10-K 1 d284806d10k.htm FORM 10-K Form 10-K
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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

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

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

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 $5.3 billion on June 30, 2011 (based on $38.12 per share, the last sale price of the Common Stock as reported on the New York Stock Exchange on such date). On January 31, 2012, there were 128.2 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 2012 Annual Meeting of Stockholders.

 

 

 


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PLAINS EXPLORATION & PRODUCTION COMPANY

2011 ANNUAL REPORT ON FORM 10-K

Table of Contents

 

  Part I   
Items 1 and 2.  

Business and Properties

     9   
Item 1A.  

Risk Factors

     31   
Item 1B.  

Unresolved Staff Comments

     45   
Item 3.  

Legal Proceedings

     45   
Item 4.  

Mine Safety Disclosures

     45   
  Part II   
Item 5.   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities      46   
Item 6.  

Selected Financial Data

     47   
Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations      49   
Item 7A.  

Quantitative and Qualitative Disclosures About Market Risk

     76   
Item 8.  

Financial Statements and Supplementary Data

     79   
Item 9.   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure      79   
Item 9A.  

Controls and Procedures

     80   
Item 9B.  

Other Information

     81   
  Part III   
Item 10.  

Directors, Executive Officers and Corporate Governance

     82   
Item 11.  

Executive Compensation

     84   
Item 12.   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters      84   
Item 13.  

Certain Relationships and Related Transactions, and Director Independence

     84   
Item 14.  

Principal Accounting Fees and Services

     84   
  Part IV   
Item 15.  

Exhibits, Financial Statement Schedules

     85   

 

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Statement Regarding Forward-Looking Statements

This Annual Report on Form 10-K includes forward-looking information regarding Plains Exploration & Production Company (“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:

 

   

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;

 

   

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;

 

   

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. and our ability to dispose of those shares;

 

   

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.

 

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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.

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.

 

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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.

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.

 

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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.

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.

 

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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.

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.

 

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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.

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.

 

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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 Coast Region;

 

   

the Gulf of Mexico; 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 our California, Eagle Ford Shale, Haynesville Shale and Gulf of Mexico plays.

Oil and Gas Reserves

As of December 31, 2011, we had estimated proved reserves of 410.9 million barrels of oil equivalent of which 59% was comprised of oil and 55% was proved developed. We have a total proved reserve life of approximately 12 years and a proved developed reserve life of approximately seven years. As of December 31, 2011, 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 $5.1 billion. As of December 31, 2011, we had estimated probable reserves of 292.1 million barrels of oil equivalent of which 37% was comprised of oil and 2% 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 2011 are based upon (1) reserve reports prepared by the independent petroleum engineers of Netherland, Sewell & Associates, Inc., or 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). In 2009, our proved reserves were based upon reserve reports prepared by NSA and Ryder Scott. The reserve volumes and values were determined using the

 

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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,  
     2011      2010      2009  

Oil and Gas Proved Reserves

        

Consolidated entities

        

Oil (MBbls)

        

Proved developed

     151,480        150,492        144,839  

Proved undeveloped

     92,550        72,776        69,191  
  

 

 

    

 

 

    

 

 

 
     244,030        223,268        214,030  
  

 

 

    

 

 

    

 

 

 

Gas (MMcf)

        

Proved developed

     454,248        517,183        509,121  

Proved undeveloped

     547,063        639,887        363,987  
  

 

 

    

 

 

    

 

 

 
         1,001,311            1,157,070            873,108  
  

 

 

    

 

 

    

 

 

 

MBOE

     410,915        416,113        359,548  
  

 

 

    

 

 

    

 

 

 

Entity’s share of equity investee (1)

        

Oil (MBbls)

        

Proved developed

     4,921        4,315     

Proved undeveloped

     542        401     
  

 

 

    

 

 

    
     5,463        4,716     
  

 

 

    

 

 

    

Gas (MMcf)

        

Proved developed

     39,066        46,974     

Proved undeveloped

     8,982        15,394     
  

 

 

    

 

 

    
     48,048        62,368     
  

 

 

    

 

 

    

MBOE

     13,471        15,111     
  

 

 

    

 

 

    

Table continued on following page.

 

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     As of December 31,  
     2011      2010      2009  

Oil and Gas Probable Reserves (2)

        

Consolidated entities

        

Oil (MBbls)

        

Probable developed (3)

     2,841        

Probable undeveloped

     106,685        
  

 

 

       
     109,526        
  

 

 

       

Gas (MMcf)

        

Probable developed (3)

     14,593        

Probable undeveloped

     1,080,967        
  

 

 

       
     1,095,560        
  

 

 

       

MBOE

     292,119        
  

 

 

       

Standardized Measure (in thousands)

        

Consolidated entities (4)

   $   5,134,181      $   3,093,135      $   2,224,839  
  

 

 

    

 

 

    

 

 

 

Entity’s shares of equity investee (1)

   $ 261,911      $ 210,898     
  

 

 

    

 

 

    

Average Realized Price (5)

        

Oil (per Bbl)

   $ 104.59      $ 72.83      $ 54.38  

Gas (per Mcf)

   $ 4.08      $ 4.29      $ 3.53  

Reference Price (6)

        

Oil (per Bbl)

   $ 95.99      $ 79.43      $ 61.18  

Henry Hub Gas (per MMBtu)

   $ 4.12      $ 4.38      $ 3.87  

Reserve Life (years)

     12.2          13.0          11.2    

 

(1) Amounts relate to our equity investment in McMoRan acquired on December 30, 2010.
(2) 2011 is the first year we have reported probable reserves.
(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 2011 standardized measure includes future development costs related to proved undeveloped reserves of $549 million, $557 million and $690 million in 2012, 2013 and 2014, 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. Recently, however, 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.

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 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 meet the reasonable certainty, economic and other conditions needed to be classified as proved undeveloped reserves but the slower pace of drilling extends the development of these reserves past five years.

 

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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 our proved acreage and 17 MMBOE in the Panhandle resulting from successful horizontal development of the Granite/Atoka Wash. Positive revisions of 20 MMBOE primarily related to higher realized oil and gas prices and proved reserve additions in the Eagle Ford Shale were 1 MMBOE. The divestment of our Gulf of Mexico shallow water shelf properties resulted in a 9 MMBOE reduction.

During the three-year period ended December 31, 2011, we participated in 977 exploratory wells, of which 960 were successful, and 420 development wells, of which 416 were successful. During this period, we incurred aggregate oil and gas acquisition, exploration and development costs of $6.4 billion, approximately half of which was for acquisition and development activities. During this period, proved reserve additions from acquisitions, extensions and discoveries totaled 217 MMBOE.

All of our proved undeveloped reserves are scheduled for development within five years. As of December 31, 2011, we had proved undeveloped reserves of 184 MMBOE, a net increase of 5 MMBOE relative to December 31, 2010. Additions to proved undeveloped reserves resulted primarily from continued successful development of our Lucius oil field, Arroyo Grande and the Eagle Ford Shale. During 2011, we invested $316.2 million and converted 29 MMBOE, or 16% of our year-end 2010 proved undeveloped reserve balance, to proved developed. The pace of development was heavily influenced by the large number of unproved locations that were drilled on our Haynesville Shale and 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 estimates 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 relate to undeveloped locations that are expected to be developed beyond five years but would otherwise meet 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 22 and 35 years of industry experience, between 12 and 35 years of reservoir engineering/management experience, and between six and ten 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.

 

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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.

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 senior revolving credit facility.

Divestments

Panhandle and South Texas Properties

In December 2011, we completed the divestment of 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. At December 31, 2011, we continue to have interests in approximately 50,000 gross leasehold acres. We expect to receive additional proceeds from future closings, as may be further modified for additional post-closing adjustments. 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. The transaction was effective November 1, 2011.

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 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 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.

 

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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 and by building future development projects through exploration primarily in the Gulf of Mexico, California and liquids rich resource plays such as the Eagle Ford Shale. 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 and enhance our proved reserves and thereby increase cash flows and enhance the value of our asset base. During the three-year period ended December 31, 2011, our additions to proved reserves from extensions and discoveries totaled 210 MMBOE. During this period, we incurred aggregate oil and gas development and exploration costs of $4.5 billion.

Our 2012 capital budget is approximately $1.6 billion, including capitalized interest and general and administrative expenses, and is focused on our major development and exploration areas. Our resources will be primarily directed to the Eagle Ford Shale, California, Gulf of Mexico and the Haynesville Shale. We continue to aggressively manage our inventory, our cost structure and our financial flexibility.

Description of Properties

Our oil and gas operations are concentrated onshore California, offshore California, the Gulf Coast Region, the Gulf of Mexico 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 base properties in California, the Eagle Ford Shale, the Gulf of Mexico and the Haynesville Shale. Also, we have continued exploration primarily in the Gulf of Mexico, California and liquids rich resource plays such as the Eagle Ford Shale. Capital additions to our oil and gas properties were $1.9 billion in 2011.

 

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The following table sets forth information with respect to our proved and probable oil and gas reserves as of December 31, 2011:

 

    As of December 31, 2011  
    Proved Reserves     Probable Reserves  
    Proved
Developed
    Proved
Undeveloped
    Total
Proved
    Probable
Developed (1 )
    Probable
Undeveloped
    Total
Probable
 
    (MMBOE)  

Consolidated entities

           

Onshore California

    135.0       68.9       203.9       2.9       90.2       93.1   

Offshore California

    13.5       -          13.5       -          3.4       3.4   

Gulf Coast Region and Gulf of Mexico

    51.8       114.3       166.1       -          193.2       193.2   

Rocky Mountains and Other

    26.9       0.5       27.4       2.4       -          2.4   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

              227.2                 183.7                 410.9                 5.3                 286.8               292.1   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Entity’s share of equity investee (2 )

    11.4       2.1       13.5        
 

 

 

   

 

 

   

 

 

       

 

(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 (18 to 29 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 2011, we spent $105 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 39 wells, including two injector wells. Our net average daily LA Basin sales volumes were 11.2 MBOE per day in the fourth quarter of 2011. In 2012, we will continue to concentrate on development drilling and on recompletion projects in the LA Basin.

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 $116 million in 2011 on capital projects in the San Joaquin Basin focused on improved recovery efficiency through infill drilling, well recompletions, facility expansions and enhancements to reduce air emissions in all of our primary fields. During 2011, we drilled 146 wells, including 27 injector wells, in the San Joaquin Basin. Our net average daily San Joaquin Basin sales volumes were 19.3 MBOE per day in the fourth quarter of 2011.

 

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We continue to evaluate our exposure to the previously announced positive industry discoveries in Kern County, California. We hold approximately 16,000 net acres in the Kern County area. In 2012, we will continue to concentrate on development drilling and on recompletion projects and facility expansions in the San Joaquin Basin. Additionally, we are participating in the acquisition of 3-D seismic over a significant portion of our acreage and are 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 2011, we spent $63 million on capital projects in this field focused on improved recovery efficiency primarily through facility enhancements and recompletion projects. Our net average daily sales volumes from the Arroyo Grande Field were 1.0 MBOE per day in the fourth quarter of 2011.

Construction of a produced water reclamation facility is underway. Upon completion of the facility in mid-2013, 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.

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 in the fourth quarter of 2011 were 2.8 MBOE per day.

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 5.7 MBOE per day in the fourth quarter of 2011. In 2011, we spent $25 million on capital projects primarily associated with equipment improvements, including a significant platform upgrade associated with capacity expansion to accommodate the drilling of additional wells. During 2012, we plan to drill additional extended reach Monterey wells in this area and continue our focus on plug back recompletions to maintain production.

