives
Settlements	$	(8,060	)	$	(60,392	)	$	(67,917	)
Unwind of crude oil puts		-			(2,935	)		-
Natural gas derivatives		50,954			7,915			37,996
	$	42,894		$	(55,412	)	$	(29,921	)

Credit Risk

We generally do not require collateral or other security to support derivative instruments subject to credit risk. However, the agreements with each of the counterparties to our derivative instruments contain netting provisions within the agreements. If a default occurs under the agreements, the non-defaulting party can offset the amount payable to the defaulting party under the derivative contracts with the amount due from the defaulting party under the derivative contracts. As a result of the netting provisions under the agreements, our maximum amount of loss due to credit risk is limited to the net amounts due from the counterparties under the derivative contracts. The maximum amount of loss due to credit risk that we would have incurred if all the counterparties to our derivative contracts failed to perform according to the terms of the derivative contracts at December 31, 2012 was $52.3 million.

Contingent Features

As of December 31, 2012, the counterparties to our commodity derivative contracts consisted of ten financial institutions. All of our counterparties or their affiliates are also lenders under our revolving line of credit. As a result, the counterparties to our derivative agreements share in the collateral supporting our revolving line of credit. Therefore, we are not generally required to post additional collateral under our derivative agreements.

Certain of our derivative agreements contain cross-default and acceleration provisions relative to our material debt agreements. If we were to default on any of our material debt agreements, it would be a violation of these provisions, and the counterparties to our derivative agreements could request immediate payment on derivative instruments that are in a net liability position at that time. As of December 31, 2012, we were in a net liability position with six of the counterparties to our derivative instruments, totaling $40.8 million.

F-27

Note 8 — Investment

At December 31, 2012 and 2011, we owned 51.0 million shares of McMoRan common stock, approximately 31.5% and 31.6%, respectively, of its common shares outstanding. McMoRan is a publicly traded oil and gas exploration and production company (New York Stock Exchange listing MMR) engaged in the exploration, development and production of natural gas and oil in the United States, specifically offshore in the shallow waters of the Gulf of Mexico Shelf and onshore in the Gulf Coast area. In December 2010, we acquired the McMoRan common stock and other consideration in exchange for all of our interests in our U.S. Gulf of Mexico leasehold located in less than 500 feet of water. See Note 4 – Divestments.

As contemplated by the Agreement and Plan of Merger, we and McMoRan entered into a registration rights agreement and a stockholder agreement at the closing of the transaction on December 30, 2010. The registration rights agreement gives us piggyback registration rights and demand registration rights under certain circumstances. Under the terms of the stockholder agreement, McMoRan expanded its board of directors and we have the right to designate two board members for so long as we own at least 10% of the outstanding shares of McMoRan. If our ownership falls below 10%, but is at least 5%, we will have the right to designate one director. The stockholder agreement requires us to refrain from certain activities that could be undertaken to acquire control of McMoRan. We may sell shares of McMoRan common stock pursuant to underwritten offerings, in periodic sales under the shelf registration statement filed by McMoRan (subject to certain volume limitations), pursuant to the exercise of piggyback registration rights or as otherwise permitted by applicable law.

On December 5, 2012, Freeport-McMoRan agreed to acquire McMoRan for per share consideration consisting of $14.75 in cash and 1.15 units of a royalty trust, which will hold a 5% overriding royalty interest in future production from McMoRan’s existing ultra-deep exploration properties. In connection with the MMR Merger, on December 5, 2012, we entered into the Support Agreement with Freeport-McMoRan, pursuant to which we are generally required to, in our capacity as a stockholder of 31.5% of McMoRan, vote all of our shares of McMoRan common stock in favor of the MMR Merger Agreement and against alternative transactions and generally prohibits us from transferring our shares of McMoRan common stock prior to the consummation of the MMR Merger.

We are deemed to exercise significant influence over the operating and investing policies of McMoRan but do not have control. We have elected to measure our equity investment in McMoRan at fair value, and the change in fair value of our investment is recognized as a gain or loss on investment measured at fair value in our income statement. We believe that using fair value as a measurement basis for our investment is useful to our investors because our earnings on the investment will be dependent on the fair value on the date we divest the shares. At December 31, 2012 and 2011, the McMoRan shares were valued at approximately $818.2 million and $611.7 million, respectively, based on McMoRan’s closing stock prices of $16.05 and $14.55 on December 31, 2012 and 2011, respectively, discounted in 2012 by the time value of money corresponding to the maturity date of the expected close of the merger and in 2011 to reflect certain limitations on the marketability of the McMoRan shares. During the year ended December 31, 2012, we recorded an unrealized gain of $206.6 million, and during the years ended December 31, 2011 and 2010, we recorded unrealized losses of $52.7 million and $1.6 million, respectively, on our investment.

F-28

McMoRan follows the successful efforts method of accounting for its oil and natural gas activities. Under this method of accounting, all costs associated with oil and gas lease acquisition, successful exploratory wells and all development wells are capitalized and amortized on a unit-of-production basis over the remaining life of proved developed reserves and proved reserves on a field basis. Unproved leasehold costs are capitalized pending the results of exploration efforts. Exploration costs, including geological and geophysical expenses, exploratory dry holes and delay rentals, are charged to expense when incurred. Below is summarized financial information of our proportionate share of McMoRan’s financial position and results of operations (in thousands):

	December 31,
	2012 (1)		2011
Financial Position (2)
Current assets	$	67,141	$	217,063
Noncurrent assets		776,152		711,729
Current liabilities		112,617		133,162
Noncurrent liabilities		225,665		251,173
Net assets	$	505,011	$	544,457

	Year Ended December 31,
	2012 (1)			2011
Results of Operations (2)
Revenues	$	118,720		$	175,511
Operating (loss) income		(28,868	)		432
Loss from continuing operations		(30,565	)		(2,087	)
Net loss applicable to common stock		(45,855	)		(18,571	)

(1) Amounts are based on McMoRan’s Form 8-K dated January 18, 2013.

(2) Amounts represent our 31.5% and 31.6% equity ownership in McMoRan as of December 31, 2012 and 2011, respectively. We acquired our McMoRan investment on December 30, 2010. Our proportionate share of McMoRan’s 2010 results of operations is not presented because it is insignificant as PXP owned the investment for one day and it is not practicable to determine one day’s results of operations.

Note 9 — Fair Value Measurements of Assets and Liabilities

Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. We follow a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value.

F-29

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Our commodity derivative instruments and investment are recorded at fair value on a recurring basis in our balance sheet with the changes in fair value recorded in our income statement. The following table presents, for each fair value hierarchy level, our commodity derivative assets and liabilities and our investment measured at fair value on a recurring basis as of December 31, 2012 and 2011 (in thousands):

			Fair Value Measurements at Reporting Date Using
	Fair Value		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
2012
Commodity derivative contracts (1)
Crude oil puts	$	440,696	$	-	$	428,355		$	12,341
Crude oil collars		17,263		-		-			17,263
Crude oil swaps		33,416		-		33,416			-
Natural gas swaps		31,222		-		31,222			-
Investment (2)		818,223		-		-			818,223
	$	1,340,820	$	-	$	492,993		$	847,827
2011
Commodity derivative contracts (1)
Crude oil puts	$	48,306	$	-	$	-		$	48,306
Crude oil collars		10,623		-		(669	)		11,292
Natural gas puts		41,335		-		-			41,335
Natural gas collars		13,163		-		-			13,163
Natural gas swaps		12,951		-		12,951			-
Investment (2)		611,671		-		-			611,671
	$	738,049	$	-	$	12,282		$	725,767

(1) Option premium and accrued interest of $511.3 million and $62.4 million at December 31, 2012 and 2011, respectively, settlement payable of $5.1 million at December 31, 2011 and settlement receivable of $0.2 million at December 31, 2011 are not included in the fair value of derivatives.

(2) Represents our equity investment in McMoRan which would otherwise be reported under the equity method of accounting.

The fair value amounts of our put and collar derivative instruments are estimated using an option-pricing model, which uses various inputs including ICE price quotations, volatilities, interest rates and contract terms. The fair value of our swap derivative instruments are estimated using a pricing model which has various inputs including NYMEX and ICE price quotations, interest rates and contract terms. We adjust the valuations for credit quality, using the counterparties’ credit quality for asset balances and our credit quality for liability balances. For asset balances, we use the credit default swap value for counterparties when available or the spread between the risk-free interest rate and the yield on the counterparties’ publicly traded debt for similar maturities. We consider the impact of netting agreements on counterparty credit risk, including whether the position with the counterparty is a net asset or net liability.

F-30

We classify derivatives that have identical assets or liabilities with quoted, unadjusted prices in active markets as Level 1. We classify derivatives as Level 2 if the inputs used in the valuation model are directly or indirectly observable for substantially the full term of the instrument; however, if the significant inputs are not observable for substantially the full term of the instrument, we classify those derivatives as Level 3. We determine whether the market for our derivative instruments is active or inactive based on transaction volume for such instruments and classify as Level 3 those instruments that are not actively traded. For these inputs, we utilize pricing and volatility information from other instruments with similar characteristics and extrapolate and/or interpolate data between data points for thinly traded instruments.

As of December 31, 2012, our commodity derivative contracts are classified as follows:

• Our 2013 and 2014 natural gas swaps, our 2013 crude oil swaps and puts, certain of our 2014 crude oil puts and our 2015 crude oil puts are classified as Level 2 instruments.

• Our 2013 crude oil collars and certain of our 2014 crude oil puts are classified as Level 3 instruments.

Historically, we have determined the fair value of our investment by applying a discount factor for lack of marketability at the reporting date. As of December 31, 2011, the discount factor for lack of marketability was determined by utilizing both Protective put and Asian put option models. Both of these options are valued using a Black-Scholes option-pricing model which utilizes various inputs including the closing price of the McMoRan common stock, implied volatility of the instrument, number of shares being valued, length of time that would be necessary to dispose of our investment, expected dividend and risk-free interest rates.

On December 5, 2012, we entered into the Support Agreement with Freeport-McMoRan and the MMR Merger Sub, pursuant to which we, in our capacity as a stockholder of McMoRan, are generally prohibited from transferring our shares of McMoRan common stock prior to the consummation of the merger. On December 31, 2012, we determined the fair value of our investment using McMoRan’s closing stock price of $16.05, which we believe is consistent with the exit price notion and is representative of what a market participant would pay for McMoRan’s common stock in an arm’s length transaction. Additionally, we utilized a time value of money analysis to determine an implied discount rate. The implied discount is determined by utilizing a risk-free interest rate based on the U.S. Treasury Strip rate with a maturity date corresponding to the expected close of the merger.

As of December 31, 2012 and 2011, our investment in McMoRan has been classified as Level 3 since the fair value is determined by utilizing significant inputs that are unobservable.

We determine the appropriate level for each financial asset and liability on a quarterly basis and recognize any transfers at the beginning of the reporting period.

F-31

We adopted the guidance amending certain accounting and disclosure requirements related to fair value measurements on January 1, 2012. The guidance clarifies (i) the requirement that the highest and best use concept is only relevant for measuring nonfinancial assets, (ii) requirements to measure the fair value of instruments classified in shareholders’ equity and (iii) the requirement to disclose quantitative information about the unobservable inputs used in a fair value measurement that is categorized within Level 3 of the fair value hierarchy. The guidance also (i) permits a reporting entity to measure the fair value of certain financial assets and liabilities managed in a portfolio at the price that would be received to sell a net asset position or transfer a net liability position for a particular risk, (ii) eliminates premiums or discounts related to size as a characteristic of the reporting entity’s holding and (iii) expands disclosures for fair value measurement. The provisions of this standard did not have an impact on our consolidated financial position, results of operations or cash flows.

