ANADARKO PETROLEUM CORP 2ND QTR 2011 FORM 10-Q
Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2011

or

[    ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the transition period from              to             

Commission File No. 1-8968

ANADARKO PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

 

Delaware   76-0146568
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)

1201 Lake Robbins Drive, The Woodlands, Texas 77380-1046

(Address of principal executive offices)

Registrant’s telephone number, including area code (832) 636-1000

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

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.

Large accelerated filer  x      Accelerated filer  ¨      Non-accelerated filer  ¨     Smaller reporting company  ¨

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

The number of shares outstanding of the Company’s common stock as of June 30, 2011, is shown below:

 

Title of Class   Number of Shares Outstanding
Common Stock, par value $0.10 per share   497,809,244


Table of Contents

TABLE OF CONTENTS

 

PART I

        Page   

Item 1.

  

Financial Statements

  
  

Consolidated Statements of Income for the Three and Six Months
Ended June 30, 2011, and 2010

     2   
  

Consolidated Balance Sheets as of June 30, 2011, and December 31, 2010

     3   
  

Consolidated Statement of Equity for the Six Months Ended June 30, 2011

     4   
  

Consolidated Statements of Comprehensive Income for the Three and Six
Months Ended June 30, 2011, and 2010

     5   
  

Consolidated Statements of Cash Flows for the Six Months
Ended June 30, 2011, and 2010

     6   
  

Notes to Consolidated Financial Statements

     7   

Item 2.

  

Management’s Discussion and Analysis

     35   
  

Financial Results

     39   
  

Operating Results

     48   
  

Liquidity and Capital Resources

     50   
  

Regulatory Matters, Environmental and Additional Factors Affecting Business

     54   
  

Critical Accounting Estimates

     55   
  

Recent Accounting Developments

     55   

Item 3.

  

Quantitative and Qualitative Disclosures About Market Risk

     56   

Item 4.

  

Controls and Procedures

     57   

PART II

     

Item 1.

  

Legal Proceedings

     58   

Item 1A.

  

Risk Factors

     61   

Item 2.

  

Unregistered Sales of Equity Securities and Use of Proceeds

     67   

Item 6.

  

Exhibits

     68   


Table of Contents

PART I. FINANCIAL INFORMATION

Item  1. Financial Statements

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
millions except per-share amounts    2011      2010      2011      2010  

Revenues and Other

           

Natural-gas sales

   $ 870       $ 802       $ 1,724       $ 1,883   

Oil and condensate sales

     2,236         1,338         4,043         2,840   

Natural-gas liquids sales

     370         235         703         509   

Gathering, processing, and marketing sales

     258         188         488         461   

Gains (losses) on divestitures and other, net

     (58)         41         (29)         50   
                                   

Total

     3,676         2,604         6,929         5,743   
                                   

Costs and Expenses

           

Oil and gas operating

     236         196         468         383   

Oil and gas transportation and other

     207         196         416         387   

Exploration

     236         198         415         353   

Gathering, processing, and marketing

     205         149         376         332   

General and administrative

     291         203         526         413   

Depreciation, depletion, and amortization

     985         902         1,970         1,883   

Other taxes

     413         268         757         569   

Impairments

     102         115         104         127   
                                   

Total

     2,675         2,227         5,032         4,447   
                                   

Operating Income (Loss)

     1,001         377         1,897         1,296   

Other (Income) Expense

           

Interest expense

     216         200         436         424   

(Gains) losses on commodity derivatives, net

     (343)         (264)         (87)         (852)   

(Gains) losses on other derivatives, net

     144         406         85         435   

Other (income) expense, net

     (18)         14         (42)         23   
                                   

Total

     (1)         356         392         30   
                                   

Income (Loss) Before Income Taxes

     1,002         21         1,505         1,266   

Income Tax Expense (Benefit)

     440         49         706         566   
                                   

Net Income (Loss)

     562         (28)         799         700   

Net Income Attributable to Noncontrolling Interests

     18         12         39         24   
                                   

Net Income (Loss) Attributable to Common Stockholders

   $ 544       $ (40)       $ 760       $ 676   
                                   

Per Common Share:

           

Net income (loss) attributable to common stockholders—basic

   $ 1.09       $ (0.08)       $ 1.52       $ 1.36   

Net income (loss) attributable to common stockholders—diluted

   $ 1.08       $ (0.08)       $ 1.51       $ 1.35   

Average Number of Common Shares Outstanding—Basic

     498         495         497         494   
                                   

Average Number of Common Shares Outstanding—Diluted

     500         495         499         496   
                                   

Dividends (per Common Share)

   $ 0.09       $ 0.09       $ 0.18       $ 0.18   

 

See accompanying Notes to Consolidated Financial Statements.