Gulf Coast Region

Eagle Ford Shale

At December 31, 2011, we own interests in oil and gas properties on approximately 89,000 gross acres (60,000 net acres) with 255 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 2011 were 9.1 MBOE per day, an increase of greater than 300% from the 2.2 MBOE per day net average during the first quarter of 2011.

 

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We spent $502 million of capital in 2011 focused on continued development drilling and the completion of seven production facilities. At December 31, 2011, we had seven rigs drilling horizontal development wells on our acreage. For 2012, we allocated approximately $655 million of our capital budget to Eagle Ford Shale activity and plan to focus on development drilling and the completion of 12 additional production facilities, including two existing facilities modified to bring on additional wells. During 2012, we plan to have nine to 11 rigs drilling horizontal development wells on our acreage.

Haynesville Shale

As of December 31, 2011, we have rights to approximately 432,000 gross acres (84,000 net acres) in the Haynesville Shale that we acquired from Chesapeake Energy Corporation, including approximately 54,000 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 is currently being 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. During 2011, 2010 and 2009, we spent $14 million, $16 million and $59 million, respectively, to acquire approximately 1,100, 1,200 and 5,000 net additional acres, respectively, in the Haynesville Shale. During 2011, we divested 3,000 net acres and released 20,200 net acres that were deemed to be outside of our primary focus area.

Our net average daily sales volumes during the fourth quarter of 2011 were 199.8 MMcfe per day, a 23% increase from the 161.9 MMcfe per day net average during the first quarter of 2011. The rate of increase in sales volumes is expected to slow as the rig count continues to decline.

We spent $363 million of capital in 2011 focused on converting undeveloped leases to leases held by production. For 2012, we allocated approximately $140 million of our capital budget to Haynesville Shale activity and plan to continue to focus on the development of our undeveloped leasehold and improved recovery efficiency through infill drilling.

Deepwater Gulf of Mexico

Our deepwater Gulf of Mexico portfolio is anchored by Lucius, a high-quality oil discovery, and a comprehensive exploration portfolio with interests in 102 blocks containing 29 prospects or leads in Pliocene, Miocene and lower Tertiary reservoirs.

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 Operations Inc., or Plains Offshore, a former wholly owned subsidiary. Plains Offshore holds all 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. The proceeds raised are expected to be used to fund Plains Offshore’s share of capital investment in the Lucius oil field and the Phobos prospect exploratory drilling planned for 2012 and other activities. 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.

 

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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 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 developed with a truss spar floating production facility with the capacity to produce in excess of 80 MBbl per day and 450 MMcfe per day. The development drilling program is expected to begin in 2012 with achievement of first production anticipated in 2014.

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.

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 Deep Unit 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 carbon dioxide and hydrogen sulfide. Our net average daily sales volumes during the fourth quarter of 2011 were 27.2 MMcfe from the Wind River Basin.

During 2011, we spent $5 million on capital projects in the Madden Deep Unit. After completion of repair work following a fire in 2010 that affected a portion of the Lost Cabin Gas Plant, production was back to full capacity during the first quarter of 2011. In 2012, we are focused on maintaining production and high-grading the remaining development drilling inventory.

Big Horn Basin

We hold leases covering 126,000 gross acres (111,000 net acres) in the Big Horn Basin located in Wyoming. We drilled two wells in 2011 that tested high-quality oil in small quantities. During 2012, we plan to monitor industry activity in this play.

 

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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,  
     2011      2010      2009  

Consolidated entities

        

Property acquisition costs

        

Unproved properties

   $ 36,562       $ 612,471      $ 1,121,644   

Proved properties

     9,236         48,078        5,072   

Exploration costs

     1,147,858         719,004        1,309,396   

Development costs

     708,519         363,242        272,820   
  

 

 

    

 

 

    

 

 

 
   $     1,902,175       $     1,742,795      $     2,708,932   
  

 

 

    

 

 

    

 

 

 

Entity’s share of equity investee (1)

        

Property acquisition costs

        

Unproved properties

   $ 15,523         

Proved properties

     -           

Exploration costs

     175,802         

Development costs

     17,190         
  

 

 

       
   $     208,515         
  

 

 

       

 

(1) 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.

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, 2011, 2010 and 2009.

 

    

Inglewood (1)

     Haynesville
Shale (1)
    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 (1)     Haynesville
Shale (1)
    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   

2009

        

Oil and liquids sales (MBbls)

     2,407        -          15,153        17,560   

Gas (MMcf)

        

Production

     1,013        15,176        61,995        78,184   

Used as fuel

     21        -          2,337        2,358   

Sales

     992          15,176          59,658          75,826   

MBOE

        

Production

     2,576        2,529        25,486        30,591   

Sales

     2,572        2,529        25,097        30,198   

Average realized sales price before derivative transactions (2)

        

Oil (per Bbl)

   $ 51.91      $ -        $ 51.36      $ 51.43   

Gas (per Mcf)

     3.72        3.50        3.77        3.72   

Per BOE

     50.01        21.01        39.98        39.25   

Average production cost per BOE (3)

        

Lease operating expenses

   $ 14.20      $ 0.96      $ 8.44      $ 8.31   

Steam gas costs

     -          -          2.14        1.78   

Electricity

     6.38        -          1.10        1.45   

Gathering and transportation

     0.11        4.70        0.98        1.21   

 

  (1) 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.
  (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.

 

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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 and collar contracts and natural gas put option, collar and swap contracts entered into with financial institutions.

A substantial portion of our oil reserves are located in California and approximately 56% 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.

Our heavy crude is primarily sold to ConocoPhillips. In August 2011, we replaced our previous contract with a new marketing contract with ConocoPhillips effective January 1, 2012 that covers approximately 90% of our California production, extends the dedication from January 1, 2015 to January 1, 2023 and replaces the percent of NYMEX index pricing mechanism with a market-based pricing approach. During 2011, we received approximately 89% of the NYMEX index price for crude oil sold under the ConocoPhillips contract, which represented approximately 50% of our total crude oil production. Separately, we executed an agreement with a third party purchaser to sell a large portion of our Eagle Ford Shale crude oil using a Light Louisiana Sweet based pricing mechanism. Due to these new marketing contracts, we expect oil price realizations on a significant portion of our crude oil production to increase relative to WTI beginning in 2012.

Approximately 20% of our 2011 crude oil production was sold under contracts that provide for NYMEX less a fixed price differential (as of December 31, 2011 the fixed price differential averaged $4.66 per barrel) with the remainder sold under contracts that provide for monthly field posted prices.

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.

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 2011, 2010 and 2009, sales to ConocoPhillips accounted for 41%, 57% and 44%, respectively, of our total revenues. During 2011, sales to Tesoro Corporation and Valero Energy Corporation accounted for 13% and 11%, respectively, of our total revenues. 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. During 2009, sales to Plains Marketing, L.P., or PMLP, accounted for 22% of our total revenues. The contract with PMLP expired in November 2009, and we entered into contracts with purchasers who previously purchased through PMLP, the most significant of which was ConocoPhillips. During 2011, 2010 and 2009, no other purchaser accounted for more than 10% of our total revenues. The loss of any single significant customer or contract could have a material adverse short-term effect; however, we do not believe that the loss of any single significant customer or contract would materially affect our business in the long-term. We believe such purchasers could be replaced by other purchasers under contracts with similar terms and conditions. However, their role as the purchaser of a significant portion of our oil production does have the potential to impact our overall exposure to credit risk, either positively or negatively, in that they may be affected by changes in economic, industry or other conditions. We 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 a 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. 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.

Acreage

The following table sets forth information with respect to our developed and undeveloped acreage as of December 31, 2011:

 

     Developed Acres      Undeveloped Acres (1)  
     Gross      Net      Gross      Net  

California

           

Onshore

     61,311        60,734        50,208        34,234   

Offshore

     43,335        39,062        -           -     

Louisiana

           

Onshore

     282,560        55,060        103,325        20,134   

Offshore

     5,670        1,323        567,947        189,286   

Nevada

     -           -           217,431        217,431   

Texas

     116,481        72,230        103,959        50,511   

Utah

     -           -           65,871        34,346   

Wyoming

     72,340        14,342        200,132        174,105   

Other states (2)

     2,884        316        9,387        7,050   
  

 

 

    

 

 

    

 

 

    

 

 

 
     584,581        243,067        1,318,260        727,097   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Approximately 21% of our total net undeveloped acres is covered by leases that expire from 2012 to 2014.
(2) Other states include Arkansas, Illinois, Kansas, Mississippi and Montana.

 

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Productive Wells

As of December 31, 2011, we had working interests in 3,190 gross (2,879 net) active producing oil wells and 1,423 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, 2011, we owned an interest in two gross wells containing multiple completions.

Drilling Activities

The number of oil and gas wells completed during the years ended December 31, 2011, 2010 and 2009 is set forth below:

 

     Year Ended December 31,  
     2011      2010      2009  
     Gross      Net      Gross      Net      Gross      Net  

Exploratory Wells (1)

                 

Oil

     36.0        27.6        6.0        3.1        1.0        1.0  

Gas

     443.0        42.7        318.0        38.3        156.0        19.6  

Dry

     3.0        -           4.0        2.2        10.0        6.6  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     482.0        70.3        328.0        43.6        167.0        27.2  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Development Wells

                 

Oil

     192.0        165.2        109.0        106.4        16.0        12.7  

Gas

     67.0        22.5        8.0        2.7        24.0        12.4  

Dry

     2.0        1.9        1.0        1.0        1.0        0.2  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     261.0        189.6        118.0        110.1        41.0        25.3  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     743.0        259.9        446.0        153.7        208.0        52.5  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Includes extension wells.

At December 31, 2011, there were 148 gross exploratory and 37 gross development wells (34.1 net exploratory and 6.5 net development wells) in progress including 147 wells in the Haynesville Shale area where we had approximately 29 rigs actively drilling horizontal wells at year-end. We had 35 wells in progress in the Eagle Ford Shale where we had seven rigs actively drilling horizontal wells at year-end.

Investment

At December 31, 2011 and 2010, we owned 51.0 million shares of McMoRan common stock, approximately 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 Items 1 and 2 – Business and Properties – Divestments.

 

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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. Under the terms of the registration rights agreement, McMoRan filed a registration statement covering the McMoRan shares within 60 days after closing. The registration rights agreement also 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 and from transferring any McMoRan shares for one year after closing (subject to certain exceptions). The one year restriction ended on December 30, 2011, and we may now 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.

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 will be responsible for creating a development plan and obtaining all necessary permits for real estate development in an environmentally responsible manner on the surface estates of our properties listed above. Cook Hill Properties is a 15% participant in the venture and can earn an additional incentive on each property.

During 2011, 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.

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 2011, we spent approximately $4 million on our real estate projects.

 

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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 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, 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.

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. However, upon our contribution of the properties to Plains Offshore, as a lessee in the deepwater U.S. Gulf of Mexico, Plains Offshore must also comply with the regulations. 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) supplemental bonding, which is required to be provided by all lessees and specifically covers the plugging and abandonment obligations associated with a lease, and (ii) 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 could be substantial and there is no assurance that bonds or other surety could be obtained in all cases.

 

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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 make 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 the 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 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 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.

 

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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 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, Oil Pollution Act 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 (regardless of who caused it), 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.