The following table presents quantitative information about Level 3 inputs used in the fair value measurement of our commodity derivative contracts and our investment measured at fair value as of December 31, 2012 (in thousands):

	Quantitative Information About Level 3 Fair Value Measurements
	Fair Value		Valuation Technique	Unobservable Input	Range (Weighted Average)
December 31, 2012
Commodity derivative contracts (1)
Crude oil puts	$	12,341	Option pricing model	Implied volatility	24% - 30% (27%)
Crude oil collars		17,263	Option pricing model	Implied volatility	22% - 78% (30%)
Investment (2)		818,223	Time value of money	Expected term	0.03% - 0.05%
			analysis		(0.04%)

(1) Represents the range of implied volatility associated with the forward commodity prices used in the valuation of our derivative contracts. We have determined that a market participant would use a similar volatility curve when pricing similar commodity derivative contracts.

(2) Represents the range of discount for time value of money associated with our investment in the common stock of McMoRan. The discount for time value of money is derived by an implied discount analysis as of the valuation date. We have determined that a market participant would use a similar valuation methodology when pricing an investment with similar terms.

The significant unobservable inputs used in the fair value measurement of our commodity derivative contracts are implied volatilities. Significant increases (decreases) in implied volatilities in isolation would result in a significantly higher (lower) fair value measurement.

The expected term associated with the completion of the merger used in determination of the fair value of our investment is a significant unobservable input. The expected term of our investment impacts the implied discount to reflect the time value of money. Failure to complete the merger and the MMR Merger could modify the term in which we are able to sell our investment in McMoRan’s common shares. Significant increases (decreases) in the expected term in isolation would result in a significantly higher (lower) discount factor. A higher implied discount factor would result in a lower fair value measurement of our investment. Additionally, failure to complete the merger could result in changes to the method we use to determine fair value of our investment, which may result in the use of other significant unobservable inputs.

F-32

The following table presents a reconciliation of changes in fair value of financial assets and liabilities classified as Level 3 for the years ended December 31, 2012 and 2011 (in thousands):

	Year Ended December 31,
	2012					2011
	Commodity Derivatives  (1)			Investment		Commodity Derivatives  (1)			Investment
Fair value at beginning of period	$	114,096		$	611,671	$	4,785		$	664,346
Transfers into Level 3 (2)		149			-		-			-
Transfers out of Level 3 (3)		(52,540	)		-		6,962			-
Purchases		12,830			-		47,948			-
Realized and unrealized gains and losses included in earnings (4)		23,917			206,552		56,775			(52,675	)
Settlements		(68,848	)		-		(2,374	)		-
Fair value at end of period	$	29,604		$	818,223	$	114,096		$	611,671
Change in unrealized gains and losses relating to assets and liabilities held as of the end of the period (4)	$	16,774		$	206,552	$	50,894		$	(52,675	)

(1) Deferred option premiums and interest are not included in the fair value of derivatives.

(2) During the year ended December 31, 2012, the inputs used to value certain of our 2012 crude oil collars were significantly unobservable and those contracts were transferred from Level 2 to Level 3.

(3) During the year ended December 31, 2012, the inputs used to value certain of our 2012 crude oil collars and certain of our 2013 crude oil puts were directly or indirectly observable and those contracts were transferred from Level 3 to Level 2. During the year ended December 31, 2011, the inputs used to value certain of our 2011 natural gas collars were directly or indirectly observable and those contracts were transferred from Level 3 to Level 2.

(4) Realized and unrealized gains and losses included in earnings for the period are reported as (loss) gain on mark-to-market derivative contracts and gain (loss) on investment measured at fair value in our income statement for our commodity derivative contracts and our investment, respectively.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Nonfinancial assets and liabilities, such as goodwill and other property and equipment, are measured at fair value on a nonrecurring basis upon impairment; however, we have no material assets or liabilities that were reported at fair value on a nonrecurring basis in our balance sheet at December 31, 2012 or 2011.

Fair Value of Other Financial Instruments

Authoritative guidance on financial instruments requires certain fair value disclosures, such as those on our long-term debt, to be presented in both interim and annual reports. The estimated fair value amounts of financial instruments have been determined using available market information and valuation methodologies described below.

The carrying values of items comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. Derivative financial instruments included in our balance sheet are stated at fair value; however, certain of our derivative financial instruments have a deferred premium, including our crude oil and natural gas put options. The deferred premium reduces the asset or increases the liability depending on the fair value of the derivative financial instrument.

F-33

The following table presents the carrying amounts and fair values of our other financial instruments as of December 31, 2012 and 2011 (in thousands):

	December 31, 2012				December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Current Asset (1)
Cash and cash equivalents	$	180,565	$	180,565	$	419,098	$	419,098
Current Liability
Deferred premium and accrued interest on derivative contracts (2)		70,831		70,831		13,029		13,029
Current maturities of long-term debt (3)		164,288		164,288		-		-
Non-Current Liability (2)
Deferred premium and accrued interest on derivative contracts		440,424		440,424		49,401		49,401
Long-Term Debt (3)
Amended Credit Facility
Revolving line of credit		1,570,000		1,570,000		735,000		735,000
Five-year term loan		655,638		655,638		-		-
Seven-year term loan		1,131,556		1,131,556		-		-
Plains Offshore senior credit facility		-		-		-		-
7 3/4% Senior Notes		-		-		79,281		81,858
10% Senior Notes		177,266		188,788		175,385		194,239
7% Senior Notes		-		-		76,901		79,593
7 5/8% Senior Notes due 2018		400,000		421,000		400,000		424,000
6 1/8% Senior Notes		750,000		817,500		-		-
8 5/8% Senior Notes		394,909		449,209		394,385		433,331
7 5/8% Senior Notes due 2020		300,000		334,500		300,000		324,750
6 1/2% Senior Notes		1,500,000		1,661,250		-		-
6 5/8% Senior Notes		600,000		660,750		600,000		630,000
6 3/4% Senior Notes		1,000,000		1,122,500		1,000,000		1,047,500
6 7/8% Senior Notes		1,500,000		1,713,750		-		-

(1) Our cash and cash equivalents consist primarily of money market mutual funds and would have been classified as Level 1 under the fair value hierarchy.

(2) If our deferred premium and accrued interest payable on our commodity derivative contracts had been measured at fair value, it would have been classified as Level 3 under the fair value hierarchy.

(3) The carrying value of our revolving line of credit and terms loans, including current portion, approximate fair value, as interest rates are variable, based on prevailing market rates. Our revolving line of credit and terms loans would have been classified as Level 1 under the fair value hierarchy. If our senior notes had been measured at fair value, we would have classified them as Level 1 under the fair value hierarchy as the inputs utilized for the measurement would be quoted, unadjusted prices from over the counter markets for debt instruments.

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Note 10 — Asset Retirement Obligation

The following table reflects the changes in our asset retirement obligation during the years ended December 31, 2012, 2011 and 2010 (in thousands):

	Year Ended December 31,
	2012			2011			2010
Asset retirement obligation – beginning of period	$	238,381		$	239,432		$	221,367
Liabilities incurred in acquisitions (1)		337,702			6			246
Property dispositions and other		(1,954	)		(19,406	)		(7,883	)
Settlements		(4,565	)		(13,998	)		(3,718	)
Change in estimate		(7,427	)		7,463			6,179
Accretion expense		16,944			17,177			17,702
Asset retirement additions		5,420			7,707			5,539
Asset retirement obligation – end of period (2)	$	584,501		$	238,381		$	239,432

(1) During 2012, we recorded $337.7 million of additional abandonment liabilities in connection with the Gulf of Mexico Acquisition. See Note 3 – Acquisitions.

(2) $18.5 million and $7.7 million are included in other current liabilities at December 31, 2012 and 2011, respectively.

Note 11 — Stock-Based and Other Compensation Plans

We have three stock incentive plans: the 2004 Stock Incentive Plan, or 2004 Plan, which provides for a maximum of 8.4 million shares available for awards; the 2006 Incentive Plan, or the 2006 Plan, which provides for cash-settled stock-based awards; and the 2010 Incentive Award Plan, or the 2010 Plan, which provides for a maximum of 5.0 million shares available for awards. In September 2012, the Company’s 2002 Stock Incentive Plan expired per its terms along with the remaining ungranted awards. Our 2004 Plan and 2010 Plan provide for the grant of stock options and other awards (including performance units, performance shares, share awards, restricted stock, stock-settled RSUs and SARs) to our directors, officers, employees, consultants and advisors. The 2006 Plan provides for the grant of cash-settled SARs and cash-settled RSUs to non-officer employees and was amended in January 2012 to allow officers to participate in the plan. 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 ten years after its grant date, 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, RSUs, share awards, performance units and performance shares on such terms and conditions as it may decide in its discretion.

Upon an event constituting a “change in control” (as defined in the plans) of PXP, all SARs will become immediately exercisable in full. In addition, in such an event, unless otherwise determined by our compensation committee, or employee agreement, generally all other awards will vest and all restrictions on such awards will lapse. We may, at our discretion, issue new shares or use treasury shares to satisfy vesting requirements. Upon the closing of the merger, an event constituting a change in control will have occurred. See Note 2 – Proposed Merger with Freeport-McMoRan Copper & Gold Inc. The disclosures and tables that follow are based on the existing terms of our stock-based compensation awards and do not reflect any impact of the Freeport-McMoRan Merger Agreement.

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Stock-based compensation is measured at the grant date, based on the calculated fair value of the award and is remeasured each reporting period for liability-classified awards. Stock-based compensation is recognized over the requisite employee service period (generally the vesting period of the grant). Stock-based compensation is expensed or capitalized based on the nature of the employee’s activities, and for the years ended December 31, 2012, 2011 and 2010 was (in thousands):

	Year Ended December 31,
	2012		2011		2010
Stock-based compensation included in:
General and administrative expense	$	49,907	$	42,268	$	46,953
Lease operating expenses		10,340		6,925		3,922
Oil and natural gas properties		18,543		13,695		14,662
Total stock-based compensation	$	78,790	$	62,888	$	65,537

Stock-based compensation charged to earnings for the years ended December 31, 2012, 2011 and 2010 was (in thousands):

	Year Ended December 31,
	2012			2011			2010
Charged to earnings	$	60,247		$	49,193		$	50,875
Tax benefit		(22,532	)		(18,438	)		(19,068	)
	$	37,715		$	30,755		$	31,807

At December 31, 2012, there was $208.2 million of total unrecognized compensation cost related to unvested stock-based compensation arrangements that is expected to be recognized over a weighted-average period of approximately 3.6 years.

SARs

SAR grants generally vest ratably over three years or 100% at the end of three years and expire within five years after the date of grant. These awards are similar to stock options, but are settled in cash rather than in shares of common stock and are classified as liability awards. Compensation cost for these awards is determined using a fair-value method and remeasured at each reporting date until the date of settlement. Stock-based compensation expense recognized is based on the number of SARs ultimately expected to vest and has been reduced for estimated forfeitures.

The following table summarizes the status of our SARs at December 31, 2012 and the changes during the year then ended:

	Outstanding (thousands)			Weighted Average Exercise Price		Aggregate Intrinsic Value ($ thousands)		Weighted Average Remaining Contractual Life (years)
Outstanding at January 1, 2012		3,570		$	37.98
Granted		528			42.40
Exercised		(1,110	)		27.52
Forfeited or expired		(769	)		46.95
Outstanding at December 31, 2012		2,219			41.15	$	15,906		2.3
Exercisable at December 31, 2012		913			45.66	$	4,235		0.8

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The total intrinsic value of SARs exercised during the years ended December 31, 2012, 2011 and 2010 was $18.6 million, $2.9 million and $0.6 million, respectively. The weighted average grant date fair value per share for SARs granted in 2012, 2011 and 2010 was $17.11, $13.65 and $11.08, respectively.