 

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

millions            June 30,        
2011
        December 31,    
2010
 

ASSETS

    

Current Assets

    

Cash and cash equivalents

   $ 3,406       $ 3,680    

Accounts receivable, net of allowance:

    

Customers

     1,264         1,032    

Others

     1,662         1,391    

Other current assets

     538         572    
  

 

 

   

 

 

 

Total

     6,870         6,675    
  

 

 

   

 

 

 

Properties and Equipment

    

Cost

     57,155         54,815    

Less accumulated depreciation, depletion, and amortization

     18,812         16,858    
  

 

 

   

 

 

 

Net properties and equipment

     38,343         37,957    

Other Assets

     1,568         1,616    

Goodwill and Other Intangible Assets

     5,836         5,311    
  

 

 

   

 

 

 

Total Assets

   $ 52,617       $ 51,559    
  

 

 

   

 

 

 

LIABILITIES AND EQUITY

    

Current Liabilities

    

Accounts payable

   $ 2,286       $ 2,726    

Accrued expenses

     1,416         1,097    

Current portion of long-term debt

     425         291    
  

 

 

   

 

 

 

Total

     4,127         4,114    
  

 

 

   

 

 

 

Long-term Debt

     12,801         12,722    

Other Long-term Liabilities

    

Deferred income taxes

     10,077         9,861    

Asset retirement obligations

     1,555         1,529    

Other

     1,709         1,894    
  

 

 

   

 

 

 

Total

     13,341         13,284    
  

 

 

   

 

 

 

Equity

    

Stockholders’ equity

    

Common stock, par value $0.10 per share (1.0 billion shares authorized, 515.3 million and 513.3 million shares issued as of June 30, 2011, and December 31, 2010, respectively)

     51         51    

Paid-in capital

     7,611         7,496    

Retained earnings

     15,119         14,449    

Treasury stock (17.5 million and 17.1 million shares as of June 30, 2011, and December 31, 2010, respectively)

     (793)        (763)   

Accumulated other comprehensive income (loss)

     (517)        (549)   
  

 

 

   

 

 

 

Total Stockholders’ Equity

     21,471         20,684    

Noncontrolling interests

     877         755    
  

 

 

   

 

 

 

Total Equity

     22,348         21,439    
  

 

 

   

 

 

 

Total Liabilities and Equity

   $         52,617       $     51,559    
  

 

 

   

 

 

 

See accompanying Notes to Consolidated Financial Statements.

 

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

 

    Total Stockholders’ Equity              
    Common
Stock
    Paid-in
Capital
    Retained
Earnings
    Treasury
Stock
    Accumulated
Other
Comprehensive
Income (Loss)
    Non-
controlling
Interests
    Total
Equity
 
millions                                          

Balance at December 31, 2010

  $ 51      $ 7,496      $ 14,449       $ (763)      $ (549)      $ 755       $ 21,439    

Net income (loss)

                  760         —         —         39         799    

Common stock issued

           115        —         —         —         —         115    

Dividends—common

                  (90)        —         —         —         (90)   

Repurchase of common stock

                  —         (30)        —         —         (30)   

Sale of subsidiary units

                  —         —         —         130         130    

Contributions from (distributions to) noncontrolling interest owners and other, net

                  —         —         —         (47)        (47)   

Reclassification of previously deferred derivative losses to net income

                  —         —                —           

Adjustments for pension and other postretirement plans

                  —         —         27         —         27    
                                                       

Balance at June 30, 2011

  $             51      $         7,611      $     15,119       $         (793)      $                 (517)      $     877       $     22,348    
                                                       

 

See accompanying Notes to Consolidated Financial Statements.

 

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

 

       Three Months Ended  
June 30,
       Six Months Ended  
June 30,
 
millions    2011      2010      2011      2010  

Net Income (Loss)

   $ 562     $ (28)       $ 799      $ 700   

Other Comprehensive Income (Loss), net of taxes

          

Reclassification of previously deferred derivative losses to net income (1)

     3              5         

Adjustments for pension and other postretirement plans:

          

Net gain (loss) incurred during period (2)

                           (21)   

Prior service credit (cost) incurred during period (3)

            (4)                 (4)   

Amortization of net actuarial loss and prior service cost to net periodic benefit cost (4)

     13       11         27        22   
                                  

Total adjustments for pension and other postretirement plans

    

 

13

 

  

 

   

 

11 

 

 

 

    

 

27

 

 

 

    

 

(3)

 

  

 

                                  

Total

     16       15         32         
                                  

Comprehensive Income (Loss)

     578       (13)         831        705   

Comprehensive Income Attributable to Noncontrolling Interests

     18       12         39        24   
                                  

Comprehensive Income (Loss) Attributable to Common Stockholders

   $         560     $         (25)       $         792      $         681   
                                  

 

(1) 

Net of income tax benefit (expense) of $(1) million and $(3) million for the three months ended June 30, 2011, and 2010, respectively, and $(3) million and $(5) million for the six months ended June 30, 2011, and 2010, respectively.

(2) 

Net of income tax benefit (expense) of zero and $(2) million for the three months ended June 30, 2011, and 2010, respectively, and zero and $12 million for the six months ended June 30, 2011, and 2010, respectively.

(3) 

Net of income tax benefit (expense) of zero and $2 million for the three months ended June 30, 2011, and 2010, respectively, and zero and $2 million for the six months ended June 30, 2011, and 2010, respectively.

(4) 

Net of income tax benefit (expense) of $(8) million and $(6) million for the three months ended June 30, 2011, and 2010, respectively, and $(16) million and $(12) million for the six months ended June 30, 2011, and 2010, respectively.

 

See accompanying Notes to Consolidated Financial Statements.