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 due later in 2012. Some of our facilities are subject to these 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 Global Warming Solutions Act of 2006 (Assembly Bill 32) requires the California Air Resources Board to establish and adopt regulations by 2012 that will achieve an overall reduction in greenhouse gas emissions from all sources in California of 25% by 2020. In October 2011, the California Air Resources Board, or CARB, adopted the final cap and trade regulation, including a delay in the start of the cap and trade rule’s compliance obligations until 2013. Because our operations emit greenhouse gases, our operations in California are subject to regulations issued under the California Global Warming Solutions Act of 2006, or Assembly Bill 32. These regulations increase our costs for those operations and adversely affect our operating results.

Depending on the particular program, we could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from our operations or from combustion of crude oil or natural gas we produce. Although we would not be impacted to a greater degree than other similarly situated oil and gas companies, a stringent greenhouse gas control program could significantly increase our cost of doing business and could also reduce demand for the oil and natural gas we produce.

 

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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.

Hydraulic Fracturing.    Our operations utilize the practice of hydraulic fracturing for new oil and natural gas wells. The practice of hydraulic fracturing continues to receive significant regulatory and legislative attention at the federal, state, and local level. Several federal agencies including the EPA and the U.S. Bureau of Land Management are reviewing current regulations related to the practice of hydraulic fracturing and are considering adopting additional regulations in the future. From time to time, legislation has been introduced in Congress to amend the federal SDWA to eliminate exemptions for most fracturing activities. Similar efforts to review the practice and impose new regulatory conditions are taking place at the state and local level in states where we operate, several of which have adopted or are considering new regulations and statutes. 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. Although we would not be impacted to a greater degree than other similarly situated oil and gas companies, the imposition of stringent new regulatory and permitting requirements related to the practice of hydraulic fracturing could significantly increase our cost of doing business and create adverse effect on our operations.

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, 2012, we had 880 full-time employees, 331 of whom were field personnel involved in oil and gas producing activities. We believe our relationship with our employees is good.

 

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Item 1A. Risk Factors

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

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

Our success is largely dependent on oil and gas prices, which are extremely volatile. Any substantial or extended decline in the price of oil and gas below current levels will have a negative impact on our business operations and future revenues. Moreover, oil and gas prices depend on factors we cannot control, such as:

 

   

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

 

   

weather;

 

   

actions by 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.

 

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

 

   

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

 

   

the assumed effects of regulations by governmental agencies;

 

   

assumptions concerning future oil and gas prices; and

 

   

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.

 

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Oil and natural gas prices have the potential to be volatile. As of February 2012, the twelve-month average of the first-day-of-the-month reference price for natural gas has declined from $4.12 per MMBtu at year-end 2011 to $3.86 per MMBtu, while the comparable price for oil has increased from $95.99 per Bbl at year-end 2011 to $97.28 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 senior revolving credit facility. 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.

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. 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 31.6% of the outstanding shares of common stock of McMoRan as of December 31, 2011. We may sell shares of McMoRan common stock pursuant to underwritten offerings, in periodic sales under a shelf registration statement to be filed by McMoRan (subject to certain volume limitations), pursuant to the exercise of piggyback registration rights or as otherwise permitted by applicable law. Our ability to sell shares of McMoRan common stock could be severely limited, both as to timing and amount, and as a result of factors beyond our control. In addition, the market price of shares of McMoRan common stock that we hold may decline substantially before we sell them.

 

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We do not control McMoRan’s assets and operations and the value of our investment in McMoRan’s common stock is 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;

 

   

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, 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.

 

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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 the derivative agreement. 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.

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.

Potential regulations regarding derivatives 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 Dodd-Frank Act. The Dodd-Frank Act creates a new regulatory framework for oversight of derivatives transactions by the Commodity Futures Trading Commission, or CFTC, and the SEC. Among other things, the Dodd-Frank Act subjects certain swap participants to new capital, margin and business conduct standards. In addition, the Dodd-Frank Act 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. There are some exceptions to these requirements for entities that use swaps to hedge or mitigate commercial risk. While we may qualify for one or more of such exceptions, the scope of these exceptions is uncertain and will be further defined through rulemaking proceedings at the CFTC and SEC in the coming months. Further, although we may qualify for exceptions, our derivatives counterparties may be subject to new capital, margin and business conduct requirements imposed as a result of the new legislation, which may increase our transaction costs or make it more difficult for us to enter into hedging transactions on favorable terms. 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.

 

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

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

 

   

hurricanes and other adverse weather conditions;

 

   

oil field service costs and availability;

 

   

compliance with environmental and other laws and regulations;

 

   

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

 

   

failure of equipment or facilities.

We are currently conducting some of our exploration in the deeper waters of the Gulf of Mexico, where operations are more difficult and costly than in shallower waters. The deeper waters in the Gulf of Mexico lack the physical and oilfield service infrastructure present in its shallower waters. 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.

Our operations in the Gulf of Mexico and offshore California could be adversely impacted by the Macondo accident and resulting oil spill.

The six-month moratorium on the drilling of new deepwater wells and a suspension of permitted wells being drilled in the Outer Continental Shelf regions of the Gulf of Mexico and Pacific Ocean was conditionally lifted in October 2010. Notwithstanding the lifting of the moratorium some permits have been issued, but at a much slower rate than before the Macondo accident.

We have offshore exploration, development and production ongoing in the Gulf of Mexico and California. 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, as well as changes in the availability and cost of insurance.

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 have entered into an oil marketing arrangement with ConocoPhillips under which ConocoPhillips 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 their financial condition could adversely impact our ability to collect the applicable receivables, and thereby affect our financial condition.

 

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

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

 

   

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 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;

 

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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.

During 2011, there was significant volatility within the global economy, particularly in certain countries of the European Union. Should this financial concern continue to cause disruption, it may negatively impact stock price and credit capacity for certain issuers, even those without exposure to the affected countries.

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 amount up to the aggregate amount of such lender’s commitment under our credit facilities. The commitments under our senior revolving credit facility and the Plains Offshore senior credit facility are from a diverse syndicate of 21 lenders. At December 31, 2011, 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.

 

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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 2011, the twelve-month average of the first-day-of-the-month reference prices (prior to adjustment for location and quality differentials) were $95.99 per Bbl for oil and $4.12 per MMBtu for natural gas. At December 31, 2011, the ceiling with respect to our domestic oil and gas properties exceeded the net capitalized costs of those properties by approximately 30%.

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 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 Assembly Bill 32 requires the CARB to establish and adopt regulations by 2012 that will achieve an overall reduction in greenhouse gas emissions from all sources in California of 25% by 2020. In October 2011, the CARB adopted the final cap and trade regulation, including a delay in the start of the cap and trade rule’s compliance obligations until 2013.

 

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Because our operations emit greenhouse gases, our operations in California are subject to regulations issued under Assembly Bill 32. 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 Oil Pollution Act of 1990; and

 

   

controlling air, water and waste emissions.

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

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

Some of our onshore California fields have been in operation for more than 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.

 

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

From time to time, legislation has been introduced in Congress to amend the federal SDWA to eliminate exemptions for most fracturing activities. Similar efforts to review the practice and impose new regulatory conditions are taking place at the state and local level in states where we operate, several of which have adopted or are considering new regulations and statutes. 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. 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 and adversely affect our operations.

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, 2011, we had leases on approximately 84,000 net acres in the Haynesville Shale area and approximately 60,000 net acres in the Eagle Ford Shale area. Over 85% of our acreage in the Haynesville Shale and over 25% 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, 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 the Haynesville Shale acreage and portions of the Eagle Ford Shale acreage, we have limited impact upon the drilling schedule for those leases.

Increased drilling in the Eagle Ford Shale may cause pipeline and gathering system capacity constraints that could limit our ability to sell our oil and gas.

Because of the current economic climate, certain pipeline projects that are planned for the Haynesville Shale and the Eagle Ford Shale may not occur because the prospective owners of these pipelines may be unable to secure the necessary financing. In such event, this could result in wells being shut-in awaiting a pipeline connection or capacity and/or gas being sold at much lower prices than those quoted on the NYMEX or than we currently project, which would adversely affect our results of operations.

 

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

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

 

   

diversion of management’s attention;

 

   

the need to integrate acquired operations;

 

   

potential loss of key employees of the acquired companies;

 

   

difficulty in assessing recoverable reserves, exploration potential, future production rates, operating costs, infrastructure requirements, future oil and natural gas prices, environmental and other liabilities, and other factors beyond our control;

 

   

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

 

   

an increase in our expenses and working capital requirements.

Assessments associated with an acquisition are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every oil and gas well or the facilities associated with those wells. Even when we perform inspections, we do not always discover structural, subsurface and environmental problems that may exist or arise. As a result of these factors, the purchase price we pay to acquire oil and gas properties may exceed the value we realize.

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

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

In a purchase transaction, goodwill represents the excess of the purchase price plus the liabilities assumed (including deferred income taxes recorded in connection with the transaction) over the fair value of the net assets acquired. At December 31, 2011, goodwill totaled $535 million and represented approximately 5% 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.

 

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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. Some companies 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 contained in the Obama Administration’s Fiscal Year 2013 budget proposal, released by the Office of Management and Budget on February 13, 2012, 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 include, but are not 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 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 legislation that has recently 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 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 and portions of our Eagle Ford Shale acreage, 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. 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.

 

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Item 1B.  Unresolved Staff Comments

Not applicable.

 

Item 3.  Legal Proceedings

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

 

Item 4.  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      

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  

2010

     

1st Quarter

   $ 36.60      $ 28.09  

2nd Quarter

     35.21        19.28  

3rd Quarter

     27.34        19.54  

4th Quarter

     32.75        25.63  

At January 31, 2012, we had approximately 2,338 shareholders of record.