We estimate the fair value of SARs granted using the Black-Scholes valuation model. The following assumptions are as of December 31, 2012, 2011 and 2010:

	2012	2011	2010
Expected life (in years)	1 - 4	1 - 4	1 - 4
Volatility	40.3% - 45.8%	47.4% - 52.2%	45.3% - 56.3%
Risk-free interest rate	0.2% - 0.5%	0.1% - 0.6%	0.3% - 1.5%
Dividend yield	0%	0%	0%

The expected life represents the period of time that SARs granted are expected to be outstanding. We use historical experience with exercise and post-vesting exercise behavior to determine the expected life of the SARs granted. Expected volatility is based on the historical volatility of our common stock and other factors. The risk-free interest rate is based on the U.S. Treasury rate with a maturity date corresponding to the SARs’ expected life.

Restricted Stock and Stock-settled RSUs

Our stock compensation plans allow grants of restricted stock and stock-settled RSUs. Restricted stock is issued on the grant date but is restricted as to transferability. Stock-settled RSU awards represent the right to receive common stock when vesting occurs.

Restricted stock and stock-settled RSU grants generally vest over periods ranging from one to five years of service. Compensation cost for these awards is based on the closing market price of our common stock on the date of grant. Stock-based compensation expense is based on the awards ultimately expected to vest, and has been reduced for estimated forfeitures.

The following table summarizes the status of our restricted stock and stock-settled RSUs at December 31, 2012 and the changes during the year then ended:

	Equity Instruments (thousands)			Weighted Average Grant Date Fair Value Price		Aggregate Intrinsic Value ($ thousands)		Weighted Average Remaining Contractual Life (years)
Nonvested at January 1, 2012		6,284		$	40.97
Granted		881			42.56
Vested		(1,041	)		42.56
Vested and deferred		(314	)		43.81
Forfeited		(53	)		35.92
Nonvested at December 31, 2012		5,757			43.11	$	270,167		3.8

F-37

The total intrinsic value of restricted stock and stock-settled RSUs vested in 2012, 2011 and 2010 was $56.4 million, $54.0 million and $41.0 million, respectively. The intrinsic value was based upon the closing price of common stock on the date restricted stock and stock-settled RSUs vested. The weighted average grant date fair value of stock-settled RSUs granted during the years ended December 31, 2011 and 2010 was $37.18 per share and $31.23 per share, respectively.

In 2006, we granted 300,000 stock-settled RSUs to certain executives that will vest only upon a change of control (as defined). As the conditions to the closing of the merger with Freeport-McMoRan as described in the Freeport-McMoRan Merger Agreement have not been satisfied, our assessment at this time is that change of control is not probable, and no compensation cost has been recognized for these awards.

The nonvested shares in the tables above include 1.6 million shares that were deemed granted in 2005 for accounting purposes under the 2004 Plan in accordance with the provisions of our Long-Term Retention and Deferred Compensation Plan. The plan allows certain executive officers to defer awards of equity compensation and in lieu thereof, an equivalent number of stock-settled RSUs available under stockholder-approved plans will be credited to an account for the executive. Under the terms of this plan, certain executives were granted the right under the 2004 Plan to receive annual RSU grants beginning in 2005 and continuing until 2014. Each annual credit is subject to continued service by the executive and all such future grants are deemed granted in 2005 for the purpose of determining stock-based compensation expense. The grants have varying vesting dates from 2013 through 2015 but payment of vested stock-settled RSUs will be generally deferred until September 30, 2015, subject to certain exceptions. At December 31, 2012, 1.2 million nonvested shares had been granted and 0.4 million nonvested shares will be granted in 2013 and 2014.

In addition, under the terms of our Long-Term Retention and Deferred Compensation Plan, annual grants may be increased if certain common stock price targets are achieved. We used a Monte-Carlo simulation model to estimate the value and number of RSUs expected to be granted in the future. This model involves forecasting potential future stock price paths based on the expected return on the common stock and its volatility, then calculating the number of RSUs expected to be granted based on the results of the simulations.

The following assumptions were used with respect to the Monte Carlo simulation model:

Expected annual return	9.80	%
Expected daily return	0.04	%
Daily standard deviation	2.09	%

We estimated that 0.4 million restricted units would be granted as a result of achieving the common stock price targets. Such units had a weighted average fair value of $46.61 per unit, an aggregate fair value of $18.7 million and a weighted average remaining contractual life of six years.

The tables above also include 1.0 million stock-settled RSUs deemed granted in 2008 for accounting purposes. An executive was granted the right to receive five annual grants of 200,000 stock-settled RSUs beginning in September 2015 and continuing until 2019. Each annual grant is subject to continued service by the executive. The first three annual grants will each vest in full in 2020 and the fourth and fifth annual grants will each vest ratably over a three year period from the date of the grant. The grant date for accounting purposes for all 1.0 million of these stock-settled RSUs is March 2008.

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At certain times a sufficient number of shares are not available for issuance under our stock compensation plans to satisfy all awards deemed granted for accounting purposes. At such times, we have reclassified and accounted for as liability awards the number of shares deemed granted in excess of available shares, until such time that the number of available shares is increased to a sufficient level to satisfy such awards, at which point the awards are reclassified back to equity awards.

Cash-settled RSUs

Our stock compensation plan allows grants of cash-settled RSUs. These awards are similar to stock-settled RSUs, but are settled in cash rather than in shares of common stock and are classified as liability awards. Cash-settled RSU awards represent the right to receive cash payment equal to the average of our common stock closing price for the five trading days immediately prior to vesting.

Cash-settled RSUs generally vest over periods ranging from three to five years of service. Compensation cost for these awards is determined and remeasured by the closing market price of our common stock at each reporting date until the vesting date, when it is settled in cash at the average of our common stock closing price for the five trading days immediately prior to vesting. Stock-based compensation is based on the awards ultimately expected to vest, and has been reduced for estimated forfeitures.

The following table summarizes the status of our cash-settled RSUs at December 31, 2012 and the changes during the year then ended:

	Equity Instruments (thousands)			Weighted Average Grant Date Fair Value Price		Aggregate Intrinsic Value ($  thousands)		Weighted Average Remaining Contractual Life (years)
Nonvested at January 1, 2012		-		$	-
Granted		1,454			43.06
Vested		(3	)		43.04
Forfeited		(25	)		43.04
Nonvested at December 31, 2012		1,426			43.06	$	66,955		3.7

The total intrinsic value of cash-settled RSUs vested in 2012 was $0.1 million. The intrinsic value was based upon the average closing price of common stock on the cash-settled RSUs vesting date.

We issued 225 thousand cash-settled RSUs that are subject to a market condition in which the price performance of PXP’s common stock is compared to an average of two peer indices. Based on the performance, these units may settle upon vesting at 0% to 150% of the number of awards granted as determined by linear interpolation. The first market condition period was reached as of December 31, 2012. Due to the performance of PXP’s common stock, 34 thousand additional unvested cash-settled RSUs were awarded and are subject to vesting requirements to be met at March 31, 2013. The initial grant of 225 thousand cash-settled RSUs and the additional 34 thousand cash-settled RSUs are included as granted awards in the above table.

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We used a Monte-Carlo simulation model to estimate the fair value of the cash-settled RSUs subject to the market condition. This model involves forecasting potential future stock price paths based on the expected return on our common stock and the indices and their volatility, then calculating the fair value of RSUs to be granted based on the results of the simulations. On the grant date, we estimated that these units had a weighted average fair value of $43.41 per unit, an aggregate fair value of $9.8 million and a weighted average remaining contractual life of 2.1 years.

The following assumptions were used with respect to the Monte Carlo simulation model:

Risk-free interest rate	0.41	%
Expected volatility	51.60	%
Expected term (in years)	2.90

Stock Options

At December 31, 2012, no stock options were outstanding, and none were exercised in 2012. The intrinsic value of options exercised in the years ended December 31, 2011 and 2010 was $22,000 and $0.4 million, respectively, and we received $8,000 and $0.2 million, respectively, upon the exercise of such options.

Other

We have a 401(k) defined contribution plan whereby we have matched 100% of an employee’s contribution (subject to certain limitations in the plan). In 2012, we made cash contributions totaling $11.6 million and accrued a supplemental contribution of $2.7 million paid in 2013. In 2011 and 2010, we made cash contributions totaling $10.3 million and $9.2 million, respectively, to the 401(k) plan.

We have certain awards which have vested, but the issuance of those common shares has been deferred. During 2012, 2011 and 2010, approximately 308,000, 318,000 and 348,000 common shares, respectively, vested and were deferred resulting in a total of approximately 1,354,000 deferred common shares at December 31, 2012. These common shares will be issued upon the earliest of a change in control, the deferral date or the recipient’s retirement or death.

Note 12 — Income Taxes

For the years ended December 31, 2012, 2011 and 2010 our income (loss) before income taxes consisted of (in thousands):

	Year Ended December 31,
	2012			2011			2010
U.S.	$	514,272		$	341,378		$	263,917
Non U.S.		(175	)		(437	)		(59,907	)
	$	514,097		$	340,941		$	204,010

F-40

For the years ended December 31, 2012, 2011 and 2010 our income tax (benefit) expense consisted of (in thousands):

	Year Ended December 31,
	2012			2011			2010
Current
U.S. Federal	$	(3,000	)	$	(25,673	)	$	(89,680	)
State		(1,102	)		(279	)		(3,410	)
	$	(4,102	)	$	(25,952	)	$	(93,090	)
Deferred
U.S. Federal	$	199,615		$	150,266		$	180,384
State		(24,203	)		9,948			13,451
	$	175,412		$	160,214		$	193,835
	$	171,310		$	134,262		$	100,745

Our deferred income tax assets and liabilities at December 31, 2012 and 2011 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,
	2012			2011
Deferred tax assets
Net operating loss	$	441,181		$	372,300
Tax credits		52,158			52,497
Stock-based compensation, commodity derivative contracts and other		57,396			56,431
		550,735			481,228
Deferred tax liabilities
Commodity derivative contracts		(21,028	)		(24,091	)
Net oil and gas acquisition, exploration and development operations and other		(2,146,293	)		(1,898,311	)
Net deferred tax liability	$	(1,616,586	)	$	(1,441,174	)
Current asset	$	150,876		$	20,723
Long-term asset		5,348			-
Current liability		(2,242	)		-
Long-term liability		(1,770,568	)		(1,461,897	)
Net deferred tax liability	$	(1,616,586	)	$	(1,441,174	)

F-41

Tax carryforwards at December 31, 2012, which are available for future utilization on income tax returns, are as follows (in thousands):

FEDERAL - PXP and Consolidated Subsidiaries	Amount		Expiration
Alternative minimum tax (AMT) credit	$	2,242	-
Enhanced oil recovery credit		35,424	2025
Net operating loss – regular tax		943,633	2027 - 2032
Net operating loss – AMT tax		439,121	2031 - 2032
FEDERAL - Plains Offshore
Net operating loss – regular tax	$	84,735	2031 - 2032
Net operating loss – AMT tax		32,997	2031 - 2032
STATE - PXP and Combined Subsidiaries
AMT credit	$	521	-
Enhanced oil recovery credit		22,296	2016 - 2020
Net operating loss – regular tax		1,512,768	2021 - 2032
Net operating loss – AMT tax		336,138	2031 - 2032

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

	Year Ended December 31,
	2012			2011			2010
U.S. federal income tax provision at statutory rate	$	179,933		$	119,329		$	71,404
State income taxes, net of federal expense		(25,305	)		9,669			10,041
Non-deductible expenses		14,852			10,389			14,644
Uncertain tax positions		698			(6,277	)		(1,169	)
Non-cash compensation		-			-			2,506
Other		1,132			1,152			3,319
Income tax expense on income before income taxes	$	171,310		$	134,262		$	100,745

Included in our 2012 amount for state income taxes, net of federal expense is a reduction to our deferred state income tax liabilities of $31.5 million related to changes in state tax apportionment factors as a result of the Gulf of Mexico Acquisition.