 

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

     Six Months Ended
June  30,
 
millions    2011      2010  

Cash Flows from Operating Activities

     

Net income (loss)

   $ 799       $ 700   

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

     

Depreciation, depletion, and amortization

     1,970         1,883   

Deferred income taxes

     258         (97)   

Dry hole expense and impairments of unproved properties

     227         244   

Impairments

     104         127   

(Gains) losses on divestitures, net

     18         (15)   

Unrealized (gains) losses on derivatives, net

     75         (240)   

Other

     61         206   

Changes in assets and liabilities:

     

(Increase) decrease in accounts receivable

     (535)          

Increase (decrease) in accounts payable and accrued expenses

     241         (229)   

Other items—net

     (92)         299   
  

 

 

    

 

 

 

Net cash provided by (used in) operating activities

     3,126         2,883   
  

 

 

    

 

 

 

Cash Flows from Investing Activities

     

Additions to properties and equipment and dry hole costs

     (2,799)         (2,413)   

Acquisition of midstream businesses

     (804)         —    

Divestitures of properties and equipment and other assets

     55         19   

Other—net

     (41)         (78)   
  

 

 

    

 

 

 

Net cash provided by (used in) investing activities

     (3,589)         (2,472)   
  

 

 

    

 

 

 

Cash Flows from Financing Activities

     

Borrowings, net of issuance costs

     1,046         947   

Repayments of debt

     (859)         (1,173)   

Repayment of midstream subsidiary note payable to a related party

     —          (250)   

Increase (decrease) in accounts payable, banks

     (38)         (93)   

Dividends paid

     (90)         (90)   

Repurchase of common stock

     (30)         (29)   

Issuance of common stock, including tax benefit on stock option exercises

     49         81   

Sale of subsidiary units

     130         97   

Distributions to noncontrolling interest owners

     (37)         (22)   

Other financing activities

            (7)   
  

 

 

    

 

 

 

Net cash provided by (used in) financing activities

     175         (539)   
  

 

 

    

 

 

 

Effect of Exchange Rate Changes on Cash

     14         (29)   
  

 

 

    

 

 

 

Net Increase (Decrease) in Cash and Cash Equivalents

     (274)         (157)   

Cash and Cash Equivalents at Beginning of Period

     3,680         3,531   
  

 

 

    

 

 

 

Cash and Cash Equivalents at End of Period

   $             3,406       $             3,374   
  

 

 

    

 

 

 

 

See accompanying Notes to Consolidated Financial Statements.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.  Summary of Significant Accounting Policies

General    Anadarko Petroleum Corporation is engaged in the exploration, development, production, and marketing of natural gas, crude oil, condensate, and natural gas liquids (NGLs). In addition, the Company engages in the gathering, processing, and treating of natural gas, and the transporting of natural gas, crude oil, and NGLs. The Company also participates in the hard minerals business through its ownership of non-operated joint ventures and royalty arrangements. The terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.

Basis of Presentation    The information furnished herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the Company’s Consolidated Balance Sheets as of June 30, 2011, and December 31, 2010, the Consolidated Statements of Income and Comprehensive Income for the three and six months ended June 30, 2011, and 2010, the Consolidated Statements of Cash Flows for the six months ended June 30, 2011, and 2010, and the Consolidated Statement of Equity for the six months ended June 30, 2011. Certain prior-period amounts have been reclassified to conform to the current-period presentation.

In preparing financial statements in accordance with accounting principles generally accepted in the United States, management makes informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, including those related to the value of properties and equipment; proved reserves; goodwill; intangible assets; asset retirement obligations; litigation reserves; environmental liabilities; pension assets, liabilities, and costs; income taxes; and fair values. Changes in facts and circumstances or additional information may result in revised estimates and actual results may differ from these estimates.

Recently Issued Accounting Standards Not Yet Adopted    The Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) that further addresses fair-value-measurement accounting and related disclosure requirements. The ASU clarifies the FASB’s intent regarding the application of existing fair-value measurement and disclosure requirements, changes the fair-value measurement requirements for certain financial instruments, and sets forth additional disclosure requirements for other fair-value measurements. The ASU is required to be adopted on a prospective basis by Anadarko beginning in 2012. The Company is currently evaluating the impact, if any, of the adoption of this ASU on its consolidated financial statements and related disclosures.

2.  Deepwater Horizon Events

Background    In April 2010, the Macondo well in the Gulf of Mexico, in which Anadarko holds a 25% non-operating leasehold interest, discovered hydrocarbon accumulations. During suspension operations, the well blew out, an explosion occurred on the Deepwater Horizon drilling rig, and the drilling rig sank, resulting in the release of hydrocarbons into the Gulf of Mexico. Eleven people lost their lives in the explosion and subsequent fire, and others sustained personal injuries. The Macondo well was permanently plugged on September 19, 2010. Response and cleanup efforts are being conducted by BP Exploration & Production Inc. (BP), the operator and 65% owner of the Macondo lease, and by other parties. Investigations by the federal government and other parties into the cause of the well blowout, explosion, and resulting oil spill, as well as other matters arising from or relating to these events, are ongoing.