Dividend Policy

We have not paid any cash dividends and do not anticipate declaring or paying any cash dividends in the future. We intend to retain our earnings to finance the expansion of our business, repurchase shares of our common stock and for general corporate purposes. Our Board of Directors 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 senior revolving credit facility 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. The following is a summary of our repurchases of common stock during the three-month period ended December 31, 2011 under this plan:

 

Period

   Total Number
of Shares
Purchased
     Average
Price Paid
Per Share
     Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs
     Approximate Dollar
Value of Shares that
May Yet Be Purchased
Under the Plans or
Programs
 
     (in thousands, except per share data)  

December 1 to December 31, 2011

     10,415      $     34.73        10,415      $     334,079  

In addition, we repurchased an additional 2,390 shares in January 2012. 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, 2011 and 2010 and the related consolidated statements of income and cash flows for each of the three years in the period ended December 31, 2011 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,  
     2011 (1)     2010 (2)     2009     2008 (3)     2007 (4)  

Income Statement Data

          

Revenues

      $ 1,964,488         $ 1,544,595         $   1,187,130         $ 2,403,471         $   1,272,840   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Costs and Expenses

          

Production costs

     558,975        451,902        423,967        626,428        413,122   

General and administrative

     134,044        136,437        144,586        153,306        124,006   

Depreciation, depletion, amortization
and accretion

  

 

681,655

  

 

 

551,118

  

 

 

421,580

  

 

 

621,484

  

 

 

316,078

  

Impairment of oil and gas properties (5)

     -          59,475        -          3,629,666        -     

Legal recovery

     -          (8,423 )       (87,272 )       -          -     

Other operating (income) expense

     (735 )       (4,130 )       2,136        -          -     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
     1,373,939         1,186,379         904,997         5,030,884          853,206     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (Loss) from Operations

     590,549         358,216        282,133        (2,627,413     419,634   

Other Income (Expense)

          

Gain on sale of assets (6)

     -          -          -          65,689        -     

Interest expense

     (161,316     (106,713     (73,811     (116,991     (68,908

Debt extinguishment costs (7)

     (120,954     (1,189 )       (12,093 )       (18,256 )       -     

Gain (loss) on mark-to-market
derivative contracts (8)

  

 

81,981

  

 

 

(60,695

 

 

(7,017

 

 

1,555,917

  

 

 

(88,549

Loss on investment measured at
fair value (9)

     (52,675     (1,551     -          -          -     

Other income (expense)

     3,356        15,942        27,968        (12,575 )       6,322   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (Loss) Before Income Taxes

     340,941        204,010        217,180        (1,153,629 )       268,499   

Income tax benefit (expense)

          

Current

     25,952        93,090        (45,091 )       (230,815 )       4,677   

Deferred

     (160,214 )       (193,835 )       (35,784 )       675,350        (114,425 )  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Income (Loss)

     206,679         $ 103,265         $ 136,305         $ (709,094      $ 158,751   
    

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to noncontrolling
interest in the form of preferred stock of subsidiary

     (1,400        
  

 

 

         

Net Income Attributable to
Common Stockholders

     $ 205,279            
  

 

 

         

Earnings (Loss) per Common Share

          

Basic

      $ 1.45         $ 0.74         $ 1.10         $ (6.52 )        $ 2.02   

Diluted

      $ 1.44         $ 0.73         $ 1.09         $ (6.52 )        $ 1.99   

Weighted Average Common
Shares Outstanding

          

Basic

     141,227        140,438        124,405        108,828        78,627   

Diluted

     142,999        141,897        125,288        108,828        79,808   

 

Table continued on following page.

 

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Table of Contents
    Year Ended December 31,  
    2011 (1)     2010 (2)     2009     2008 (3)     2007 (4)  

Cash Flow Data

         

Net cash provided by operating
activities

  $ 1,110,755      $ 912,470      $ 499,046      $ 1,371,409      $ 588,112   

Net cash used in investing activities

    (1,154,591     (1,575,308     (1,280,399     (227,790     (2,243,137

Net cash provided by (used in) financing activities

    456,500        667,413        471,337        (857,190     1,679,572   
    As of December 31,  
    2011 (1)     2010 (2)     2009     2008 (3)     2007 (4)  
Balance Sheet Data                              
Assets          

Cash and cash equivalents

  $ 419,098      $ 6,434      $ 1,859      $ 311,875      $ 25,446   

Other current assets

    1,022,279        396,453        304,776        1,164,566        649,474   

Property and equipment, net

    7,725,295        7,220,752        6,832,722        4,513,396        8,377,227   

Goodwill

    535,140        535,144        535,237        535,265        536,822   

Investment (9)

    -          664,346        -          -          -     

Other assets

    89,660        71,808        60,137        586,813        104,382   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
  $ 9,791,472      $ 8,894,937      $ 7,734,731      $ 7,111,915      $ 9,693,351   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Liabilities and Equity

         

Current liabilities

  $ 626,186      $ 533,689      $ 682,551      $ 993,645      $ 818,046   

Long-term debt

    3,760,952        3,344,717        2,649,689        2,805,000        3,305,000   

Other long-term liabilities

    247,205        278,516        269,762        191,534        272,627   

Deferred income taxes

    1,461,897        1,355,050        933,748        744,456        1,959,431   

Stockholders’ equity

    3,264,636        3,382,965        3,198,981        2,377,280        3,338,247   

Noncontrolling interest
Preferred stock of subsidiary

    430,596        -          -          -          -     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
  $  9,791,472      $ 8,894,937      $ 7,734,731      $ 7,111,915      $ 9,693,351   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

  (1) Reflects the December 2011 divestiture of interests in our Texas Panhandle and South Texas conventional natural gas properties.
  (2) 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.
  (3) 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.
  (4) Reflects the acquisition of Pogo Producing Company effective November 6, 2007 and the Piceance Basin properties effective May 31, 2007.
  (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) In December 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, 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 Coast Region;

 

   

the Gulf of Mexico; 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 our California, Eagle Ford Shale, Haynesville Shale and Gulf of Mexico plays. As of December 31, 2011, we had estimated proved reserves of 410.9 MMBOE, of which 59% was comprised of oil and 55% was proved developed. Our primary sources of liquidity are cash generated from our operations, our senior revolving credit facility and periodic public offerings of debt and equity.

Our assets include 51.0 million shares of McMoRan common stock, approximately 31.6% 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 agreements and subjects us to the credit risk of the counterparties to such agreements. 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

Divestments

In December 2011, we completed the divestment of 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. At December 31, 2011, we continue to have interests in approximately 50,000 gross leasehold acres. We expect to receive additional proceeds from future closings, as may be further modified for additional post-closing adjustments. 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. The transaction was effective November 1, 2011.

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

Gulf of Mexico

In October 2011, we entered into a securities purchase agreement with 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 all 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. The proceeds raised are expected to be used to fund Plains Offshore’s share of capital investment in the Lucius oil field and the Phobos prospect exploratory drilling planned for 2012 and other activities. Under the agreement and upon closing of the transaction, Plains Offshore issued to 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 will pay 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. 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. PXP guarantees the Plains Offshore senior credit facility.

 

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Table of Contents

Debt Offering and Tender Offers

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 senior revolving credit facility and for general corporate purposes.

In December 2011, we made payments totaling approximately $1.4 billion, including premiums, to retire $520.7 million of the $600 million outstanding principal amount of our 7 3/4% Senior Notes due 2015, or the 7 3/4% Senior Notes, $380.1 million of the $565 million outstanding principal amount of our 10% Senior Notes due 2016, or the 10% Senior Notes, and $423.1 million of the $500 million outstanding principal amount of our 7% Senior Notes due 2017, or the 7% Senior Notes. In connection with the retirement of the 7 3/4% Senior Notes, 10% Senior Notes and 7% Senior Notes, we recorded $121.0 million of debt extinguishment costs.

Derivatives

In December 2011, we entered into natural gas swap contracts, at an average price of $4.27 per MMBtu, on 110,000 MMBtu per day for 2013.

During the period from January 1, 2012 through February 22, 2012, we converted 5,000 of the 22,000 BOPD of Brent crude oil put option contracts in 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 eliminates approximately $11 million of deferred premiums. Additionally, we entered into the following Brent oil derivatives for 2013 and 2014:

 

   

Brent crude oil put option spread contracts on 13,000 BPOD for 2013 with a floor price of $100 per barrel and a limit of $80 per barrel.

 

   

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

 

   

Brent crude oil put option spread contracts on 20,000 BOPD for 2014 with a floor price of $90 per barrel and a limit of $70 per barrel.

In February 2012, we entered into natural gas swap contracts, at an average price of $4.16 per MMBtu, on 70,000 MMBtu per day for 2014.

Stock Repurchase Program

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.

In January 2012, we completed the purchase of an additional 2.4 million common shares at an average cost of $37.02 per share totaling $88.5 million. Subsequent to those purchases, 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.

 

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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, 2011, the ceiling with respect to our domestic oil and gas properties exceeded the net capitalized costs of those properties by approximately 30%.

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, 2011, we reported net income attributable to common stockholders of $205.3 million, on total revenues of $2.0 billion. This compares to net income of $103.3 million, on total revenues of $1.5 billion for the year ended December 31, 2010, and net income of $136.3 million, on total revenues of $1.2 billion for the year ended December 31, 2009.

Significant transactions that affect comparisons between the periods include 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,  
     2011      2010      2009  

Sales Volumes

        

Oil and liquids sales (MBbls)

     17,872        16,769        17,560  

Gas (MMcf)

        

Production

     111,577        95,047        78,184  

Used as fuel

     2,108        1,954        2,358  

Sales

     109,469        93,093        75,826  

MBOE

        

Production

     36,468        32,610        30,591  

Sales

     36,117        32,285        30,198  

Daily Average Volumes

        

Oil and liquids sales (Bbls)

     48,964        45,943        48,110  

Gas (Mcf)

        

Production

     305,691        260,402        214,203  

Used as fuel

     5,776        5,353        6,461  

Sales

     299,915        255,049        207,742  

BOE

        

Production

     99,912        89,343        83,811  

Sales

     98,950        88,451        82,734  

Unit Economics (in dollars)

        

Average NYMEX Prices

        

Oil

   $ 95.11      $ 79.61      $ 62.09  

Gas

     4.04        4.38        3.97  

Average Realized Sales Price

        

Before Derivative Transactions

        

Oil (per Bbl)

   $ 85.53      $ 68.14      $ 51.43  

Gas (per Mcf)

     3.91        4.29        3.72  

Per BOE

     54.18        47.77        39.25  

Costs and Expenses per BOE
Production costs

        

Lease operating expenses

   $ 9.27      $ 8.13      $ 8.31  

Steam gas costs

     1.81        2.06        1.78  

Electricity

     1.14        1.33        1.45  

Production and ad valorem taxes

     1.53        0.91        1.28  

Gathering and transportation

     1.72        1.57        1.21  

DD&A (oil and gas properties)

     17.76        15.87        12.79  

 

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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,  
     2011     2010     2009  

Oil derivatives

      

Settlements

   $ (60,392   $ (67,917   $ 141,297  

Unwind of crude oil puts, swaps and collars

     (2,935     -          1,074,361  

Natural gas derivatives

     7,915       37,996       308,146  
  

 

 

   

 

 

   

 

 

 
   $        (55,412)      $      (29,921)      $         1,523,804  
  

 

 

   

 

 

   

 

 

 

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

Oil and gas revenues.    Oil and gas revenues increased $0.5 billion, to $2.0 billion for 2011 from $1.5 billion 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 $0.4 billion, to $1.5 billion for 2011 from $1.1 billion 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.

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 is primarily at our California properties.

 

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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 is 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.

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, 10% Senior Notes and 7% Senior Notes. In connection with the reduction in the borrowing base on our senior revolving credit facility, we recorded $1.2 million of debt extinguishment costs in 2010.

Gain (loss) 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.

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.

 

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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 annual effective tax rate from the 35% federal statutory for 2011 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 annual effective tax rate from the 35% federal statutory rate for 2010 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.

Comparison of Year Ended December 31, 2010 to Year Ended December 31, 2009

Oil and gas revenues.    Oil and gas revenues increased $0.3 billion, to $1.5 billion for 2010 from $1.2 billion for 2009, primarily due to an $8.52 per BOE increase in average realized prices and a 7% increase in sales volumes. Increased production from our Haynesville Shale properties is primarily responsible for the increase in sales volumes.

Oil revenues increased $239.6 million, to $1.1 billion for 2010 from $903.1 million for 2009, reflecting higher average realized prices ($293.5 million) partially offset by lower sales volumes ($53.9 million). Our average realized price for oil increased $16.71 per Bbl to $68.14 per Bbl for 2010 from $51.43 per Bbl for 2009. The increase is primarily attributable to an increase in the NYMEX oil price, which averaged $79.61 per Bbl in 2010 versus $62.09 per Bbl in 2009. Oil sales volumes decreased 2.2 MBbls per day to 45.9 MBbls per day in 2010 from 48.1 MBbls per day in 2009, primarily reflecting decreased production from our California properties.