Tax Relationship with Plains Offshore. As of December 31, 2012 and 2011, Plains Offshore was not consolidated with us for federal income tax purposes. Plains Offshore files a separate federal tax return and has its own federal tax loss carryforwards and other tax attributes. Plains Offshore may or may not be combined with us and our other subsidiaries for state tax filing purposes dependent upon the applicable state tax rules. We and Plains Offshore have entered into a Tax Matters Agreement, or TMA, which governs Plains Offshore’s and our respective rights, responsibilities, and obligations with respect to the filing of tax returns, payment of taxes, conduct of tax audits and certain other tax matters.

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Under the TMA, Plains Offshore is obligated to reimburse us for its share of taxes that are paid by us and can receive payment from us for any Plains Offshore tax attributes utilized by us related to our tax returns filed on a consolidated, combined or unitary basis including Plains Offshore but only to the extent and at such time as Plains Offshore would have paid the tax or utilized such attributes on a separate return basis. To the extent Plains Offshore files tax returns which are not consolidated, combined or unitary with us, Plains Offshore pays its tax liabilities directly to the applicable taxing authority.

Tax Loss and Credit Carryovers. Certain of our U.S. and state tax loss and credit carryovers are, or may become, subject to federal or state income tax limitations as to the amount that can be used each year. We do not expect these limitations to materially impact our ability to utilize these losses.

Valuation Allowance. In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the related deferred tax benefits will not be realized. We consider the scheduled reversal of deferred tax liabilities, projected future income and tax planning strategies in making the assessment of whether it is more likely than not that some portion or all of our deferred tax assets will not be realized. Based on this assessment as of December 31, 2012, no valuation allowances were necessary.

Other Tax Matters. We did not record a tax benefit related to non-cash employee compensation for 2012 and 2011 since we generated a net operating loss for federal tax purposes in both 2012 and 2011 which will be carried forward to future periods. As the Company utilizes this net operating loss in future periods, a tax benefit of $4.0 million will be credited to additional paid-in capital as a result of the non-cash employee compensation that vested in 2012 and 2011. In 2010 we recorded tax expense of $2.7 million related to non-cash employee compensation that vested in that year.

Unrecognized Tax Benefits. A reconciliation of the beginning and ending amount of gross unrecognized tax benefits (excluding accrued interest) is as follows (dollars in thousands):

	2012			2011			2010
Balance at beginning of period	$	7,311		$	13,896		$	16,473
Additions based on tax positions related to the current year		-			-			-
Adjustments for audit settlements in the current year		(660	)		-			(1,901	)
Additions for tax positions in prior years		660			-			-
Reductions for tax positions of prior years		-			(833	)		-
Adjustments due to any expiration of a statute of limitations		-			(5,752	)		(676	)
Balance at end of period	$	7,311		$	7,311		$	13,896

During 2012, our balance of net unrecognized tax benefits increased by $0.7 million during the year related to certain state tax positions under audit and later decreased by $0.7 million when these same state tax audits were concluded. During 2011, our balance of net unrecognized tax benefits decreased by $6.1 million primarily as a result of the expiration of the statute of limitations for various tax years. During 2010, we concluded our administrative appeal with the IRS and as a result reduced our balance of gross unrecognized tax benefits by $2.6 million primarily related to certain tax deductions for these same tax years.

We estimate our balance of net unrecognized tax benefits will be reduced by $5.3 million over the next twelve months as the statute of limitations expires for various tax years. Included in the balance at December 31, 2012 is approximately $6.9 million that would affect our effective tax rate if recognized. The difference between this amount and the $7.3 million ending balance of gross unrecognized tax benefits represents the federal benefit of state tax positions.

F-43

We had approximately $2.5 million and $1.8 million of accrued interest on unrecognized tax benefits in our balance sheets as of December 31, 2012 and 2011, respectively. We did not have any accrued liabilities for penalties related to unrecognized tax benefits for the years ended December 31, 2012 and 2011.

We file income tax returns in the U.S. federal and various state and foreign jurisdictions. As of December 31, 2012, we are not under examination by the IRS and are no longer subject to U.S. federal income tax examinations for years prior to 2007 except for certain tax credit carryforwards generated before 2007, but utilized after 2006. We received a letter from the IRS in 2012 indicating that our federal tax returns for the years 2008, 2009 and 2010 were being evaluated by the IRS to determine whether they will be examined or accepted without examination. No subsequent response has yet been received from the IRS concerning this evaluation.

We are currently undergoing an audit by the state of California with regard to our 2007 and 2008 California income tax returns. We are not currently under examination in any other states. In all states except California and Louisiana, we are no longer subject to state income tax examinations by the relevant tax authorities for years prior to 2009. For California, we are no longer subject to state income tax examinations for years prior to 2007 except for certain California tax loss and credit carryforwards generated before 2007 but utilized after 2006. For Louisiana, we are no longer subject to state income tax examinations for years prior to 2009 except for certain Louisiana tax loss carryforwards generated before 2009 but utilized after 2008.

Note 13 — Commitments, Contingencies and Industry Concentration

Commitments and Contingencies

Operating Leases. Our operating leases relate primarily to obligations associated with aircraft and office facilities. Future non-cancellable commitments related to these leases are as follows (in thousands):

2013	$	18,015
2014		18,186
2015		17,244
2016		14,387
2017		14,080
Thereafter		30,681
	$	112,593

Total expenses related to such leases were $13.9 million, $12.2 million and $12.3 million in 2012, 2011 and 2010, respectively.

F-44

Contractual Obligations. As is common within the industry, we have entered into various commitments and operating agreements associated with, among other things, oil and gas exploration, development and production activities, gathering and transportation, drilling rig and oilfield and other services. Aggregate future obligations under these agreements, described below, total $567.9 million, of which approximately $247.9 million is expected to be paid in 2013, $63.3 million in 2014, $42.7 million in 2015, $40.1 million in 2016, $35.3 million in 2017 and $138.6 million thereafter.

Through our ownership in Lucius, located in the deepwater U.S. Gulf of Mexico, we joined the Lucius and Hadrian working interest partners and executed a unit participation and unit operating agreement effective June 1, 2011. As part of the agreements, we have agreed to share in our portion of certain costs for construction and installation of the production facility and subsea infrastructure, long lead equipment orders and detailed engineering work and have a commitment of approximately $201.9 million remaining under the development plan.

Plains Offshore and its partners have entered into various agreements with third parties for long-term oil and gas gathering and transportation services at the Lucius oil field. Beginning in 2014, Plains Offshore will pay guaranteed fixed minimum monthly fees plus additional variable gathering fees based upon actual throughput. The commitments of Plains Offshore under the oil gathering agreements are guaranteed by PXP.

We have commitments for hydraulic fracturing services, coil tubing services and drilling rig contracts with terms from one year up to three years primarily to perform our Eagle Ford Shale drilling program.

At our Arroyo Grande field in San Luis Obispo County, California, we have committed for the design and construction of a produced water reclamation facility. Additionally, we have signed a ten-year operations agreement for the facility which will commence upon commercial operations expected in the first quarter of 2013.

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 100 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.

F-45

In California, the California Air Resources Board, or CARB, has developed regulations pursuant to the California Global Warming Solutions Act of 2006, or Assembly Bill 32, that are intended to achieve an overall reduction in greenhouse gas emissions to 1990 levels, a 15% reduction by 2020. Because several of our operations emit greenhouse gases in excess of 25,000 metric tons per year, various operations in California are subject to the requirements of this program. In October 2011 CARB adopted the final Cap and Trade regulation which is intended to implement the Cap and Trade Program under Assembly Bill 32. The regulation established three separate three year compliance periods as follows: 2012 to 2014, 2015 to 2017 and 2018 to 2020. The regulation required regulated entities to “true up” their emission offset obligations by the end of each three-year obligation period. Due to time constraints on implementing the Cap and Trade Program, the regulation included a provision which would forego the requirement of regulated entities to surrender compliance instruments for their emissions the first year of the first compliance period. The first year which will require regulated entities to surrender compliance instruments will be for 2013 emissions, and we are in the process of acquiring our required allowances. Compliance with these regulations will require companies to periodically secure instruments known as offsets and allowances, each of which is equal to one metric ton of emissions under the Cap and Trade program. The price of these instruments will vary in accordance with market conditions. The total amount of instruments we owe will vary annually based on the total greenhouse gas emissions registered in any one year and the number of “free allowances” issued by CARB annually. In November 2012 CARB held the first public auction of allowance instruments for regulated entities to begin meeting their compliance obligations. The settling price in the auction placed the price at $10.09 per allowance. In 2011 our California properties subject to regulation under Assembly Bill 32 emitted 955,000 metric tons of greenhouse gas emissions. In 2012 we were issued 644,000 free allowances by CARB based on estimated emissions using our 2011 verified emissions data. Based on these figures we will be required to secure an estimated 311,000 instruments to meet our 2013 obligations by the end of the first compliance period.

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 platforms, tanks, production equipment and flow lines and restore the wellsite. We estimate our 2013 cash expenditures related to plugging, abandonment and remediation will be approximately $18.5 million. Typically, when producing oil and gas assets are purchased, the purchaser assumes the obligation to plug and abandon wells and facilities that are part of such assets. See Note 10 – Asset Retirement Obligation. However, in some instances, we have received an indemnity with respect to those costs. We cannot be assured that we will be able to collect on these indemnities.

Although our offshore California properties have a shorter reserve life, third parties have retained the majority of the obligations for abandoning these properties, which include the Point Arguello Unit, offshore California, where the companies from which we purchased our interests retained responsibility for: (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 abandonments, conductor removals and site cleanup and preparation.

F-46

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, $74.3 million ($151.3 million undiscounted), is included in our asset retirement obligation as reflected on our 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 $84.3 million). To secure its abandonment obligations, the purchaser of the properties is required to periodically deposit funds into an escrow account. At December 31, 2012, the escrow account had a balance of $20.9 million. The fair value of our guarantee at December 31, 2012, $0.3 million, considers the payment/performance risk of the purchaser and is included in other long-term liabilities in our 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. 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. 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 are self-insured for named windstorms in the Gulf of Mexico. 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.

In the event we make a claim under our insurance policies, we will be subject to the credit risk of the insurers. Volatility and disruption in the financial and credit markets may adversely affect the credit quality of our insurers and impact their ability to pay out claims.

Firm Delivery Commitments. Beginning in December 2012, we have oil and gas production volume delivery commitments. If we are unable to meet the commitments to deliver this production, our maximum financial commitment at December 31, 2012 would be $50.6 million over the remaining contract term. We currently have sufficient reserves and production capacity to fulfill this commitment. In December 2012, we were producing 12.4 MBbls per day at these properties. As of December 31, 2012, our delivery commitments for the next five years and thereafter were as follows:

	Oil (MBbl)
2013		3,378
2014		4,473
2015		5,475
2016		5,490
2017		5,010
Thereafter		-
		23,826

F-47

Shareholder Class Actions. Beginning on December 5, 2012, 26 purported shareholder class actions were filed challenging the merger of the Company with Freeport-McMoRan and the MMR Merger. The lawsuits were filed against PXP, Freeport-McMoRan and McMoRan and the boards of these companies as well as certain other named individuals. The shareholder class actions generally allege that the boards of these companies breached fiduciary duties and adversely affected shareholders by approving the merger and the MMR Merger. We believe these purported shareholder class actions are without merit and we intend to defend against them vigorously.