Based on information provided by BP to the Company, BP has incurred costs of approximately $20.4 billion through June 30, 2011, related to spill response and containment, relief-well drilling, grants to certain Gulf Coast states for cleanup costs, local tourism promotion, other grants, monetary damage claims, and federal costs.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

BP has sought reimbursement from Anadarko for amounts BP has paid or committed to pay for spill-response efforts, grants, damage claims, and costs incurred by the federal government through provisions of the operating agreement (OA), which is the contract governing the relationship between BP and the non-operating OA parties to the lease for Mississippi Canyon Block 252 in which the Macondo well is located (Lease). BP has invoiced the Company an aggregate of $5.2 billion for what BP considers to be Anadarko’s 25% proportionate share of actual costs through June 30, 2011. In addition, BP has invoiced Anadarko for anticipated near-term future costs related to the Deepwater Horizon events. Anadarko has withheld reimbursement to BP for Deepwater Horizon event-related invoices pending the completion of various ongoing investigations into and litigation regarding the cause of the well blowout, explosion, and subsequent release of hydrocarbons. Final determination of the root causes of the Deepwater Horizon events could materially impact the Company’s potential obligations under the OA.

In April 2011, the Company received a Notice of Dispute (as defined in the OA) from BP requesting, among other things, payment of all amounts invoiced to the Company to date by BP related to the Deepwater Horizon events. Pursuant to dispute resolution procedures under the OA, each party appointed a management representative to meet with the other party’s management representative in an attempt to resolve the dispute. In the event the dispute is not resolved within certain prescribed time periods, totaling approximately 190 days following issuance of the Notice of Dispute, any party may, but is not required to, initiate arbitration proceedings under the OA.

In May 2011, BP and the other non-operating OA party entered into a settlement, release and indemnity agreement. According to its press release, BP and the other non-operating OA party have agreed to a mutual release of claims against each other relating to the Deepwater Horizon events in exchange for a $1.1 billion payment to BP by the other non-operating OA party. BP has also agreed to indemnify the other non-operating OA party for compensatory claims arising from the Deepwater Horizon events, excluding civil, criminal or administrative fines and penalties, and certain other claims.

BP, Anadarko, and other parties, including parties that do not own an interest in the Lease, such as the drilling contractor, have received correspondence from the United States Coast Guard (USCG) referencing their identification as a “responsible party or guarantor” (RP) under the Oil Pollution Act of 1990 (OPA). The United States Department of Justice (DOJ) has also filed a civil lawsuit against such parties seeking, among other things, to confirm each party’s identified RP status. Under OPA, RPs may be jointly and severally liable for costs of well control, spill response, and containment and removal of hydrocarbons, as well as other costs and damage claims related to the spill and spill cleanup. The USCG has directly invoiced the identified RPs for reimbursement of spill-related response costs incurred by the USCG and other federal and state agencies. The identified RPs each received identical invoices for total costs, without specification or stipulation of any allocation of costs among the identified RPs. To date, as operator, BP has paid all USCG invoices, thereby satisfying any joint and several obligation of the identified RPs to the USCG for these costs. BP has also made repeated public statements regarding its intention to continue to pay 100% of costs associated with cleanup efforts, claims, and reimbursements related to the Deepwater Horizon events.

The following analysis applies relevant accounting guidance to the Deepwater Horizon events to determine the Company’s liability accrual as of June 30, 2011. The process for quantifying the Company’s Deepwater Horizon event-related liability accrual involves the identification of all potential costs and the grouping of these costs in a manner that enables the Company to apply relevant accounting guidance to each cost based on the qualitative characteristics of such costs. This is appropriate because satisfaction of liability-recognition criteria varies depending on the type of costs being analyzed. For example, contingent contractual liabilities (such as those arising under the OA) and contingent environmental liabilities (such as those arising under OPA) are subject to substantially similar liability-recognition criteria; however, circumstances under which such criteria are considered satisfied are different.

After applying the relevant accounting guidance to the Company’s Deepwater Horizon event-related contingent liabilities, the Company’s aggregate liability accrual for these amounts is zero as of June 30, 2011. The zero liability accrual is not intended to represent an opinion of the Company that it will not incur any future liability related to the Deepwater Horizon events. Rather, the zero liability accrual is based on currently available facts and the application of accounting rules to this set of facts where the relevant accounting rules do not allow for loss recognition where a potential loss is not considered “probable” or cannot be reasonably estimated.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

In quantifying its potential Deepwater Horizon event-related liabilities, the Company has made certain assumptions regarding facts that are the subject of continuing investigations and litigation, the duration and extent of ongoing cleanup activities, and future damage claims. Thus, the Company’s zero liability accrual for the Deepwater Horizon events as of June 30, 2011, is subject to change in the future, perhaps materially. Below is a discussion of the Company’s current analysis, under applicable accounting guidance, of its potential liability for (i) amounts invoiced by BP under the OA, (ii) OPA-related environmental costs, and (iii) other contingent liabilities.

OA Contingent Liabilities    OA contingent liabilities relate to Anadarko’s potential responsibility for a 25% share of costs incurred by BP through June 30, 2011, for which BP has sought reimbursement from Anadarko under the OA. Accounting standards require the Company to accrue contingent liabilities arising under the terms of the OA if it is both “probable” that a liability has been incurred and the amount of the liability can be reasonably estimated.