Gas revenues increased $117.6 million, to $399.6 million in 2010 from $282.0 million in 2009, due to an increase in sales volumes ($74.1 million) and an increase in realized prices ($43.5 million). Gas sales volumes increased from 207.7 MMcf per day in 2009 to 255.0 MMcf per day in 2010 primarily reflecting increased production from our Haynesville Shale properties partially offset by decreased production from our South Texas and Gulf Coast asset areas. Our average realized price for gas was $4.29 per Mcf in 2010 compared to $3.72 per Mcf in 2009. Our realized price for gas increased primarily due to an increase in the NYMEX price for natural gas ($4.38 per Mcf in 2010 versus $3.97 per Mcf in 2009).

Lease operating expenses.    Lease operating expenses increased $11.6 million, to $262.5 million in 2010 from $250.9 million in 2009, reflecting higher costs primarily due to an increased number of producing wells in the Haynesville Shale and higher expenditures for well workovers primarily from our California properties. On a per unit basis, lease operating costs decreased to $8.13 per BOE in 2010 versus $8.31 per BOE in 2009.

Steam gas costs.    Steam gas costs increased $12.6 million, to $66.4 million in 2010 from $53.8 million in 2009, primarily reflecting higher cost of gas used in steam generation. In 2010, we burned approximately 15.7 Bcf of natural gas at a cost of approximately $4.23 per MMBtu compared to 15.1 Bcf at a cost of approximately $3.57 per MMBtu in 2009.

Electricity.    Electricity decreased $1.1 million, to $42.8 million in 2010 from $43.9 million in 2009, primarily reflecting a decrease in rates in California. On a per unit basis, electricity was $1.33 per BOE in 2010 and $1.45 per BOE in 2009.

 

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Production and ad valorem taxes.    Production and ad valorem taxes decreased $9.3 million, to $29.4 million in 2010 from $38.7 million in 2009, primarily reflecting lower ad valorem taxes and production tax abatements. The reduction in ad valorem taxes reflects lower commodity prices at the time of assessment. The valuation of our oil and gas properties and related ad valorem taxes has a direct relationship to commodity price movements, and will increase as prices increase.

Gathering and transportation expenses.    Gathering and transportation expenses increased $14.0 million, to $50.7 million in 2010 from $36.7 million in 2009, primarily reflecting an increase in production from our Haynesville Shale properties, partially offset by a decrease in rates and volumes at our Gulf of Mexico properties prior to the December 2010 sale.

General and administrative expense.    G&A expense decreased $8.2 million, to $136.4 million in 2010 from $144.6 million in 2009, primarily due to a decrease in stock-based compensation expense.

Depreciation, depletion and amortization.    DD&A expense increased $126.2 million, to $533.4 million in 2010 from $407.2 million in 2009. The increase is attributable to our oil and gas depletion, primarily due to a higher per unit rate ($94.1 million) and increased production ($32.0 million). Our oil and gas unit of production rate increased to $15.87 per BOE in 2010 compared to $12.79 per BOE in 2009. Our oil and gas DD&A rate for 2011, after the effect of our fourth quarter 2010 acquisitions and divestments, is expected to be $16.28 per BOE.

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.

Legal recovery.    We received a net recovery of $8.4 million in 2010 and $87.3 million in 2009 as our share of a portion of the judgments in the Amber Resources Company et al. v. United States related lawsuits.

Interest expense.    Interest expense increased $32.9 million, to $106.7 million in 2010 from $73.8 million in 2009, primarily due to greater average debt outstanding attributed to the Senior Notes issued in March 2010 and increased borrowings under our senior revolving credit facility related to the purchase of our Eagle Ford Shale properties during the fourth quarter 2010. 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 $130.9 million and $116.2 million of interest in 2010 and 2009, respectively.

Debt extinguishment costs.    In connection with reductions of the borrowing base on our senior revolving credit facility, we recorded $1.2 million and $12.1 million of debt extinguishment costs in 2010 and 2009, respectively.

Gain (loss) 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 or receiving a payment from the counterparty.

 

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We recognized a $60.7 million loss on mark-to-market derivative contracts in 2010, which was primarily associated with a decrease in the fair value of our 2011 and 2012 crude oil and natural gas contracts due to higher forward commodity prices partially offset by a gain on our 2010 natural gas collars. We recognized a $7.0 million loss on mark-to-market derivative contracts in 2009, which was primarily attributed to a decrease in the fair value of our crude oil puts attributable to higher crude oil prices, partially offset by an increase in the fair value on our natural gas collars as a result of lower natural gas commodity prices.

Other income (expense).    Other income for 2010 primarily consisted of interest on royalty refunds related to production in prior years. Other income for 2009 primarily consisted of net royalty refunds related to properties sold by Pogo prior to our acquisition.

Income tax benefit (expense).    Our 2010 income tax expense was $100.7 million, reflecting an annual effective tax rate of 49%, as compared with an income tax expense of $80.9 million and an effective tax rate of 37% for 2009. Variances in our annual effective tax rate from the 35% federal statutory rate for these years resulted primarily from the tax effects of permanent differences including expenses that are not deductible because of IRS limitations, the special deduction related to domestic production, state income taxes, foreign operations, tax and financial reporting differences related to non-cash compensation and changes to our balance of unrecognized tax positions.

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 financial and credit markets may adversely affect the financial condition of lenders in our senior revolving credit facility, 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. These market 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 senior revolving credit facility and periodic public offerings of debt and equity. At December 31, 2011, we had approximately $663.8 million available for future secured borrowings under our senior revolving credit facility, which had commitments and a borrowing base of $1.4 billion and $1.8 billion, respectively. In February 2012, our borrowing base was increased from $1.8 billion to $2.3 billion until the next scheduled redetermination date on or before May 1, 2013. The commitments remained unchanged at $1.4 billion.

Under the terms of our senior revolving credit facility, the borrowing base will be 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 senior revolving credit facility. 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 credit facility. At December 31, 2011, the commitments are from a diverse syndicate of 21 lenders and no single lender’s commitment represented more than 7% of the total commitments.

 

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During the fourth quarter of 2011, we improved our liquidity position by reducing our future interest costs and extending the average maturity of our senior notes by issuing $1.0 billion of 6 3/4% Senior Notes that mature in 2022 and retiring approximately $1.3 billion of principal related to our senior notes with higher interest rates and nearer term maturities. See Financing Activities. We further improved our liquidity position by divesting our Texas Panhandle properties and our conventional natural gas South Texas properties. After the exercise of third party preferential rights and preliminary closing adjustments, we received approximately $735.8 million in cash upon the closing of these transactions. At December 31, 2011, we continue to have interests in approximately 50,000 gross acres at our Texas Panhandle properties. We expect to receive additional proceeds from future closings, as may be further modified for additional post-closing adjustments. The cash proceeds received from the 2011 divestments were primarily used to reduce indebtedness. Further, our investment in McMoRan was reclassified from long-term to current assets as the one year restriction to sell the shares ended on December 30, 2011.

Stock Repurchase Program.    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. In January 2012, we completed the purchase of an additional 2.4 million common shares at an average cost of $37.02 per share totaling $88.5 million.

Plains Offshore.    In October 2011, we entered into a securities purchase agreement with 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. The proceeds raised are expected to be used to fund Plains Offshore’s share of capital investment in the Lucius oil field and the Phobos prospect exploratory drilling planned for 2012 and other activities. Under the agreement and upon closing of the transaction, Plains Offshore issued to 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 will pay 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. 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; (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. 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

 

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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, which is discussed below.

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.

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. See Financing Activities. At December 31, 2011, Plains Offshore had $300 million available for future secured borrowings.

Crude Oil Marketing Contract.    In August 2011, we entered into a new marketing contract with ConocoPhillips effective January 1, 2012 that covers approximately 90% of our California production, extends the dedication from January 1, 2015 to January 1, 2023, and replaces the percent of NYMEX index pricing mechanism with a market-based pricing approach. Separately, we executed an agreement with a third party purchaser to sell a large portion of our Eagle Ford Shale crude oil using a Light Louisiana Sweet based pricing mechanism. Due to these new marketing contracts, we expect oil price realizations on a significant portion of our crude oil production to increase relative to WTI beginning in 2012.

Other Considerations.    Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisitions 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 or gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements. 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.

Our 2012 capital budget is approximately $1.6 billion, including capitalized interest and general and administrative expenses. We intend to fund our 2012 capital budget from internally generated funds and borrowings under our senior revolving credit facility, with the portion of our 2012 budget related to Plains Offshore being funded with cash on hand. In addition, we could curtail the portion of our capital expenditures that is discretionary if our cash flows decline from expected levels.

 

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We believe that we have sufficient liquidity through our forecasted cash flow from operations and borrowing capacity under our senior revolving credit facility, 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. We have no near-term debt maturities. Our senior revolving credit facility matures on May 4, 2016 and the earliest maturity of our senior notes will occur on June 15, 2015.

Working Capital

At December 31, 2011, we had working capital of approximately $815.2 million, primarily due to the current asset classification of our investment in the McMoRan common shares and cash on hand from the Plains Offshore preferred stock transaction with EIG in November 2011. Our working capital fluctuates for various reasons, including the fair value of our investment, commodity derivative instruments and stock appreciation rights.

Financing Activities

Senior Revolving Credit Facility.    As of December 31, 2011, our borrowing base is $1.8 billion and commitments are $1.4 billion. In May 2011, we entered into an amendment to our senior revolving credit facility, adjusting our borrowing rates and extending the maturity date to May 4, 2016. In connection with the EIG preferred stock private placement, we further amended our senior revolving credit facility in November 2011. See Plains Offshore Senior Credit Facility. The amendment requires, among other things, that we make a mandatory prepayment if the combined total borrowings under both our senior revolving credit facility and the Plains Offshore senior credit facility exceed the borrowing base, which remained at $1.8 billion. In connection with our divestments in December 2011, we further amended our senior revolving credit facility. The amendment provided for no reduction to our borrowing base. The borrowing base will be 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. In February 2012, our borrowing base was increased from $1.8 billion to $2.3 billion until the next scheduled redetermination date on or before May 1, 2013. The commitments remained unchanged at $1.4 billion. Additionally, our senior revolving credit facility contains a $250 million limit on letters of credit and a $50 million commitment for swingline loans. At December 31, 2011, we had $735.0 million in outstanding borrowings and $1.2 million in letters of credit outstanding under our senior revolving credit facility. The daily average outstanding balance for the quarter and year ended December 31, 2011 was $439.1 million and $411.2 million, respectively.

Amounts borrowed under our senior revolving credit facility, as amended, 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 greater of (1) the prime rate, as determined by JPMorgan Chase Bank, (2) the federal funds rate, plus   1/2 of 1%, and (3) the adjusted 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 additional variable amount of interest payable is based on the utilization rate as a percentage of (a) the total amount of funds borrowed under both our senior revolving credit facility and the Plains Offshore senior credit facility and (b) the borrowing base under our senior revolving credit facility. Letter of credit fees under our senior revolving 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 effective interest rate on our borrowings under our senior revolving credit facility was 2.08% at December 31, 2011.