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

Industry Concentration

Financial instruments that potentially subject us to concentrations of credit risk consist principally of accounts receivable with respect to our oil and gas operations and derivative instruments. During the three years ended December 31, 2012, 2011 and 2010, sales to the following purchasers accounted for the percentages of our total revenues as disclosed:

	2012			2011			2010
ConocoPhillips (1)		14	%		41	%		57	%
Phillips 66 (1)		35	%		-			-
Valero Energy Corporation		17	%		11	%		-	%(2)
Tesoro Corporation (3)		-			13	%		-	%(2)

(1) Phillips 66 was spun off from ConocoPhillips on May 1, 2012. On a combined basis, sales to Phillips 66 and ConocoPhillips accounted for 49% of our total revenues in 2012.

(2) Sales accounted for less than 10% of our total revenues.

(3) The contract with Tesoro Corporation expired in November 2011. We did not renew this contract, and upon expiration we entered into a contract with ConocoPhillips for these volumes, which was subsequently assigned to Phillips 66.

During 2012, 2011 and 2010, no other purchaser accounted for more than 10% of our total revenues. Beginning in early 2013, a large portion of our production from the Gulf of Mexico Acquisition will be sold to Phillips 66. Based on current production rates, we anticipate a larger percentage of our total revenue will result from sales to Phillips 66 in 2013. The loss of any single significant purchaser or contract could have a material adverse short-term effect; however, we do not believe that the loss of any single significant purchaser 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 such purchasers may be affected by changes in economic, industry or other conditions. We do not currently require letters of credit or other collateral from the above stated purchasers to support trade receivables. Accordingly, a material adverse change in any such purchaser’s financial condition could adversely impact our ability to collect the applicable receivables, and thereby affect our financial condition.

F-48

As a result of the Gulf of Mexico Acquisition, a substantial portion of our production is from the Gulf of Mexico beginning in December 2012 and expected to continue in 2013. Our Gulf of Mexico operations are subject to more extensive governmental regulation than our other oil and gas activities. Further, these properties are vulnerable to hurricanes and other adverse weather conditions, oilfield service costs and availability as well as compliance with environmental and other laws and regulations, remediation and other costs resulting from oil spill releases of hazardous materials or other environmental damages.

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 us 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.

Subsequent Event

Offshore Morocco Exploration. In January 2013, we announced we entered into a definitive agreement to participate in an exploration program offshore the Kingdom of Morocco. Subject to customary closing conditions, including the receipt of Moroccan governmental approvals (expected first half of 2013), we will make a cash payment of $15.0 million to farm-in to Pura Vida Energy’s 75% working interest in the approximate 2.7 million acre Mazagan permit area in the Essaouira Basin offshore Morocco. We will earn a 52% working interest and act as operator in exchange for funding 100% of the costs of certain specified exploration activities that will include a commitment to fund and drill two wells, and if agreed, various additional exploration operations subject to a maximum of $215.0 million. The first exploration well is expected to be drilled in 2014.

Note 14 — Supplemental Cash Flow Information

Cash payments (receipts) for interest and income taxes were as follows (in thousands):

	Year Ended December 31,
	2012			2011			2010
Cash payments for interest (net of capitalized interest)	$	194,917		$	164,474		$	98,262
Cash (receipts) payments for income taxes	$	(8,030	)	$	(62,414	)	$	(58,920	)

At December 31, 2012 and 2011, accrued capital expenditures included in accounts payable in the balance sheet were $225.2 million and $196.0 million, respectively.

Common stock and treasury shares issued in connection with our compensation plans were as follows (in thousands):

	Year Ended December 31,
	2012		2011		2010
Shares (1)		733		876		728
Amount (1)	$	31,014	$	31,052	$	21,232

(1) The number of shares is net of shares withheld for employee taxes and the amount is based on the grant date price.

F-49

Non-cash oil and gas property reductions and additions included:

• non-cash reductions to oil and gas properties in 2010 of $665.9 million related to the sale of our Gulf of Mexico shallow water shelf properties in exchange for 51.0 million shares of McMoRan common stock; and

• non-cash additions to oil and gas properties of $350.7 million, $12.9 million and $21.8 million in 2012, 2011 and 2010, respectively, related to our asset retirement obligation. The 2012 non-cash additions to oil and gas properties are primarily attributable to obligations assumed in connection with the Gulf of Mexico Acquisition.

Certain of our commodity derivative contracts include deferred premiums to be paid to the counterparty based on the settlement terms specified in the contract. During 2012, 2011 and 2010, we entered into derivative contracts with deferred premiums of $470.7 million, $49.2 million and $162.9 million, respectively. In connection with our February 2012 derivative transactions, we converted 5,000 BOPD of Brent crude oil put option contracts for 2013 to three-way collars and eliminated approximately $11.3 million of deferred premiums and interest. In connection with our September 2011 derivative transactions, we eliminated $93.2 million of deferred premiums and interest associated with contracts entered into in 2010.

Note 15 — Equity

Pursuant to the terms of the Freeport-McMoRan Merger Agreement, on the closing of the merger, all outstanding PXP common stock will be converted into the right to receive, at the election of the holder, the cash consideration or the stock consideration, subject to the proration specified within the Freeport-McMoRan Merger Agreement. See Note 2 – Proposed Merger with Freeport-McMoRan Copper & Gold Inc. The disclosures and tables that follow are based on the existing terms of our equity and do not reflect any impact of the Freeport-McMoRan Merger Agreement.

Earnings Per Common Share

Weighted average common shares outstanding for computing basic and diluted earnings were as follows (in thousands):

	Year Ended December 31,
	2012		2011		2010
Common shares outstanding – basic		129,925		141,227		140,438
Unvested restricted stock, restricted stock units and stock options		1,942		1,772		1,459
Common shares outstanding – diluted		131,867		142,999		141,897

Included in computing our basic earnings per common share are certain awards which have vested, but, at the election of the award recipients, the issuance of those common shares has been deferred. For the years ended December 31, 2012, 2011 and 2010, 0.2 million, 1.4 million and 1.8 million, respectively, restricted stock units were excluded in computing diluted earnings per common share because they were antidilutive due to the impact of the unrecognized compensation cost on the calculation of assumed proceeds in the application of the treasury stock method.

F-50

In computing our earnings per share for years ended December 31, 2012 and 2011, we decreased our reported net income by $36.4 million and $1.4 million, respectively, for preferred stock dividends attributable to the noncontrolling interest associated with our consolidated subsidiary Plains Offshore. We owned 100% of the common shares of Plains Offshore during the years ended December 31, 2012 and 2011, and because Plains Offshore had a net loss for the years ended December 31, 2012 and 2011, we did not allocate any undistributed earnings to the noncontrolling interest preferred stock. In the event that Plains Offshore has net income in future periods, we will be required to allocate distributed and undistributed earnings between the common and preferred shares of Plains Offshore.

Authorized Shares

The number of our authorized common shares at December 31, 2012 is 250.0 million, with a par value of $0.01.

The number of our authorized preferred shares at December 31, 2012 is 5.0 million, with a par value of $0.01. No PXP preferred shares were issued as of December 31, 2012.

Stock Repurchase Program

In January 2012, we repurchased 2.4 million common shares at an average cost of $37.02 per share totaling $88.5 million. Subsequent to these repurchases, our Board of Directors reset the authorization to $1.0 billion of PXP common stock and extended the program until January 2016.

During the year ended December 31, 2011, we repurchased 10.4 million common shares at an average cost of $34.73 per share totaling $361.7 million.

Note 16 — Other Income

Other income for 2010 primarily consists of $8.1 million of royalty receipts and related interest and $5.0 million of preacquisition adjustments related to properties sold by Pogo prior to our acquisition of Pogo.

F-51

Note 17 — Consolidating Financial Statements

We are the issuer of 10% Senior Notes, 7 ⁵/₈% Senior Notes due 2018, 6 ¹/₈% Senior Notes, 8 ⁵/₈% Senior Notes, 7 ⁵/₈% Senior Notes due 2020, 6 ¹/₂% Senior Notes, 6 ⁵/₈% Senior Notes, 6 ³/₄% Senior Notes and 6 ⁷/₈% Senior Notes as of December 31, 2012, which are jointly and severally guaranteed by certain of our existing domestic subsidiaries (referred to as “Guarantor Subsidiaries”). In the future, a subsidiary guarantor’s guarantee may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the assets of that subsidiary guarantor; (ii) in connection with any sale or other disposition of all the capital stock of that subsidiary guarantor; (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation or dissolution of that subsidiary guarantor provided no default or event of default has occurred or is continuing; or (vi) at such time as that subsidiary guarantor does not have outstanding any guarantee of any of our or any of our other subsidiary guarantors’ indebtedness (other than the notes) in excess of $10.0 million in aggregate principal amount. Certain of our subsidiaries do not guarantee the Senior Notes (referred to as “Non-Guarantor Subsidiaries”).

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

• PXP (the “Issuer”);

• the Guarantor Subsidiaries on a combined basis;

• the Non-Guarantor Subsidiaries on a combined basis;

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

• PXP on a consolidated basis.

F-52

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2012

(in thousands of dollars)

	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	11,722	$	-	$	168,843	$	-	$	180,565
Accounts receivable and other current assets		1,349,806		305,702		3,657		-		1,659,165
		1,361,528		305,702		172,500		-		1,839,730
Property and Equipment, at cost
Oil and natural gas properties - full cost method		5,801,258		15,167,966		1,476,588		-		22,445,812
Other property and equipment		56,618		42,162		54,564		-		153,344
		5,857,876		15,210,128		1,531,152		-		22,599,156
Less allowance for depreciation, depletion, amortization and impairment		(2,757,630)		(7,803,206)		(999,711)		3,690,191		(7,870,356)
		3,100,246		7,406,922		531,441		3,690,191		14,728,800
Investment in and Advances to Affiliates		10,326,671		(5,503,149)		(99,206)		(4,724,316)		-
Other Assets		173,680		587,927		11,861		(43,715)		729,753
	$	14,962,125	$	2,797,402	$	616,596	$	(1,077,840)	$	17,298,283
LIABILITIES AND EQUITY
Current Liabilities	$	807,820	$	95,876	$	76,305	$	-	$	980,001
Long-Term Debt		9,979,369		-		-		-		9,979,369
Other Long-Term Liabilities		250,684		360,153		1,067		-		611,904
Deferred Income Taxes		407,774		(6,658)		32,992		1,336,460		1,770,568
Equity
Stockholders’ equity		3,516,478		2,348,031		66,269		(2,414,300)		3,516,478
Noncontrolling interest Preferred stock of subsidiary		-		-		439,963		-		439,963
		3,516,478		2,348,031		506,232		(2,414,300)		3,956,441
	$	14,962,125	$	2,797,402	$	616,596	$	(1,077,840)	$	17,298,283

F-53

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2011

(in thousands of dollars)

	Issuer		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Intercompany Eliminations		Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	3,189	$	6	$	415,903	$	-	$	419,098
Accounts receivable and other current assets		885,860		136,642		444		(667)		1,022,279
		889,049		136,648		416,347		(667)		1,441,377
Property and Equipment, at cost
Oil and natural gas properties - full cost method		4,301,524		8,841,469		1,282,708		-		14,425,701
Other property and equipment		52,906		42,747		50,306		-		145,959
		4,354,430		8,884,216		1,333,014		-		14,571,660
Less allowance for depreciation, depletion, amortization and impairment		(2,327,063)		(6,392,068)		(1,059,186)		2,931,952		(6,846,365)
		2,027,367		2,492,148		273,828		2,931,952		7,725,295
Investment in and Advances to Affiliates		4,583,550		(1,282,085)		(73,079)		(3,228,386)		-
Other Assets		73,832		548,615		2,353		-		624,800
	$	7,573,798	$	1,895,326	$	619,449	$	(297,101)	$	9,791,472
LIABILITIES AND EQUITY
Current Liabilities	$	443,098	$	135,681	$	48,074	$	(667)	$	626,186
Long-Term Debt		3,760,952		-		-		-		3,760,952
Other Long-Term Liabilities		211,106		35,296		803		-		247,205
Deferred Income Taxes		(105,994)		437,367		31,757		1,098,767		1,461,897
Equity
Stockholders’ equity		3,264,636		1,286,982		108,219		(1,395,201)		3,264,636
Noncontrolling interest Preferred stock of subsidiary		-		-		430,596		-		430,596
		3,264,636		1,286,982		538,815		(1,395,201)		3,695,232
	$	7,573,798	$	1,895,326	$	619,449	$	(297,101)	$	9,791,472