With respect to the operator’s duties and liabilities, the OA provides the following:

 

   

BP, as operator, owes duties to the non-operating parties (including Anadarko) to perform the drilling of the well in a good and workmanlike manner and to comply with all applicable laws and regulations;

 

   

BP, as operator, is not liable to non-operating parties for losses sustained or liabilities incurred, except for losses resulting from the operator’s gross negligence or willful misconduct; and

 

   

liability for losses, damages, costs, expenses, or claims involving activities or operations shall be borne by each party in proportion to its participating interest, except that when liability results from the gross negligence or willful misconduct of a party, that party shall be solely responsible for liability resulting from its gross negligence or willful misconduct.

The Company believes publicly available evidence indicates that the blowout of the well, the explosion on the Deepwater Horizon drilling rig, and the subsequent release of hydrocarbons were preventable and the direct result of BP’s decisions, omissions, and actions, and likely constitute gross negligence or willful misconduct by BP. BP has issued public statements indicating that it disagrees with this assessment. Under the terms of the OA, liabilities arising as a result of gross negligence or willful misconduct by BP are the sole responsibility of BP and are not chargeable to other OA parties, including Anadarko. In light of the foregoing, Anadarko does not consider OA contingent liabilities for Deepwater Horizon event-related costs invoiced by BP to the Company to satisfy the standard of “probable” required for loss recognition. Accordingly, as of June 30, 2011, pursuant to applicable accounting guidance, the Company has not recognized a liability in its Consolidated Balance Sheets for Deepwater Horizon event-related costs that have been invoiced by BP to Anadarko under the OA and that are, in part, the subject of BP’s April 2011 Notice of Dispute.

In the future, the Company may recognize a liability for Deepwater Horizon event-related costs invoiced by BP under the OA if new information arising from the legal discovery or adjudication process, hearings, other investigations, expert analysis, or testing alters the Company’s current assessment as to the likelihood of the Company incurring a liability for its existing OA contingent liabilities. In addition, BP, as the operator, may have enforceable indemnity obligations to certain of its contractors, for which BP may be able to obtain reimbursement from the Company under the OA for the Company’s share of any such costs incurred by BP, notwithstanding BP’s own gross negligence. The Company currently is not positioned to assess the validity of BP’s ostensible indemnity obligations to its contractors, nor is the Company knowledgeable as to whether BP has incurred actual costs as a result of these indemnity provisions. As a result, the Company currently does not consider any loss attributable to potential indemnity obligations to be “probable,” and is furthermore unable to reasonably estimate the amount of any such potential loss.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

OPA-Related Environmental Costs    Under OPA, Anadarko may be jointly and severally liable with all RPs for OPA-related environmental costs associated with the Deepwater Horizon events. Anadarko’s treatment by the USCG as an identified RP arises as a result of Anadarko’s status as a co-lessee in the Lease.

Applicable accounting guidance requires the Company to accrue an environmental liability if it is both “probable” that a liability has been incurred and the amount of the liability can be reasonably estimated. Under accounting guidance applicable to environmental liabilities, a liability is presumed “probable” if the entity is both identified as an RP and associated with the environmental event. The Company’s co-lessee status in the Lease and the subsequent identification and treatment of the Company as an RP satisfies these standards and therefore establishes the presumption that the Company’s potential environmental liabilities related to the Deepwater Horizon events are “probable.” Given that such liabilities are probable, applicable accounting guidance requires the Company to (i) estimate, on a gross basis, a range of total potential OPA-related environmental costs for the Deepwater Horizon events, and (ii) separately assess and estimate the Company’s allocable share of the gross estimated costs.

OPA-related environmental costs that have been paid by BP and subsequently invoiced to Anadarko under the OA are accounted for as OA contingent liabilities (discussed above) rather than OPA-related environmental costs (discussed herein). Payment of OPA-related environmental costs by BP satisfies these liabilities for all identified RPs, including Anadarko, and has resulted in BP seeking reimbursement from Anadarko for these costs through the OA, thereby creating OA contingent liabilities. The Company assumes that all OPA-related environmental costs incurred by BP and reported to the Company have been paid by BP, thereby satisfying those joint and several OPA-related environmental costs for all identified RPs.

Gross OPA-Related Environmental Cost Estimate    The Company estimates the range of gross OPA-related environmental costs for all identified RPs to be $4.0 billion to $5.0 billion, excluding (i) $20.4 billion of costs BP has incurred as of June 30, 2011, which are considered and analyzed as OA contingent liabilities, and (ii) amounts the Company currently cannot reasonably estimate, which include OPA damage claims that may be filed subsequent to the third quarter of 2011, potential costs associated with penalties and fines, civil litigation damages, and costs that have not yet been committed by BP for natural resource damage (NRD) assessments and NRD claims. The costs that the Company currently cannot reasonably estimate may be significant.