 

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Our senior revolving 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 senior revolving 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, pay dividends on stock, make distributions of cash or property, change the nature of our business or operations, redeem stock or redeem subordinated debt, make investments, create liens, enter into leases, sell assets, sell capital stock of subsidiaries, guarantee other indebtedness, enter into agreements that restrict dividends from subsidiaries, enter into certain types of swap agreements, enter into 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, 2011, 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%; (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  1/2 of 1%, and (3) the adjusted LIBOR plus 1%. The additional variable amount of interest payable is based on the utilization rate as a percentage of (a) the total amount of funds borrowed under both our senior revolving credit facility and the Plains Offshore senior credit facility and (b) the borrowing base under our senior revolving 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 senior revolving 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 transaction with affiliates, as well as other customary events of default, including a cross-default to PXP’s senior revolving credit facility. If an event of default (as defined in our senior revolving credit facility) has occurred and is continuing under our senior revolving 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, 2012, 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, 2012. Each advance under the short-term facility shall bear interest at a rate per annum mutually agreed on by the bank and us.

 

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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 senior revolving credit facility. No amounts were outstanding under the short-term facility at December 31, 2011. The daily average outstanding balance for the quarter and year ended December 31, 2011 was $43.0 million and $52.6 million, respectively. The weighted average interest rate on borrowings under our short-term credit facility was 1.5% for the years ended December 31, 2011 and 2010.

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 senior revolving credit facility 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 senior revolving credit facility 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.

Cash Tender Offers for 7 3/4% Senior Notes, 10% Senior Notes and 7% Senior Notes.    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, $429.5 million to retire $380.1 million of the $565 million outstanding principal amount of our 10% Senior Notes and $442.1 million to retire $423.1 million of the $500 million outstanding principal amount of our 7% Senior Notes.

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 our debt retirement transactions.

The 7 3/4% Senior Notes, 10% Senior Notes, 7% Senior Notes, 7 5/8% Senior Notes due 2018, 8 5/8% Senior Notes, 7 5/8% Senior Notes due 2020, 6 5/8% Senior Notes and 6 3/4% 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, the guarantees 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 a 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 such subsidiary guarantor provided no default or event of default has occurred or is continuing; or (vi) at such time as such subsidiary guarantor does not have

 

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outstanding any guarantee of any of our or any of our subsidiary guarantor’s 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 senior revolving 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, as defined in the indenture, 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.

Cash Flows

 

     Year Ended December 31,  
     2011     2010     2009  
     (in millions)  

Cash provided by (used in):

      

Operating activities

   $ 1,110.8     $ 912.5     $ 499.0  

Investing activities

     (1,154.6     (1,575.3     (1,280.4

Financing activities

     456.5       667.4       471.3  

Net cash provided by operating activities was $1.1 billion in 2011, $912.5 million in 2010 and $499.0 million in 2009. 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. The increase in net cash provided by operating activities in 2010 primarily reflects higher operating income in 2010 as a result of higher commodity prices.

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 the Haynesville Carry. Net cash used in investing activities of $1.3 billion in 2009 includes additions to oil and gas properties of $1.6 billion and acquisitions of oil and gas properties of $1.2 billion, reflecting the payment of the Haynesville Carry, partially offset by derivative settlements received of $1.5 billion. Derivative settlements related to derivatives that are not accounted for as hedges and do not contain a significant financing element are reflected as investing activities.

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 senior revolving credit facility 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 senior revolving credit facility of $390.0 million and the net proceeds from the $300 million offering of 7 5/8% Senior Notes due 2020. Net cash provided by financing activities of $471.3 million in 2009 primarily reflects the proceeds of $916.4 million, net of original issue discount of $48.6 million, from the issuance of the 10% and the 8 5/8% Senior Notes and the $648.0 million of proceeds from our common stock offerings partially offset by the $1.1 billion net reduction in borrowings under our senior revolving credit facility.

 

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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 2012, excluding acquisitions, is approximately $1.6 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 senior revolving credit facility, 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, we could curtail the portion of our capital expenditures that is discretionary if our cash flows decline from expected levels.

Stock Repurchase Program

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.

In January 2012, we completed the purchase of an additional 2.4 million common shares at an average cost of $37.02 per share totaling $88.5 million. Subsequent to those purchases, 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.

Commitments and Contingencies

We had the following obligations at December 31, 2011 (in thousands):

 

    Total     2012     2013
and 2014
    2015
and 2016
    Thereafter  

Long-term debt

  $   3,776,074     $ -        $ -        $ 999,173     $ 2,776,901  

Interest on debt

    1,951,675       223,467       488,185       457,894       782,129  

Operating leases

    102,138       15,016       28,173       24,038       34,911  

Oil and gas and related activities

    770,437       226,603       289,056       79,261       175,517  

Asset retirement obligation

    238,381       7,749       8,942       19,364       202,326  

Commodity derivative contracts

    68,291       18,209       50,082       -          -     

Stock compensation awards

    21,676       21,676       -          -          -     

Tax uncertainties

    8,708       6,614       480       -          1,614  

Other obligations

    24,894       10,250       9,761       2,074       2,809  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
  $   6,962,274     $      529,584     $      874,679     $   1,581,804     $   3,976,207  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

The long-term debt and interest on debt amounts consist of amounts due under our senior revolving credit facility and Senior Notes and interest payments to maturity. The principal amount under our senior revolving credit facility varies based on our cash inflows and outflows and the amounts reflected in this table assume the principal amount outstanding at December 31, 2011 remains outstanding to maturity with interest and commitment fees calculated at the rates in effect at December 31, 2011.

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

 

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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 $456.1 million. Through our ownership in Lucius, we have a commitment of approximately $314.3 million for our share of certain long lead equipment orders and detailed engineering work.

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.

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

Stock compensation awards represent the net liability for the deemed vested portion of our stock appreciation rights, or SARs. The liability at December 31, 2011 is calculated based on our closing stock price and other factors at that date. The ultimate settlement amount of such liability is unknown because settlements will be based on the market price of our common stock at the time the SARs are exercised. See Critical Accounting Policies and Estimates – Stock-based Compensation.

Tax uncertainties 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 the uncertain tax positions.

Other obligations primarily represent our commitments for various service contracts and aircraft maintenance contracts.

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 which we believe is customary in the industry for environmental matters, but we are not fully insured against all environmental risks. There can be no assurance that current or future local, state or federal rules and regulations will not require us to spend material amounts to comply with such rules and regulations.

Plugging, Abandonment and Remediation Obligations.    Consistent with normal industry practices, substantially all of our oil and gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. Typically, when producing oil and gas assets are purchased, the purchaser assumes the obligation to plug and abandon wells that are part of such assets. However, in some instances, we have received an indemnity with respect to those costs. We cannot be assured that we will be able to collect on these indemnities.

 

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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.

We estimate our 2012 cash expenditures related to plugging, abandonment and remediation will be approximately $7.7 million. At the Point Arguello Unit, offshore California, the companies from which we purchased our interests retained responsibility for the majority of the abandonment costs, including: (1) removing, dismantling and disposing of the existing offshore platforms; (2) removing and disposing of all existing pipelines; and (3) removing, dismantling, disposing and remediating all existing onshore facilities. We are responsible for our 69.3% share of other abandonment costs which primarily consist of well bore abandonments, conductor removals and site cleanup and preparation. Although our offshore California properties have a shorter reserve life, third parties have retained the majority of the obligations for abandoning these properties.

In connection with the sale of certain properties offshore California in December 2004, we retained the responsibility for certain abandonment costs, including removing, dismantling and disposing of the existing offshore platforms. The present value of such abandonment costs, $82.6 million ($145.2 million undiscounted), is included in our asset retirement obligation as reflected in 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 $86.1 million). To secure its abandonment obligations, the purchaser of the properties is required to periodically deposit funds into an escrow account. At December 31, 2011, the escrow account had a balance of $17.7 million. The fair value of our guarantee at December 31, 2011, $0.7 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.

 

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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.

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.

The eight financial institutions that are counterparties for our derivative commodity contracts had a Standard & Poor’s rating of A - or better as of December 31, 2011. Our counterparties to our derivative agreements or their affiliates are generally also lenders under our senior revolving credit facility. As a result, the counterparties to our derivative agreements share in the collateral supporting our revolving credit facility. Therefore, we are not generally required to post additional collateral under our derivative agreements.

The commitments under our senior revolving credit facility and the Plains Offshore senior credit facility are from a diverse syndicate of 21 lenders. At December 31, 2011, 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.

 

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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. Approximately 95% of our 2011 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 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, 2011, the ceiling with respect to our domestic oil and gas properties exceeded the net capitalized costs by 30% and we did not record an impairment.

 

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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 December 31, 2011, we had approximately $2.4 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 57% of the costs not subject to amortization at December 31, 2011 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 2012, after the effect of our fourth quarter 2011 divestments, is expected to be $21.64 per BOE. Based on our estimated proved reserves and our net oil and gas properties subject to amortization at December 31, 2011: (i) a 5.0% increase in our costs subject to amortization would increase our DD&A rate by approximately $1.08 per BOE and (ii) a 5.0% negative revision to proved reserves would increase our DD&A rate by approximately $1.14 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.

 

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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.

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 NYMEX and 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 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.

 

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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. We determine the fair value of our investment by discounting for lack of marketability at the reporting date. The discount factor for lack of marketability is 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 such models requires substantial judgment with respect to the inputs used to determine fair value.

At December 31, 2011, the McMoRan shares were valued at approximately $611.7 million, based on McMoRan’s closing stock price of $14.55 on December 31, 2011, discounted to reflect certain limitations on the marketability of the shares.

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.

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, and in the case of restricted stock unit grants that include common stock price based performance targets, we utilize a Monte-Carlo simulation model to estimate the fair value and the number of restricted stock units 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 $49 million, $51 million and $61 million of stock-based compensation expense for the years ended December 31, 2011, 2010 and 2009, respectively.

 

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Allocation of Purchase Price in Business Combinations.    Accounting for business combinations requires the allocation of the purchase price to the various assets and liabilities of the acquired business at their respective fair values. The most significant estimates in our allocation typically relate to the value assigned to future recoverable oil and gas reserves and unproved properties. To the extent the consideration paid exceeds the fair value of the net assets acquired, we are required to record the excess as goodwill. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. The value allocated to recoverable oil and gas reserves and unproved properties is subject to the full cost ceiling limitation as described in Impairments of Oil and Gas Properties above.

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, 2011, goodwill totaled $535 million and represented approximately 5% 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. A two-step impairment test is used to identify potential goodwill impairment and measure the amount of goodwill impairment loss to be recognized, if any. The first step of the 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.

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.

In September 2011, the Financial Accounting Standards Board, or FASB, issued authoritative guidance which amends the rules for testing goodwill for impairment. Under the new rules, companies are permitted to make a qualitative assessment of a reporting unit’s fair value prior to performing the two-step goodwill impairment test. 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. As of December 31, 2011, we have elected to continue performing our annual goodwill impairment assessment under the quantitative two-step impairment test.

 

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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. We estimate the fair value of the reporting unit by applying a control premium to the quoted market price of our common stock. We determine the control premium 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. 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 2010, the FASB issued authoritative guidance clarifying the acquisition date that should be used for reporting the pro forma financial information disclosures when comparative financial statements are presented. The guidance also improves the usefulness of the pro forma revenue and earnings disclosures by requiring a description of the nature and amount of material, nonrecurring pro forma adjustments that are directly attributable to the business combination. We adopted the provisions of this standard effective January 1, 2011, and it did not have a significant impact on our consolidated financial position, results of operations or cash flows.

In December 2010, the FASB issued authoritative guidance amending the criteria for performing the second step of the goodwill impairment test for companies with reporting units with zero or negative carrying amounts. The amended guidance requires performance of the second step if qualitative factors indicate that it is more likely than not that a goodwill impairment exists. We adopted the provisions of this standard effective January 1, 2011, and it did not have a significant impact on our consolidated financial position, results of operations or cash flows.