F-54

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME

YEAR ENDED DECEMBER 31, 2012

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	2,024,231		$	301,691		$	-		$	-		$	2,325,922
Gas sales		34,357			198,084			-			-			232,441
Other operating revenues		1,179			5,765			-			-			6,944
		2,059,767			505,540			-			-			2,565,307
Costs and Expenses
Production costs		448,530			182,616			1,306			-			632,452
General and administrative		117,531			73,792			7,850			-			199,173
Depreciation, depletion, amortization and accretion		461,258			224,632			534			431,628			1,118,052
Impairment of oil and gas properties		-			1,189,867			-			(1,189,867	)		-
Other operating expense (income)		3,511			(3,538	)		-			-			(27	)
		1,030,830			1,667,369			9,690			(758,239	)		1,949,650
Income (Loss) from Operations		1,028,937			(1,161,829	)		(9,690	)		758,239			615,657
Other (Expense) Income
Equity in earnings of subsidiaries		(394,676	)		-			-			394,676			-
Interest expense		(91,069	)		(200,952	)		(5,518	)		-			(297,539	)
Debt extinguishment costs		(8,388	)		-			-			-			(8,388	)
Loss on mark-to-market derivative contracts		(2,879	)		-			-			-			(2,879	)
Gain on investment measured at fair value		206,552			-			-			-			206,552
Other income		304			356			34			-			694
Income (Loss) Before Income Taxes		738,781			(1,362,425	)		(15,174	)		1,152,915			514,097
Income tax (expense) benefit		(432,361	)		532,866			9,592			(281,407	)		(171,310	)
Net Income (Loss)		306,420			(829,559	)		(5,582	)		871,508			342,787
Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary		-			-			(36,367	)		-			(36,367	)
Net Income (Loss) Attributable to Common Stockholders	$	306,420		$	(829,559	)	$	(41,949	)	$	871,508		$	306,420

F-55

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME

YEAR ENDED DECEMBER 31, 2011

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	1,271,176		$	256,558		$	922		$	-		$	1,528,656
Gas sales		16,910			411,310			-			-			428,220
Other operating revenues		1,309			6,303			-			-			7,612
		1,289,395			674,171			922			-			1,964,488
Costs and Expenses
Production costs		360,643			198,332			-			-			558,975
General and administrative		81,720			49,866			2,458			-			134,044
Depreciation, depletion, amortization and accretion		214,389			271,747			339			195,180			681,655
Impairment of oil and gas properties		-			354,305			495,504			(849,809	)		-
Other operating expense (income)		184			(919	)		-			-			(735	)
		656,936			873,331			498,301			(654,629	)		1,373,939
Income (Loss) from Operations		632,459			(199,160	)		(497,379	)		654,629			590,549
Other (Expense) Income
Equity in earnings of subsidiaries		(124,416	)		-			-			124,416			-
Interest expense		(1,320	)		(156,580	)		(3,416	)		-			(161,316	)
Debt extinguishment costs		(120,954	)		-			-			-			(120,954	)
Gain on mark-to-market derivative contracts		81,981			-			-			-			81,981
Loss on investment measured at fair value		(52,675	)		-			-			-			(52,675	)
Other income (expense)		1,521			1,893			(58	)		-			3,356
Income (Loss) Before Income Taxes		416,596			(353,847	)		(500,853	)		779,045			340,941
Income tax (expense) benefit		(211,317	)		137,153			172,961			(233,059	)		(134,262	)
Net Income (Loss)		205,279			(216,694	)		(327,892	)		545,986			206,679
Net income attributable to noncontrolling interest in the form of preferred stock of subsidiary		-			-			(1,400	)		-			(1,400	)
Net Income (Loss) Attributable to Common Stockholders	$	205,279		$	(216,694	)	$	(329,292	)	$	545,986		$	205,279

F-56

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF INCOME

YEAR ENDED DECEMBER 31, 2010

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil sales	$	952,714		$	190,046		$	-		$	-		$	1,142,760
Gas sales		67,780			331,827			-			-			399,607
Other operating revenues		884			1,344			-			-			2,228
		1,021,378			523,217			-			-			1,544,595
Costs and Expenses
Production costs		296,285			155,617			-			-			451,902
General and administrative		87,043			48,322			1,072			-			136,437
Depreciation, depletion, amortization and accretion		218,905			161,006			144			171,063			551,118
Impairment of oil and gas properties		-			266,442			63,636			(270,603	)		59,475
Legal recovery		-			(8,423	)		-			-			(8,423	)
Other operating income		(988	)		(3,142	)		-			-			(4,130	)
		601,245			619,822			64,852			(99,540	)		1,186,379
Income (Loss) from Operations		420,133			(96,605	)		(64,852	)		99,540			358,216
Other (Expense) Income
Equity in earnings of subsidiaries		(119,427	)		(68	)		-			119,495			-
Interest expense		(84	)		(104,383	)		(2,246	)		-			(106,713	)
Debt extinguishment costs		(1,189	)		-			-			-			(1,189	)
Loss on mark-to-market derivative contracts		(60,695	)		-			-			-			(60,695	)
Other income (expense)		976			13,486			(71	)		-			14,391
Income (Loss) Before Income Taxes		239,714			(187,570	)		(67,169	)		219,035			204,010
Income tax (expense) benefit		(136,449	)		50,995			3,983			(19,274	)		(100,745	)
Net Income (Loss)	$	103,265		$	(136,575	)	$	(63,186	)	$	199,761		$	103,265

F-57

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2012

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	306,420		$	(829,559	)	$	(5,582	)	$	871,508		$	342,787
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization, accretion and impairment		461,258			1,414,499			534			(758,239	)		1,118,052
Equity in earnings of subsidiaries		394,676			-			-			(394,676	)		-
Deferred income tax expense (benefit)		362,818			(461,848	)		(6,966	)		281,408			175,412
Debt extinguishment costs		4,160			-			-			-			4,160
Loss on mark-to-market derivative contracts		2,879			-			-			-			2,879
Gain on investment measured at fair value		(206,552	)		-			-			-			(206,552	)
Non-cash compensation		49,563			10,684			-			-			60,247
Other non-cash items		8,260			(116	)		126			-			8,270
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(101,534	)		(137,942	)		(5,134	)		-			(244,610	)
Accounts payable and other liabilities		49,756			8,575			8,655			-			66,986
Income taxes receivable/payable		3,160			-			-			-			3,160
Net cash provided by (used in) operating activities		1,334,864			4,293			(8,367	)		1			1,330,791
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(1,387,151	)		(264,530	)		(202,574	)		-			(1,854,255	)
Acquisition of oil and gas properties		(21,217	)		-			(29,834	)		-			(51,051	)
Gulf of Mexico Acquisition		-			(5,895,878	)		-			-			(5,895,878	)
Proceeds from sales of oil and gas properties, net of costs and expenses		67,619			-			-			-			67,619
Derivative settlements		42,894			-			-			-			42,894
Other		(8,322	)		(4	)		(4,258	)		-			(12,584	)
Net cash used in investing activities		(1,306,177	)		(6,160,412	)		(236,666	)		-			(7,703,255	)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		9,479,075			-			-			-			9,479,075
Repayments of revolving credit facilities		(8,644,075	)		-			-			-			(8,644,075	)
Proceeds from term loans		1,950,864			-			-			-			1,950,864
Principal payments of long-term debt		(156,182	)		-			-			-			(156,182	)
Proceeds from issuance of Senior Notes		3,750,000			-			-			-			3,750,000
Costs incurred in connection with financing arrangements		(130,261	)		-			-			-			(130,261	)
Purchase of treasury stock		(88,490	)		-			-			-			(88,490	)
Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary		-			-			(27,000	)		-			(27,000	)
Investment in and advances to affiliates		(6,181,085	)		6,156,113			24,973			(1	)		-
Net cash (used in) provided by financing activities		(20,154	)		6,156,113			(2,027	)		(1	)		6,133,931
Net increase (decrease) in cash and cash equivalents		8,533			(6	)		(247,060	)		-			(238,533	)
Cash and cash equivalents, beginning of period		3,189			6			415,903			-			419,098
Cash and cash equivalents, end of period	$	11,722		$	-		$	168,843		$	-		$	180,565

F-58

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2011

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	205,279		$	(216,694	)	$	(327,892	)	$	545,986		$	206,679
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization, accretion and impairment		214,389			626,052			495,843			(654,629	)		681,655
Equity in earnings of subsidiaries		124,416			-			-			(124,416	)		-
Deferred income tax expense (benefit)		19,961			42,812			(135,619	)		233,060			160,214
Debt extinguishment costs		2,844			-			-			-			2,844
Gain on mark-to-market derivative contracts		(81,981	)		-			-			-			(81,981	)
Loss on investment measured at fair value		52,675			-			-			-			52,675
Non-cash compensation		37,042			12,151			-			-			49,193
Other non-cash items		1,272			(6,898	)		67			-			(5,559	)
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(48,878	)		(9,937	)		1,086			-			(57,729	)
Accounts payable and other liabilities		56,840			(4,887	)		7,133			-			59,086
Income taxes receivable/payable		43,678			-			-			-			43,678
Net cash provided by operating activities		627,537			442,599			40,618			1			1,110,755
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(820,984	)		(853,696	)		(108,624	)		-			(1,783,304	)
Acquisition of oil and gas properties		(13,145	)		(27,370	)		-			-			(40,515	)
Proceeds from sales of oil and gas properties and related assets, net of costs and expenses		736,228			-			-			-			736,228
Derivative settlements		(55,412	)		-			-			-			(55,412	)
Other		(8,062	)		480			(4,006	)		-			(11,588	)
Net cash used in investing activities		(161,375	)		(880,586	)		(112,630	)		-			(1,154,591	)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		6,305,300			-			-			-			6,305,300
Repayments of revolving credit facilities		(6,190,300	)		-			-			-			(6,190,300	)
Principal payments of long-term debt		(1,295,737	)		-			-			-			(1,295,737	)
Proceeds from issuance of Senior Notes		1,600,000			-			-			-			1,600,000
Costs incurred in connection with financing arrangements		(27,829	)		-			(2,410	)		-			(30,239	)
Purchase of treasury stock		(361,729	)		-			-			-			(361,729	)
Net proceeds from issuance of noncontrolling interest in the form of preferred stock of subsidiary		-			-			430,246			-			430,246
Distributions to holders of noncontrolling interest in the form of preferred stock of subsidiary		-			-			(1,050	)		-			(1,050	)
Investment in and advances to affiliates		(498,707	)		437,985			60,691			31			-
Other		9			-			32			(32	)		9
Net cash (used in) provided by financing activities		(468,993	)		437,985			487,509			(1	)		456,500
Net (decrease) increase in cash and cash equivalents		(2,831	)		(2	)		415,497			-			412,664
Cash and cash equivalents, beginning of period		6,020			8			406			-			6,434
Cash and cash equivalents, end of period	$	3,189		$	6		$	415,903		$	-		$	419,098

F-59

PLAINS EXPLORATION & PRODUCTION COMPANY

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2010

(in thousands of dollars)