Anadarko’s gross OPA-related environmental cost estimate is comprised of spill-response costs and OPA damage claims. This cost estimate is based on cost information received from BP, certain assumptions discussed below, and publicly available information from the Gulf Coast Claims Facility (GCCF). The GCCF is a claims facility that was established in June 2010, as part of an agreement between the federal government and BP, to assist claimants in the submission and resolution of claims for costs and damages incurred as a result of the Deepwater Horizon events. As a non-operator, the Company is limited to formulating its estimates of spill-response costs and OPA damages based on information provided by BP, publicly available information, and management’s assumptions regarding a number of variables associated with the Deepwater Horizon events that remain uncertain or unknown. Although the Macondo well has been permanently plugged, the scope and extent of damages and cleanup activities continue to evolve, resulting in significant uncertainty as to the spill’s ultimate impacts and associated costs. Accordingly, the Company believes that actual gross OPA-related environmental costs may vary, perhaps materially, from the Company’s estimate.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

Spill-Response Costs and Assumptions    Estimated spill-response costs are based on cost information received from BP, which was used to estimate activity-based cost run-rates for spill-response activities, which, in turn, were projected forward according to the Company’s estimates of the potential duration and extent of the spill response and cleanup.

The Company’s current cost estimate is based on the following assumptions:

 

   

activities (including required resources) related to the operation, demobilization, and decontamination of offshore well-site equipment are substantially complete; and

 

   

at a minimum, costs will continue through the end of the third quarter of 2011, and end prior to the end of the fourth quarter of 2011, for the following activities:

 

 

shallow-water marine cleanup;

 

 

demobilization and decontamination of vessels deployed in open-water cleanup;

 

 

shoreline cleanup; and

 

 

federal, state, and local spill mitigation and coordination.

The above costs may continue for periods longer than those assumed by the Company for purposes of formulating its cost estimate. The scope and extent of the above costs continue to evolve over time, which adversely impacts the Company’s ability to reasonably estimate certain costs that may continue beyond the above-stated periods. The Company will continue to monitor and estimate costs as the scope and extent of required activities become more certain.

OPA Damage Claims    OPA damages (other than NRD, discussed below) include costs associated with increased public-service expenses, damages to real or personal property, damages to subsistence users of natural resources, lost revenues, lost profits, and diminished earnings capacity. These damages are assessed pursuant to OPA and are limited, in general, to $75 million. However, the $75 million limit has not been applied for purposes of formulating the Company’s cost-range estimate and may not be applicable under OPA where there is a finding of gross negligence, willful misconduct, or a violation of an applicable federal safety, construction, or operating regulation by an RP, an agent or employee of an RP, or a person acting pursuant to a contractual relationship with an RP.

The Company’s cost estimate includes potential OPA damage claims and costs to administer those claims based on data received from BP and publicly available information from the GCCF. This claims information has been used to formulate estimates of the number of claims to be paid and the average per-claim payout projected for claims filed through the end of the third quarter of 2011. In addition, the Company’s cost estimate includes claims administration costs projected through August 2013, the date the GCCF is expected to cease operations.

The Company believes that new claims will continue to be filed beyond the end of the third quarter of 2011; however, the Company is currently unable to reasonably estimate the number and magnitude of such claims. The Company lacks visibility into, among other things, the processes associated with OPA damage claim approvals and claims administration, which significantly hinders the Company’s ability to formulate a long-term estimate of the amount of potential OPA damage claims. Accordingly, the Company’s cost estimate does not include amounts attributable to OPA damage claims that could be made subsequent to the end of the third quarter of 2011.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

Allocable Share of Gross OPA-Related Environmental Costs    As discussed above, under applicable accounting guidance, the Company is required to estimate its allocable share of gross OPA-related environmental costs based on the Company’s estimate of the allocation method and percentage that may ultimately apply. No agreed-upon or stipulated allocation of gross OPA-related environmental costs currently exists. As a result, the Company considered the following factors for purposes of estimating a range of its allocable share of these costs:

 

   

BP’s payment to date of Deepwater Horizon event-related costs—To date, BP has paid all Deepwater Horizon event-related costs and has repeatedly stated publicly and in congressional testimony that it will continue to pay all of these costs. The liability of all RPs for amounts payable under OPA is satisfied as BP funds these amounts. Accordingly, Anadarko’s minimum allocable share of gross OPA-related environmental costs is zero where BP continues to fund 100% of OPA-related environmental costs. Furthermore, the Company believes that in order for BP to obtain reimbursement from Anadarko under the OA for OPA-related environmental costs paid by BP, BP must establish that it is entitled to reimbursement under the terms of the OA. As discussed above, the Company does not consider BP to be entitled to cost reimbursement under the OA.

 

   

Anadarko’s OA sharing percentage—If BP ceases paying any portion of the Deepwater Horizon event-related costs, the federal government could seek payment from all potential RPs under the joint and several liability provisions of OPA. Under this scenario, the Company estimates its maximum allocation of gross OPA-related environmental costs could be 25%, which is equivalent to Anadarko’s OA sharing percentage. The Company does not consider an allocable percentage in excess of 25% to be reasonable based on BP’s public statements that it intends to continue to honor its commitments in the Gulf of Mexico, the Company’s assessment of BP’s ability to continue funding all OPA-related environmental costs, and BP’s agreement to indemnify the other non-operating OA party for its share of potential costs. This estimate of a maximum allocation percentage assumes no allocation of gross OPA-related environmental costs to RPs that are not party to the OA (non-OA RPs).

 

   

Allocation to non-OA RPs—In addition to the parties to the OA identified as RPs (including the Company), two non-OA RPs have been identified by the federal government. The allocation of costs to all potential RPs, including non-OA RPs, would likely reduce Anadarko’s potential allocable share of gross OPA-related environmental costs to an amount less than Anadarko’s 25% OA sharing percentage.