 

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In May 2011, the FASB issued authoritative guidance amending certain accounting and disclosure requirements related to fair value measurements. 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 guidance is effective for interim and annual periods beginning after December 15, 2011. Early adoption is not permitted. We do not expect this guidance to have a significant impact on our consolidated financial position, results of operations or cash flows.

In June 2011, the FASB issued authoritative guidance to improve the comparability, consistency and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. The guidance requires entities to report components of comprehensive income in either (i) a single continuous statement of comprehensive income or (ii) two separate but consecutive statements. The guidance also requires entities to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statements where the components of net income and other comprehensive income are presented. In December 2011, the FASB issued further authoritative guidance deferring the requirements for entities to present on the face of the financial statements those reclassification adjustments for items that are reclassified from other comprehensive income to net income. The guidance reinstates the requirements for the presentation of reclassification adjustments on either the face of financial statements where comprehensive income is reported or in the notes to the financial statements. The requirements of both standards are effective for interim and annual periods beginning after December 15, 2011, with early adoption permitted. We adopted the provisions of the June 2011 guidance, excluding the requirements deferred in the December 2011 guidance, effective December 31, 2011 and these provisions require that we position our statement of comprehensive income consecutively to the income statement.

In September 2011, the FASB issued authoritative guidance permitting companies to make a qualitative assessment of a reporting unit’s fair value prior to performing the two-step goodwill impairment test. 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 guidance is effective for interim and annual goodwill impairment tests performed in fiscal years beginning after December 15, 2011, with early adoption permitted. We perform our goodwill impairment test annually as of December 31. We adopted the provisions of this standard effective December 31, 2011 and elected to continue performing our annual goodwill impairment assessment under the quantitative two-step impairment test.

In December 2011, the 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. The guidance is effective for interim and annual periods beginning after January 1, 2013, and will primarily impact our disclosures associated with our commodity derivative instruments. We are currently evaluating the impact of this guidance.

 

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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. See Note 6 – Commodity Derivative Contracts and Note 8 – Fair Value Measurements of Assets and Liabilities in the accompanying financial statements for a discussion of our derivative activities and fair value measurements.

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. Additionally, we converted 40,000 of the 160,000 MMBtu per day 2012 natural gas 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. 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 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.

During the period from January 1, 2012 through February 22, 2012, we converted 5,000 of the 22,000 BOPD of Brent crude oil put option contracts in 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 eliminates approximately $11 million of deferred premiums. Additionally, we entered into the following Brent oil derivatives for 2013 and 2014:

 

   

Brent crude oil put option spread contracts on 13,000 BPOD for 2013 with a floor price of $100 per barrel and a limit of $80 per barrel.

   

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

   

Brent crude oil put option spread contracts on 20,000 BOPD for 2014 with a floor price of $90 per barrel and a limit of $70 per barrel.

In February 2012, we entered into natural gas swap contracts, at an average price of $4.16 per MMBtu, on 70,000 MMBtu per day for 2014.

 

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As of February 22, 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

     

2012

         

Feb - Dec

  Three-way collars (2)   40,000 Bbls   $100.00 Floor with an $80.00 Limit   -   Brent
      $120.00 Ceiling    

2013

         

Jan - Dec

  Put options (3)   17,000 Bbls   $90.00 Floor with a $70.00 Limit   $6.253 per Bbl   Brent

Jan - Dec

  Put options (4)   13,000 Bbls   $100.00 Floor with an $80.00 Limit   $6.800 per Bbl   Brent

Jan - Dec

  Three-way collars (5)   25,000 Bbls   $100.00 Floor with an $80.00 Limit   -   Brent
      $124.29 Ceiling    

Jan - Dec

  Three-way collars (6)   5,000 Bbls   $90.00 Floor with a $70.00 Limit   -   Brent
      $126.08 Ceiling    

2014

         

Jan - Dec

  Put options (3)   20,000 Bbls   $90.00 Floor with a $70.00 Limit   $6.555 per Bbl   Brent

Sales of Natural Gas Production

       

2012

         

Feb - Dec

  Put options (7)   120,000 MMBtu   $4.30 Floor with a $3.00 Limit   $0.298 per MMBtu   Henry Hub

Feb - Dec

  Three-way collars (8)   40,000 MMBtu   $4.30 Floor with a $3.00 Limit   -   Henry Hub
      $4.86 Ceiling    

2013

         

Jan - Dec

  Swap contracts (9)   110,000 MMBtu   $4.27   -   Henry Hub

2014

         

Jan - Dec

  Swap contracts (9)   70,000 MMBtu   $4.16   -   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 $100 per barrel floor, we receive the difference between the $100 per barrel floor and the index price up to a maximum of $20 per barrel. We pay the difference between the index price and $120 per barrel if the index price is greater than the $120 per barrel ceiling. If the index price is at or above $100 per barrel but at or below $120 per barrel, no cash settlement is required.
(3) If the index price is less than the $90 per barrel floor, we receive the difference between the $90 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 $90 per barrel, we pay only the option premium.
(4) If the index price is less than the $100 per barrel floor, we receive the difference between the $100 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 $100 per barrel, we pay only the option premium.
(5) If the index price is less than the $100 per barrel floor, we receive the difference between the $100 per barrel floor and the index price up to a maximum of $20 per barrel. We pay the difference between the index price and $124.29 per barrel if the index price is greater than the $124.29 per barrel ceiling. If the index price is at or above $100 per barrel but at or below $124.29 per barrel, no cash settlement is required.
(6) If the index price is less than the $90 per barrel floor, we receive the difference between the $90 per barrel floor and the index price up to a maximum of $20 per barrel. We pay the difference between the index price and $126.08 per barrel if the index price is greater than the $126.08 per barrel ceiling. If the index price is at or above $90 per barrel but at or below $126.08 per barrel, no cash settlement is required.
(7) If the index price is less than the $4.30 per MMBtu floor, we receive the difference between the $4.30 per MMBtu floor and the index price up to a maximum of $1.30 per MMBtu less the option premium. If the index price is at or above $4.30 per MMBtu, we pay only the option premium.
(8) If the index price is less than the $4.30 per MMBtu floor, we receive the difference between the $4.30 per MMBtu floor and the index price up to a maximum of $1.30 per MMBtu. We pay the difference between the index price and $4.86 per MMBtu if the index price is greater than the $4.86 per MMBtu ceiling. If the index price is at or above $4.30 per MMBtu but at or below $4.86 per MMBtu, no cash settlement is required.
(9) If the index price is less than the fixed price ($4.27 per MMBtu for the 2013 contracts and $4.16 per MMBtu for the 2014 contracts), 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.

 

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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 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, 2011 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

   $ 48      $ (12   $ 14  

Crude oil collars

     11        (81     70  

Natural gas collars

     13        (3     2  

Natural gas puts

     41        (6     6  

Natural gas swaps

     13        (15     16  
  

 

 

    

 

 

   

 

 

 
   $ 126      $ (117   $ 108  
  

 

 

    

 

 

   

 

 

 

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.

 

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

Approximately 20% of our 2011 crude oil production was sold under contracts that provide for NYMEX less a fixed price differential (as of December 31, 2011 the fixed price differential averaged $4.66 per barrel) with the remainder sold under contracts that provide for monthly field posted prices.

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 senior revolving credit facility, the Plains Offshore senior credit facility and our short-term credit facility. At December 31, 2011, $735.0 million was outstanding under our senior revolving credit facility at an effective interest rate of 2.08%. Based on the $735.0 million outstanding under our senior revolving credit facility at December 31, 2011, on an annualized basis a 1% change in the effective interest rate would result in a $7.4 million change in our interest costs. At December 31, 2011, no amounts were outstanding under the Plains Offshore senior credit facility or our short-term credit facility.

Equity Price Risk

We are exposed to market risk because we own an equity investment in McMoRan common stock. See Note 7 – Investment and Note 8 – Fair Value Measurements of Assets and Liabilities in the accompanying financial statements for a discussion of our equity investment. At December 31, 2011, the investment, comprised of 51.0 million shares of McMoRan common stock, was valued at approximately $611.7 million. A 10% change in the underlying equity market price per share would result in a $61.2 million increase or decrease in the fair value of our investment, recognized in the income statement.

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, 2011 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.

 

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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, 2011.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2011 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended December 31, 2011 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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 an amendment to this Form 10-K or in the proxy statement for the 2012 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2011, and is incorporated by reference to this report.

Directors and Executive Officers of Plains Exploration & Production Company

Listed below are our directors and executive officers, their age as of January 31, 2012 and their business experience for the last five years.

Directors

James C. Flores, age 52, 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 known as 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 76, 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 64, 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 71, 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 71, 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 67, Director since November 2007.    He was also a director of 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 currently serves as a director of the National Energy Education and Development Project as well as the National Marine Sanctuary Foundation, where he is head of the Audit Committee.

Charles G. Groat, age 71, Director since November 2007.    He was also a director of Pogo from 2005 to November 2007. Dr. Groat currently serves as the 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. He is also a professor of Geological Sciences and Public Affairs at the University of Texas at Austin. 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. Dr. Groat currently serves as a director on the board of The Water Institute of the Gulf.

John H. Lollar, age 73, 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 52, 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 54, 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 49, 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 50, 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 an amendment to this Form 10-K or in the proxy statement for the 2012 annual meeting of stockholders and is incorporated by reference to this report.

 

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

Information regarding beneficial ownership will be included in an amendment to this Form 10-K or in the proxy statement for the 2012 annual meeting of stockholders and is incorporated by reference to this report.

 

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

Information regarding certain relationships and related transactions and director independence will be included in an amendment to this Form 10-K or in the proxy statement for the 2012 annual meeting of stockholders and is incorporated by reference to this report.

 

Item 14.  Principal Accounting Fees and Services

Information regarding principal accounting fees and services will be included in an amendment to this Form 10-K or in the proxy statement for the 2012 annual meeting of stockholders and is incorporated by reference to this report.

 

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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

 

Exhibit

Number

  

Description

2.1    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).
2.2    Participation Agreement between Plains Exploration & Production Company, PXP Louisiana L.L.C., PXP Louisiana Operations LLC and Chesapeake Louisiana, L.P., dated July 7, 2008 (incorporated by reference to Exhibit 2.2 to the Company’s Current Report on Form 8-K filed July 8, 2008, File No. 1-31470).
2.3    First Amendment to the Participation Agreement between Plains Exploration & Production Company, PXP Louisiana L.L.C., PXP Louisiana Operations LLC and Chesapeake Louisiana, L.P., dated February 20, 2009 (incorporated by reference to Exhibit 2.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-31470, or the 2008 10-K).
2.4    Second Amendment to the Participation Agreement among Plains Exploration & Production Company, PXP Louisiana L.L.C., PXP Louisiana Operations LLC and Chesapeake Louisiana, L.P., dated August 5, 2009 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed August 7, 2009, File No. 1-31470).
2.5*    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.
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, or the Amendment No. 2 to Form S-1).
3.2    Certificate of Amendment to the Certificate of Incorporation of Plains Exploration & Production Company dated May 14, 2004 (incorporated by reference to Exhibit 3.1 to the Company’s 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).