	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	103,265		$	(136,575	)	$	(63,186	)	$	199,761		$	103,265
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization, accretion and impairment		218,905			427,448			63,780			(99,540	)		610,593
Equity in earnings of subsidiaries		119,427			68			-			(119,495	)		-
Deferred income tax (benefit) expense		(326,269	)		469,426			30,296			20,382			193,835
Debt extinguishment costs		1,189			-			-			-			1,189
Loss on mark-to-market derivative contracts		60,695			-			-			-			60,695
Non-cash compensation		39,114			11,761			-			-			50,875
Other non-cash items		4,286			(1,890	)		198			-			2,594
Change in assets and liabilities from operating activities
Accounts receivable and other assets		(24,221	)		(23,356	)		1,471			-			(46,106	)
Accounts payable and other liabilities		12,449			(42,229	)		(1,571	)		-			(31,351	)
Income taxes receivable/payable		(33,119	)		-			-			-			(33,119	)
Net cash provided by operating activities		175,721			704,653			30,988			1,108			912,470
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(198,177	)		(679,918	)		(170,763	)		-			(1,048,858	)
Acquisition of oil and gas properties		(590,116	)		35,431			-			-			(554,685	)
Proceeds from sales of oil and gas properties		73,845			120			-			-			73,965
Derivative settlements		(29,921	)		-			-			-			(29,921	)
Other		(4,007	)		(6,115	)		(5,687	)		-			(15,809	)
Net cash used in investing activities		(748,376	)		(650,482	)		(176,450	)		-			(1,575,308	)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		3,332,610			-			-			-			3,332,610
Repayments of revolving credit facilities		(2,942,610	)		-			-			-			(2,942,610	)
Proceeds from issuance of Senior Notes		300,000			-			-			-			300,000
Costs incurred in connection with financing arrangements		(22,771	)		-			-			-			(22,771	)
Investment in and advances to affiliates		(90,042	)		(54,174	)		145,324			(1,108	)		-
Other		184			-			-			-			184
Net cash provided by (used in) financing activities		577,371			(54,174	)		145,324			(1,108	)		667,413
Net increase (decrease) in cash and cash equivalents		4,716			(3	)		(138	)		-			4,575
Cash and cash equivalents, beginning of period		1,304			11			544			-			1,859
Cash and cash equivalents, end of period	$	6,020		$	8		$	406		$	-		$	6,434

F-60

Note 18 — Quarterly Financial Data (Unaudited)

The following table shows summary financial data for 2012 and 2011 (in thousands, except per share data):

	First Quarter			Second Quarter		Third Quarter			Fourth Quarter		Year
2012
Revenues	$	524,275		$	566,724	$	605,104		$	869,204	$	2,565,307
Income from operations		171,297			135,555		131,767			177,038		615,657
Net (loss) income attributable to common stockholders		(82,319	)		223,199		(53,088	)		218,628		306,420
Basic (loss) earnings per common share		(0.64	)		1.72		(0.41	)		1.68		2.36
Diluted (loss) earnings per common share		(0.64	)		1.70		(0.41	)		1.65		2.32
2011
Revenues	$	430,314		$	514,785	$	501,848		$	517,541	$	1,964,488
Income from operations		133,788			186,095		168,552			102,114		590,549
Net income (loss) attributable to common stockholders		70,979			124,892		(88,296	)		97,704		205,279
Basic earnings (loss) per common share		0.50			0.88		(0.62	)		0.70		1.45
Diluted earnings (loss) per common share		0.49			0.87		(0.62	)		0.69		1.44

Note 19 — Oil and Natural Gas Activities (Unaudited)

Investment

At December 31, 2012, 2011 and 2010, we owned 51.0 million shares of McMoRan common stock, approximately 31.5%, 31.6% and 32.4%, respectively, of its common shares outstanding. McMoRan is a publicly traded oil and gas exploration and production company (New York Stock Exchange listing MMR) engaged in the exploration, development and production of natural gas and oil in the United States, specifically offshore in the shallow waters of the Gulf of Mexico Shelf and onshore in the Gulf Coast area. We acquired the McMoRan common stock and other consideration in exchange for all of our interests in our Gulf of Mexico leasehold located in less than 500 feet of water. See Note 4 – Divestments.

McMoRan follows the successful efforts method of accounting for its oil and natural gas activities. See Note 8 – Investment.

F-61

Costs Incurred

In 2012 and 2011, our oil and natural gas acquisition, exploration and development activities were conducted in the United States. The following table summarizes the costs incurred during the last three years (in thousands):

	Year Ended December 31,
	2012		2011		2010
Consolidated entities
Property acquisition costs
Unproved properties
Gulf of Mexico Acquisition	$	2,047,057	$	-	$	-
Other		55,571		36,562		612,471
Proved properties
Gulf of Mexico Acquisition		4,135,173		-		-
Other		3,827		9,236		48,078
Exploration costs (1)		1,078,986		1,147,858		719,004
Development costs		829,090		708,519		363,242
	$	8,149,704	$	1,902,175	$	1,742,795
Entity’s share of equity investee (2)
Property acquisition costs
Unproved properties	$	-	$	15,523
Proved properties		-		-
Exploration costs		162,150		175,802
Development costs		6,708		17,190
	$	168,858	$	208,515

(1) Exploration costs are related to exploratory activities as defined for accounting purposes and include the drilling of exploratory wells primarily in the Eagle Ford Shale and acquisition of seismic data.

(2) Amounts relate to our equity investment in McMoRan acquired on December 30, 2010. Our proportionate share of McMoRan’s 2010 costs incurred is not presented because it is insignificant as PXP owned the investment for one day and it is not practicable to determine one day of costs incurred.

Amounts presented include capitalized general and administrative expense of $93.5 million, $77.1 million and $68.0 million in 2012, 2011 and 2010, respectively, and capitalized interest expense of $49.1 million, $115.4 million and $128.0 million in 2012, 2011 and 2010, respectively. We had no international exploration costs in 2012 and 2011; in 2010, our international exploration costs, primarily in offshore Vietnam, were $1.7 million.

During the second quarter of 2010, we completed our interpretation of seismic and drilling data from our two offshore Vietnam exploratory wells and decided not to pursue additional exploratory activities in this area. We terminated our production sharing contract in accordance with its terms. The costs related to our Vietnam oil and gas properties not subject to amortization were transferred to our Vietnam full cost pool where they were subject to the ceiling limitation. Because our Vietnam full cost pool had no associated proved oil and gas reserves, we recorded a non-cash pre-tax impairment charge of $59.5 million. We also recorded a corresponding tax benefit of $23.0 million.

F-62

Capitalized Costs

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

	December 31,
	2012			2011
Consolidated entities
Property subject to amortization	$	18,814,337		$	12,016,252
Accumulated DD&A and impairment		(7,844,543	)		(6,823,722	)
	$	10,969,794		$	5,192,530
Entity’s share of equity investee (1)
Unproved properties	$	618,169		$	497,955
Proved properties		717,091			805,264
Accumulated DD&A and impairment		(580,995	)		(613,740	)
	$	754,265		$	689,479

(1) Amounts relate to our equity investment in McMoRan acquired on December 30, 2010.

Our average DD&A rate per BOE was $27.62, $17.76 and $15.87 in 2012, 2011 and 2010, respectively.

Costs not subject to amortization

The following table summarizes the categories of costs comprising the amount of unproved properties not subject to amortization by the year in which such costs were incurred (in thousands):

	December 31,
	Total		2012 (1)		2011		2010 (2)		Prior
Onshore
Acquisition costs	$	1,274,789	$	36,284	$	32,411	$	447,274	$	758,820
Exploration costs		49,736		37,228		8,639		3,651		218
Capitalized interest		150,346		39,229		63,950		37,877		9,290
Offshore
Acquisition costs		2,106,000		2,062,837		-		36,909		6,254
Exploration costs		42,117		37,514		3,260		148		1,195
Capitalized interest		8,487		2,653		3,198		1,966		670
	$	3,631,475	$	2,215,745	$	111,458	$	527,825	$	776,447

(1) Includes $2.0 billion attributable to the Gulf of Mexico Acquisition in the fourth quarter of 2012. See Note 3 – Acquisitions.

(2) Includes amounts attributable to our Eagle Ford Shale acquisition in the fourth quarter of 2010. See Note 3 – Acquisitions.

F-63

The costs of unproved oil and gas properties are excluded from amortization until the properties are evaluated. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Unproved properties are assessed periodically, at least annually, to determine whether impairment has occurred. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment considers the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. The transfer of costs into the amortization base involves a significant amount of judgment and may be subject to changes over time based on our drilling plans and results, geological and geophysical evaluations, the assignment of proved reserves, availability of capital, and other factors. Costs not subject to amortization consist primarily of capital costs incurred for undeveloped acreage and wells in progress pending determination, together with capitalized interest costs for these projects. Due to the nature of the reserves, the ultimate evaluation of the properties will occur over a period of several years. We expect that 58% of the costs not subject to amortization at December 31, 2012 will be transferred to the amortization base over the next five years and the remainder in the next seven to ten years.

Approximately 24% of our total net undeveloped acreage is covered by leases that will expire from 2013 to 2015. There are no material expirations of our net undeveloped acreage in the Gulf of Mexico within the next three years. In 2008 and 2010, we added a significant number of new leases in the Haynesville Shale and the Eagle Ford Shale, respectively, with lease terms generally ranging from two to three years. Over 90% of our acreage in the Haynesville Shale and over 50% of our acreage in the Eagle Ford Shale is currently held by production or held by operations and future plans include drilling or extending leases on our remaining acreage.

During the first quarter of 2012, due to low natural gas prices, our assessment of the unproved property in the Haynesville Shale area indicated an impairment and accumulated costs of approximately $483 million were transferred to the full cost pool.

During the third quarter of 2011, we determined not to develop the Friesian prospect and the lease terminated by its terms. The accumulated costs of approximately $460 million associated with the project were transferred to the full cost pool.

F-64

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 and interest income. Income tax expense was determined by applying the statutory rates to pre-tax operating results (in thousands):

	Year Ended December 31,
	2012			2011			2010
Consolidated entities
Revenues from oil and gas producing activities	$	2,565,307		$	1,964,488		$	1,544,595
Production costs		(632,425	)		(558,240	)		(447,772	)
Depreciation, depletion, amortization and accretion		(1,097,240	)		(664,892	)		(535,239	)
Impairment of oil and gas properties		-			-			(59,475	)
Income tax expense		(312,530	)		(277,860	)		(188,190	)
Results of operations from producing activities for consolidated entities (excluding general and administrative and interest costs)	$	523,112		$	463,496		$	313,919
Entity’s share of equity investee (1)
Revenues from oil and gas producing activities	$	114,343		$	171,370
Production and delivery costs		(48,869	)		(65,197	)
Exploration expenses		(40,318	)		(25,830	)
Depreciation, depletion, amortization and accretion		(40,203	)		(74,820	)
Impairment of oil and gas properties		(14,549	)		(22,477	)
Insurance recoveries		387			28,780
Gain on sale of oil and gas properties		12,743			284
Income tax expense		-			-
Results of operations from producing activities for equity investee (excluding general and administrative and interest costs)	$	(16,466	)	$	12,110

(1) Amounts relate to our equity investment in McMoRan acquired on December 30, 2010. We completed the divestment of our Gulf of Mexico shallow water properties on December 30, 2010. Our proportionate share of McMoRan’s 2010 results of operations is not presented because it is insignificant as PXP owned the investment for one day and it is not practicable to determine one day’s results of operations.