Based on the above, the Company has concluded that a range of 0-25% is appropriate as an estimate of its potential allocable share of gross OPA-related environmental costs. At June 30, 2011, the Company considers zero to be the most likely allocable percentage within the 0-25% range for allocation of gross OPA-related environmental costs and, consistent with applicable accounting guidance, continues to have a liability accrual of zero. The Company’s assessment as to the most likely allocation percentage is based on BP’s continued funding of 100% of OPA-related environmental costs and BP’s repeated public commentary regarding its ability and intent to continue to honor its Deepwater Horizon-related commitments. BP’s funding and public commentary has continued subsequent to the release of BP’s own investigation report as well as the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling’s final report, which the Company considers significant in concluding that zero is the most likely allocation percentage within the 0-25% range.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

Other Contingencies

Penalties and Fines    These costs include amounts that may be assessed as a result of potential civil and/or criminal penalties under various federal, state, and/or local statutes and/or regulations as a result of the Deepwater Horizon events, including, for example, the Clean Water Act (CWA), the Outer Continental Shelf Lands Act, the Migratory Bird Treaty Act, and possibly other federal, state, and local laws. The foregoing does not represent an exhaustive list of statutes and regulations that potentially could trigger a penalty or fine assessment against BP or the Company. Currently, the Company cannot reasonably estimate the amount of any federal, state, or local penalties or fines that could be assessed or the extent to which such penalties or fines could be material to the Company’s financial statements.

To date, no penalties or fines have been assessed against the Company or, to the Company’s knowledge, any other party. However, on December 15, 2010, the DOJ, on behalf of the United States, filed a civil lawsuit in the United States District Court in New Orleans, Louisiana (Louisiana District Court) against several parties, including Anadarko Petroleum Corporation and Anadarko E&P Company LP (AE&P), a subsidiary of Anadarko, seeking (i) an assessment of civil penalties under the CWA in an amount to be determined by the Louisiana District Court, and (ii) a declaratory judgment that such parties are jointly and severally liable without limitation under OPA for all removal costs and damages resulting from the Deepwater Horizon events. In the lawsuit, the DOJ states that civil penalties under the CWA may be assessed in an amount up to $1,100 per barrel of oil discharged or, in cases involving gross negligence or willful misconduct, in an amount up to $4,300 per barrel of oil discharged. Based on the allegations in the DOJ complaint, the United States government is seeking a declaration of liability and separate assessments against both Anadarko Petroleum Corporation and AE&P. The DOJ apparently seeks relief against AE&P solely based on a temporary interest that AE&P held at one time in the Lease. In April 2011, the Company moved to dismiss AE&P from the DOJ lawsuit because the effective date of AE&P’s transfer of its interest in the Lease to Anadarko pre-dated the Deepwater Horizon events.

While Anadarko was named in the DOJ civil lawsuit, its status as a defendant does not mean that Anadarko will be assessed a penalty in that action. CWA penalties, in practice, are generally assessed on a party-specific basis and take into account several factors such as the party’s degree of fault. The Company considers BP’s actions, as well as the Company’s lack of direct involvement in the operation of the drilling rig or the spill, significant for purposes of concluding that potential losses from CWA penalty assessments are not “probable.” Neither the DOJ civil lawsuit nor the potential for BP to be found grossly negligent alters the Company’s assessment of its exposure to potential penalties under the CWA. Accordingly, the Company has not recorded a liability for potential CWA penalties at June 30, 2011.

In addition to determining that any potential liability for CWA penalties is not “probable,” the Company currently cannot estimate the amount of any such penalty. Over the course of the spill, there have been several widely varying estimates of the ultimate spill volume by various groups. On August 2, 2010, the federal government published its spill-volume estimate of 4.9 million barrels, which was based on several assumptions and acknowledges variability of the flow rate over time, inherent imprecision in the federal government’s ability to accurately estimate the flow rate, and uncertainty in evaporation and dispersion rates. In December 2010, BP stated publicly its intent to challenge the federal government’s spill-volume estimate. The DOJ complaint does not reference or estimate a spill volume.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

In addition to spill-volume variability, there is significant uncertainty as to the Company’s ultimate liability for potential CWA penalties, if any, as previous CWA penalty settlements vary greatly, have not been based solely on a simple per-barrel penalty assessment, and have often been influenced by some or all of the following subjective factors included in the CWA:

 

   

the degree of culpability involved;

 

   

the seriousness of the violation;

 

   

the economic benefit to the violator;

 

   

any other penalties assessed for the same incident;

 

   

the history of prior violations; and

 

   

any mitigation efforts undertaken and the success of those efforts.

Based on the above factors, the significant uncertainty regarding the actual spill volume, and historic resolution through settlement, the Company currently is unable to reasonably estimate any potential CWA penalties.

Natural Resource Damages (NRD)    This category includes costs to assess damages to natural resources resulting from the spill and/or spill-cleanup activities as well as future damage claims that may be made by federal and/or state natural resource trustee agencies at the completion of injury assessments and restoration planning. Natural resources generally include land, fish, water, air, wildlife, or other such resources belonging to, managed by, held in trust by, or otherwise controlled by, the federal, state, or local government.