 

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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    First Supplemental Indenture, dated March 13, 2007, 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 7% Senior Notes) (incorporated by reference to Exhibit 4.2 to the March 13, 2007 Form 8-K).
4.3    Second Supplemental Indenture dated as of June 5, 2007, to the Indenture dated as of March 13, 2007, among Plains Exploration & Production Company, Plains Resources Inc., PXP East Plateau LLC, PXP Brush Creek LLC, PXP CV Pipeline LLC, PXP Hell’s Gulch LLC, PXP Piceance LLC, the Subsidiary Guarantors parties thereto, and Wells Fargo Bank, N.A., as Trustee (incorporated by reference to Exhibit 4.3 to the 2007 10-K).
4.4    Third Supplemental Indenture dated as of June 19, 2007, 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 3/4% Senior Notes) (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed June 19, 2007, File No. 1-31470).
4.5    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).
4.6    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).
4.7    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).
4.8    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).
4.9    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 quarter ended September 30, 2008, File No. 1-31470).

 

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4.10    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).
4.11    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).
4.12    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).
4.13    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).
4.14    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, or the November 21, 2011 Form 8-K).
4.15    Amended and Restated Credit Agreement, dated as of August 3, 2010, among Plains Exploration & Production Company, 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 4.1 to the Company’s Current Report on Form 8-K filed August 5, 2010, File No. 001-31470).
4.16    Consent and Amendment No.1 to Amended and Restated Credit Agreement, dated as of October 8, 2010, among Plains Exploration & Production Company, 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 4.1 to the Company’s Current Report on Form 8-K filed October 12, 2010, File No. 1-31470).
4.17    Amendment No.2 to Amended and Restated Credit Agreement, dated as of May 4, 2011, among Plains Exploration & Production Company, 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 4.1 to the Company’s Current Report on Form 8-K filed May 5, 2011, File No. 1-31470).
4.18    Omnibus Amendment No.3 to Amended and Restated Credit Agreement, dated as of November 17, 2011, among Plains Exploration & Production Company, the several banks and other financial institutions signatory thereto and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Exhibit 4.2 to the November 21, 2011 Form 8-K).

 

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4.19    Amendment No.4, dated December 8, 2011, to the Amended and Restated Credit Agreement, dated as of August 3, 2010, among Plains Exploration & Production Company, 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 4.1 to the Company’s Current Report on Form 8-K filed December 9, 2011, File No. 1-31470).
4.20*    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.
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+    Plains Exploration & Production Company 2002 Stock Incentive Plan (incorporated by reference to Exhibit 10.7 to the 2007 10-K).
10.5+    Form of Plains Restricted Stock Award Agreement under the 2002 Incentive Plan (incorporated by reference to Exhibit 10.19 to the Company’s Form 10-K for the year ended December 31, 2002, File No. 1-31470).
10.6+*    Form of Restricted Stock Unit Agreement under the 2002 Stock Incentive Plan.
10.7+    Form of Plains Stock Appreciation Rights Agreement under the 2002 Incentive Plan (incorporated by reference to Exhibit 10.11 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, File No. 1-31470, or the September 30, 2006 Form 10-Q).
10.8+    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 quarter ended September 30, 2007, File No. 1-31470).
10.9+    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).
10.10+*    Form of Restricted Stock Unit Agreement under the 2004 Stock Incentive Plan.
10.11+    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).
10.12+    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).
10.13+    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).

 

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10.14+    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).
10.15+    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).
10.16+    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).
10.17+    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).
10.18+    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).
10.19+    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).
10.20    Form of Election for Director Deferral of Restricted Stock Awards (incorporated by reference to Exhibit 10.23 to the 2008 10-K).
10.21    Summary of Director Compensation Program (incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006, File No. 1-31470).
10.22+    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).
10.23+    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).
10.24+    Form of Plains Restricted Stock Award Agreement under the 2010 Incentive Plan (incorporated by reference to Exhibit 10.25 to the 2010 10-K).
10.25+*    Form of Restricted Stock Unit Agreement under the 2010 Incentive Award Plan.
10.26+    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).
10.27    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).
10.28    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).

 

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10.29#    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 quarter ended June 30, 2011, File No. 1-31470).
10.30*    Plains Exploration & Production Company 2006 Incentive Plan.
  10.31+*    Form of Plains Restricted Stock Unit Agreement under the 2006 Incentive Plan.
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.
+ 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.

 

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SIGNATURES

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

 

  PLAINS EXPLORATION & PRODUCTION COMPANY
Date: February 23, 2012  

/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 23, 2012  

/s/ James C. Flores

 

  James C. Flores, Chairman of the Board, President and
Chief Executive Officer (Principal Executive Officer)
Date: February 23, 2012  

/s/ Isaac Arnold, Jr.

 

  Isaac Arnold, Jr., Director
Date: February 23, 2012  

/s/ Alan R. Buckwalter, III

 

  Alan R. Buckwalter, III, Director
Date: February 23, 2012  

/s/ Jerry L. Dees

 

  Jerry L. Dees, Director
Date: February 23, 2012  

/s/ Tom H. Delimitros

 

  Tom H. Delimitros, Director
Date: February 23, 2012  

/s/ Thomas A. Fry, III

 

  Thomas A. Fry, III, Director
Date: February 23, 2012  

/s/ Charles G. Groat

 

  Charles G. Groat, Director
Date: February 23, 2012  

/s/ John H. Lollar

 

  John H. Lollar, Director
Date: February 23, 2012  

/s/ Winston M. Talbert

 

  Winston M. Talbert, Executive Vice President and Chief Financial Officer (Principal Financial Officer)
Date: February 23, 2012  

/s/ Nancy I. Williams

 

  Nancy I. Williams, Vice President / Controller and Chief Accounting Officer (Principal Accounting Officer)

 

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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, 2011 and 2010

     F-3   

Consolidated Statements of Income

  

For the years ended December 31, 2011, 2010 and 2009

     F-4   

Consolidated Statements of Comprehensive Income

  

For the years ended December 31, 2011, 2010 and 2009

     F-5   

Consolidated Statements of Cash Flows

  

For the years ended December 31, 2011, 2010 and 2009

     F-6   

Consolidated Statements of Equity

  

For the years ended December 31, 2011, 2010 and 2009

     F-7   

Notes to Consolidated Financial Statements

     F-8   

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

 

F-1


Table of Contents

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, comprehensive 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, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 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, 2011, 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.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 23, 2012

 

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS

(in thousands of dollars)

 

     December 31,  
     2011     2010  
ASSETS     

Current Assets

    

Cash and cash equivalents

   $ 419,098     $ 6,434  

Accounts receivable

     302,675       269,024  

Commodity derivative contracts

     50,964       -     

Inventories

     20,173       24,406  

Investment

     611,671       -     

Deferred income taxes

     20,723       74,086  

Prepaid expenses and other current assets

     16,073       28,937  
  

 

 

   

 

 

 
     1,441,377       402,887  
  

 

 

   

 

 

 

Property and Equipment, at cost

    

Oil and natural gas properties - full cost method

    

Subject to amortization

     12,016,252       9,975,056  

Not subject to amortization

     2,409,449       3,304,554  

Other property and equipment

     145,959       137,150  
  

 

 

   

 

 

 
     14,571,660       13,416,760  

Less allowance for depreciation, depletion, amortization and impairment

     (6,846,365     (6,196,008
  

 

 

   

 

 

 
     7,725,295       7,220,752  
  

 

 

   

 

 

 

Goodwill

     535,140       535,144  
  

 

 

   

 

 

 

Commodity Derivative Contracts

     12,678       -     
  

 

 

   

 

 

 

Investment

     -          664,346  
  

 

 

   

 

 

 

Other Assets

     76,982       71,808  
  

 

 

   

 

 

 
   $ 9,791,472     $ 8,894,937  
  

 

 

   

 

 

 
LIABILITIES AND EQUITY     

Current Liabilities

    

Accounts payable

   $ 385,231     $ 284,628  

Commodity derivative contracts

     3,761       52,971  

Royalties and revenues payable

     97,095       70,990  

Stock appreciation rights

     21,676       10,603  

Interest payable

     39,342       49,127  

Other current liabilities

     79,081       65,370  
  

 

 

   

 

 

 
     626,186       533,689  
  

 

 

   

 

 

 

Long-Term Debt

     3,760,952       3,344,717   
  

 

 

   

 

 

 

Other Long-Term Liabilities

    

Asset retirement obligation

     230,633       225,571  

Commodity derivative contracts

     823       24,740  

Other

     15,749       28,205  
  

 

 

   

 

 

 
     247,205       278,516  
  

 

 

   

 

 

 

Deferred Income Taxes

     1,461,897       1,355,050  
  

 

 

   

 

 

 

Commitments and Contingencies (Note 12)

    

Equity

    

Stockholders’ equity

    

Common stock, $0.01 par value, 250.0 million shares authorized,
143.9 million shares issued at December 31, 2011 and 2010

     1,439       1,439  

Additional paid-in capital

     3,434,928       3,427,869  

Retained earnings

     337,991       148,620  

Treasury stock, at cost, 13.3 million shares and 3.8 million shares at
December 31, 2011 and 2010, respectively

     (509,722     (194,963
  

 

 

   

 

 

 
     3,264,636       3,382,965  

Noncontrolling interest

    

Preferred stock of subsidiary

     430,596       -     
  

 

 

   

 

 

 
     3,695,232       3,382,965  
  

 

 

   

 

 

 
   $ 9,791,472     $ 8,894,937  
  

 

 

   

 

 

 

See notes to consolidated financial statements.

 

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per share data)

 

     Year Ended December 31,  
     2011     2010     2009  

Revenues

      

Oil sales

   $ 1,528,656     $ 1,142,760     $ 903,146  

Gas sales

     428,220       399,607       281,978  

Other operating revenues

     7,612       2,228       2,006  
  

 

 

   

 

 

   

 

 

 
     1,964,488       1,544,595       1,187,130  
  

 

 

   

 

 

   

 

 

 

Costs and Expenses

      

Lease operating expenses

     334,923       262,533       250,916  

Steam gas costs

     65,482       66,449       53,801  

Electricity

     41,242       42,794       43,891  

Production and ad valorem taxes

     55,225       29,446       38,708  

Gathering and transportation expenses

     62,103       50,680       36,651  

General and administrative

     134,044       136,437       144,586  

Depreciation, depletion and amortization

     664,478       533,416       407,248  

Impairment of oil and gas properties

     -          59,475       -     

Accretion

     17,177       17,702       14,332  

Legal recovery

     -          (8,423     (87,272

Other operating (income) expense

     (735     (4,130     2,136  
  

 

 

   

 

 

   

 

 

 
     1,373,939       1,186,379       904,997  
  

 

 

   

 

 

   

 

 

 

Income from Operations

     590,549       358,216       282,133  

Other (Expense) Income

      

Interest expense

     (161,316     (106,713     (73,811

Debt extinguishment costs

     (120,954     (1,189     (12,093

Gain (loss) on mark-to-market derivative contracts

     81,981       (60,695     (7,017

Loss on investment measured at fair value

     (52,675     (1,551     -     

Other income

     3,356       15,942       27,968  
  

 

 

   

 

 

   

 

 

 

Income Before Income Taxes

     340,941       204,010       217,180  

Income tax benefit (expense)

      

Current

     25,952       93,090       (45,091

Deferred

     (160,214     (193,835     (35,784
  

 

 

   

 

 

   

 

 

 

Net Income

     206,679     $ 103,265     $ 136,305  
    

 

 

   

 

 

 

Net income attributable to noncontrolling intere