F-65

Supplemental Reserve Information

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, 2012. All of our reserves are located in the United States. The following table sets forth certain information with respect to all of our proved reserves that for 2012 are based upon reserve reports prepared by the independent petroleum engineers of Netherland, Sewell & Associates, Inc., or NSA. In 2011, our proved reserves were based upon (1) reserve reports prepared by the independent petroleum engineers of NSA (95% of proved reserve volumes) and (2) reserve volumes prepared by us, which were not audited by an independent petroleum engineer (5% of proved reserve volumes). In 2010, our proved reserves were based upon (1) reserve reports prepared by the independent petroleum engineers of NSA and Ryder Scott Company L.P., or Ryder Scott, (99% of proved reserve volumes) and (2) reserve volumes prepared by us, which were not audited by an independent petroleum engineer (1% of proved reserve volumes).

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 the amount 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 subjective, 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 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. Our reference prices are the WTI spot price for oil and the Henry Hub spot price for gas. As of February 2013, the twelve-month average of the first-day-of-the-month reference price for natural gas has increased from $2.76 per MMBtu at year-end 2012 to $2.86 per MMBtu, while the comparable price for oil has declined from $94.71 per Bbl at year-end 2012 to $94.14 per Bbl.

Historically, the market price for California crude oil differs from the established market indices in the United States due principally to the higher transportation and refining costs associated with heavy oil. Recently, however, the market price for California crude oil has strengthened relative to NYMEX and WTI primarily due to world demand and declining domestic supplies of both Alaskan and California crude oil. Approximately 43% of our 2012 reserve volumes are attributable to properties in California where differentials to the reference prices have been volatile due to these factors.

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Estimated Quantities of Oil and Natural Gas Reserves

The following table sets forth certain data pertaining to our proved, proved developed and proved undeveloped reserves for the three years ended December 31, 2012.

	Oil (MBbl)			Gas (MMcf)			(MBOE)
2012
Consolidated entities
Proved Reserves
Beginning balance		244,030			1,001,311			410,915
Revisions of previous estimates		(15,003	)		(596,183	)		(114,368	)
Extensions, discoveries and other additions		45,690			79,057			58,866
Improved recovery		-			-			-
Purchase of reserves in-place		113,154			79,359			126,381
Sale of reserves in-place		(1,075	)		(7,047	)		(2,249	)
Production		(24,365	)		(88,472	)		(39,110	)
Ending balance		362,431			468,025			440,435
Proved Developed Reserves, December 31		213,169			388,008			277,837
Proved Undeveloped Reserves, December 31		149,262			80,017			162,598
Entity’s share of equity investee (1)
Proved Reserves
Beginning balance		5,446			47,896			13,428
Revisions of previous estimates		324			4,745			1,115
Extensions, discoveries and other additions		45			4,479			791
Improved recovery		-			-			-
Purchase of reserves in-place		-			-			-
Sale of reserves in-place		(441	)		(4,285	)		(1,155	)
Production		(968	)		(10,016	)		(2,637	)
Ending balance		4,406			42,819			11,542
Proved Developed Reserves, December 31		3,957			31,417			9,193
Proved Undeveloped Reserves, December 31		449			11,402			2,349

Table continued on following page.

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	Oil (MBbl)			Gas (MMcf)			(MBOE)
2011
Consolidated entities
Proved Reserves
Beginning balance		223,268			1,157,070			416,113
Revisions of previous estimates		12,295			(64,972	)		1,466
Extensions, discoveries and other additions		36,436			232,872			75,248
Improved recovery		-			-			-
Purchase of reserves in-place		1,382			17,454			4,291
Sale of reserves in-place		(11,479	)		(229,536	)		(49,735	)
Production		(17,872	)		(111,577	)		(36,468	)
Ending balance		244,030			1,001,311			410,915
Proved Developed Reserves, December 31		151,480			454,248			227,188
Proved Undeveloped Reserves, December 31		92,550			547,063			183,727
Entity’s share of equity investee (1)
Proved Reserves
Beginning balance		4,600			60,828			14,738
Revisions of previous estimates		2,081			829			2,219
Extensions, discoveries and other additions		5			611			107
Improved recovery		-			-			-
Purchase of reserves in-place		-			-			-
Sale of reserves in-place		-			-			-
Production		(1,223	)		(14,220	)		(3,593	)
Ending balance		5,463			48,048			13,471
Proved Developed Reserves, December 31		4,921			39,066			11,432
Proved Undeveloped Reserves, December 31		542			8,982			2,039
2010
Consolidated entities
Proved Reserves
Beginning balance		214,030			873,108			359,548
Revisions of previous estimates		15,299			28,111			19,984
Extensions, discoveries and other additions		10,250			401,288			77,131
Improved recovery		-			-			-
Purchase of reserves in-place		1,260			854			1,403
Sale of reserves in-place		(802	)		(51,244	)		(9,343	)
Production		(16,769	)		(95,047	)		(32,610	)
Ending balance		223,268			1,157,070			416,113
Proved Developed Reserves, December 31		150,492			517,183			236,689
Proved Undeveloped Reserves, December 31		72,776			639,887			179,424
Entity’s share of equity investee (1)
Proved Reserves
Beginning balance		5,028			57,938			14,684
Revisions of previous estimates		204			3,632			809
Extensions, discoveries and other additions		-			-			-
Improved recovery		-			-			-
Purchase of reserves in-place		360			15,091			2,875
Sale of reserves in-place		(72	)		(45	)		(79	)
Production		(804	)		(14,248	)		(3,178	)
Ending balance		4,716			62,368			15,111
Proved Developed Reserves, December 31		4,315			46,974			12,144
Proved Undeveloped Reserves, December 31		401			15,394			2,967

(1) Amounts relate to our equity investment in McMoRan acquired on December 30, 2010.

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Revisions of Previous Estimates

In 2012, we had net negative revisions of 114 MMBOE. Approximately 95 MMBOE, or 83%, of these revisions were related to the continued decline in natural gas prices during 2012, which most significantly impacted our Haynesville Shale and Madden properties.

In 2011, we had net positive revisions of 1 MMBOE. Positive revisions of 21 MMBOE were primarily related to higher realized oil prices principally at our California properties. Negative revisions of 20 MMBOE were mostly related to lower gas prices, primarily at our Panhandle properties prior to the divestment in December 2011.

In 2010, we had net positive revisions of 20 MMBOE. Positive revisions of 8 MMBOE were primarily related to higher realized oil prices principally at our California properties while positive revisions of 12 MMBOE were primarily related to higher realized gas prices principally at our Panhandle, Haynesville Shale and South Texas properties.

Purchases of Reserves in-Place

In 2012, proved reserves acquired in the Gulf of Mexico Acquisition were 126 MMBOE.

In 2011, proved reserves acquired in the Texas Panhandle were 4 MMBOE. These proved reserves were subsequently divested in December 2011.

In 2010, proved reserve additions acquired in the Eagle Ford Shale were 1 MMBOE.

Extensions, Discoveries and Other Additions

In 2012, we had a total of 59 MMBOE of extensions and discoveries, including 42 MMBOE in the Eagle Ford Shale resulting from continued successful drilling during 2012 that extended and developed our proved acreage and 10 MMBOE in the deepwater Gulf of Mexico resulting from successful appraisal drilling in the Lucius oil field.

In 2011, we had a total of 75 MMBOE of extensions and discoveries, including 25 MMBOE in the Haynesville Shale and 22 MMBOE in the Eagle Ford Shale resulting from successful drilling during 2011 that extended and developed our proved acreage and 19 MMBOE in the deepwater Gulf of Mexico resulting from sanctioning of the Lucius project.

In 2010, we had a total of 77 MMBOE of extensions and discoveries, including 54 MMBOE in the Haynesville Shale resulting from successful drilling during 2010 that extended and developed the proved acreage and 17 MMBOE of extensions and discoveries in the Panhandle resulting from successful horizontal development and extension of the proved acreage in the Granite/Atoka Wash.

Sales of Reserves in-Place

In 2012, we had a total of 2 MMBOE of divestments, which were primarily from our Panhandle and East Texas properties.

In 2011, we had a total of 50 MMBOE of divestments, which were primarily from our Panhandle and South Texas properties.

In 2010, we had a total of 9 MMBOE of divestments, all of which were from our shallow water Gulf of Mexico divestment to McMoRan.

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Standardized Measure of Discounted Future Net Cash Flows

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,
	2012			2011			2010
Consolidated entities
Future cash inflows	$	38,584,092		$	29,502,864		$	21,151,315
Future development costs		(4,921,679	)		(4,017,365	)		(3,290,657	)
Future production expense		(11,126,583	)		(9,543,319	)		(7,919,772	)
Future income tax expense		(5,650,467	)		(4,999,822	)		(3,197,758	)
Future net cash flows		16,885,363			10,942,358			6,743,128
Discounted at 10% per year		(6,860,913	)		(5,808,177	)		(3,649,993	)
Standardized measure of discounted future net cash flows	$	10,024,450		$	5,134,181		$	3,093,135
Entity’s share of equity investee (1)
Future cash inflows	$	532,611		$	716,829		$	656,020
Future development costs		(139,101	)		(168,966	)		(192,889	)
Future production expense		(145,938	)		(179,155	)		(165,640	)
Future income tax expense		-			-			-
Future net cash flows		247,572			368,708			297,491
Discounted at 10% per year		(80,524	)		(106,797	)		(86,593	)
Standardized measure of discounted future net cash flows	$	167,048		$	261,911		$	210,898

(1) Amounts relate to our equity investment in McMoRan acquired on December 30, 2010.

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 the twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. These prices 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 use various derivative instruments to manage our exposure to commodity prices. Arrangements in effect at December 31, 2012 are discussed in Note 7 – Commodity Derivative Contracts. The derivative instruments we have in place are not classified as hedges for accounting purposes. The realized sales prices used in the reserve reports as of December 31, 2012, 2011 and 2010 were $103.06, $104.59 and $72.83 per barrel of oil, respectively, and $2.71, $4.08 and $4.29 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 in effect at December 31 of the year presented and held constant throughout the life of the properties.

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, 2012, are as follows (in thousands):

	December 31,
	2012			2011			2010
Consolidated entities
Balance, beginning of year	$	5,134,181		$	3,093,135		$	2,224,839
Sales, net of production expenses		(1,925,912	)		(1,397,901	)		(1,090,465	)
Net change in sales and transfer prices, net of production expenses		1,239,493			3,085,916			2,030,484
Extensions, discoveries and improved recovery, net of costs		1,535,524			959,491			410,973
Changes in estimated future development costs		837,067			(167,533	)		(335,614	)
Previously estimated development costs incurred during the year		631,682			454,778			267,719
Purchase of reserves in-place		5,863,947			82,418			41,214
Sale of reserves in-place		(31,015	)		(594,299	)		(120,082	)
Revision of quantity estimates		(3,091,327	)		38,352			338,683
Accretion of discount		793,732			420,957			273,259
Net change in income taxes		(962,922	)		(841,133	)		(947,875	)
Balance, end of year	$	10,024,450		$	5,134,181		$	3,093,135
Entity’s share of equity investee (1)
Balance, beginning of year	$	261,082		$	205,691
Sales, net of production expenses		(65,608	)		(105,965	)
Changes in prices		(52,461	)		46,514
Discoveries and extensions, less related costs		85			1,881
Changes in estimated future development costs and other		(13,655	)		(34,060	)
Previously estimated development costs incurred during the year		30,716			65,651
Purchase of reserves in-place		-			-
Sale of reserves in-place		(21,701	)		-
Revision of quantity estimates		2,482			61,630
Accretion of discount		26,108			20,569
Net change in income taxes		-			-
Balance, end of year	$	167,048		$	261,911

(1) Amounts relate to our equity investment in McMoRan acquired on December 30, 2010. Our proportionate share of McMoRan’s changes in the standardized measure for the year ended December 31, 2010 is not presented because it is insignificant as PXP owned the investment for one day and it is not practicable to determine one day’s change in the standardized measure.

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