The NRD-assessment process is led by government agencies that act as trustees of natural resources on behalf of the public. Government agencies involved in the process include the Department of Commerce, the Department of the Interior, and the Department of Defense. These governmental departments, along with the five affected states, Alabama, Florida, Louisiana, Mississippi, and Texas, are referred to as the “Co-Trustees.” The Co-Trustees continue to conduct injury assessment and restoration planning. The assessment phase will continue as long as spill-cleanup activities are ongoing, and may extend for an unknown period of time subsequent to the completion date of spill-cleanup activities. Restoration planning is ongoing and will be completed subsequent to the completion of the injury assessment.

In October 2010, the Co-Trustees notified the identified RPs that certain “emergency restoration actions” were to commence. BP is working cooperatively with the Co-Trustees and has provided the Company with documentation of expenses associated with pre-funding the Co-Trustees’ NRD assessment activities. NRD assessment costs, such as these, may change significantly as injury assessment and restoration planning continues. Thus, the Company is unable to project total NRD assessment costs at this time.

The DOJ civil lawsuit filed against BP, the Company, and others seeks unspecified damages for injury to federal natural resources. Not all of the Co-Trustees were a party to this lawsuit; however, during the second quarter of 2011, the states of Alabama and Louisiana each filed NRD-related claims against the Company in the Louisiana District Court. The Company filed a motion to dismiss all of the claims in both of these complaints in June 2011. At this time, the Company is unable to reasonably estimate the magnitude of any NRD claim until assessment and restoration planning is complete, which may take several years, or until additional facts or information are revealed during legal discovery.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

Civil Litigation Damage Claims    Numerous civil lawsuits have been filed against BP and other parties, including the Company, by, among others, fishing, boating, and shrimping enterprises and industry groups; restaurants; commercial and residential property owners; certain rig workers or their families; the State of Alabama and several of its political subdivisions; the DOJ; environmental non-governmental organizations; the State of Louisiana and certain of its political subdivisions; and certain Mexican states. Many of the lawsuits filed assert various claims of negligence, gross negligence, and violations of several federal and state laws and regulations, including, among others, OPA; the Comprehensive Environmental Response, Compensation, and Liability Act; the Clean Air Act; the CWA; and the Endangered Species Act; or challenge existing permits for operations in the Gulf of Mexico. Generally, the plaintiffs are seeking actual damages, punitive damages, declaratory judgment, and/or injunctive relief.

In August 2010, the United States Judicial Panel on Multidistrict Litigation created Multidistrict Litigation No. 2179 (MDL) to administer essentially all pretrial matters for litigation filed in federal court involving Deepwater Horizon event-related claims. Federal Judge Carl Barbier presides over this MDL in the Louisiana District Court. The Louisiana District Court has issued a number of case management orders that establish a schedule for procedural matters, discovery, and trial of certain of the MDL cases. The parties to the MDL are actively engaged in discovery. In May 2011, Judge Barbier heard oral arguments on the numerous motions to dismiss filed by the multiple defendants named in this litigation, but has not issued a ruling on the Master Complaints that name the Company as a defendant, except in July 2011 to dismiss Racketeer Influenced and Corrupt Organizations Act (RICO) claims alleged by the plaintiffs.

The Louisiana District Court has scheduled a February 2012 trial in Transocean’s Limitation of Liability case in the MDL to determine the liability issues and the liability allocation among the parties involved in the Deepwater Horizon events. In April 2011, the Company filed its answer in this Limitation of Liability case in the MDL proceeding and cross-claimed against affiliates of BP and Transocean Ltd. (Transocean), Halliburton Energy Services, Inc. (Halliburton), Cameron International Corporation (Cameron), and other third-party defendants. Transocean, Halliburton, and Cameron subsequently filed cross-claims against the Company, and BP filed a motion to stay the litigation in the MDL between BP and the non-operating OA parties. In the motion to stay, BP argues that the cross-claims asserted against BP by the Company and the other non-operating OA party are covered by the dispute resolution procedures under the OA and should be stayed. In May 2011, BP and the other non-operating OA party entered into a settlement, release and indemnity agreement. In June 2011, Judge Barbier issued an order holding that BP and the Company had agreed in the OA to submit disputes among them to arbitration, but requested that the parties submit further briefing on whether BP had waived arbitration by its conduct in the MDL. In July 2011, BP and the Company submitted their briefs and the court ordered that all litigation between BP and the Company is stayed pending arbitration.

Lawsuits seeking to place limitations on the oil and gas industry’s operations in the Gulf of Mexico, including those of the Company, have also been filed outside of the MDL by non-governmental organizations against various governmental agencies. These cases are filed in the Louisiana District Court, the United States District Courts for the Southern District of Alabama and the District of Columbia, and in the United States Court of Appeals for the Fifth Circuit.

Two separate class action complaints were filed in June and August 2010, in the United States District Court for the Southern District of New York (New York District Court) on behalf of purported purchasers of the Company’s stock between June 12, 2009, and June 9, 2010, against Anadarko and certain of its officers. The complaints allege causes of action arising pursuant to the Securities Exchange Act of 1934 for purported misstatements and omissions regarding, among other things, the Company’s liability related to the Deepwater Horizon events. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs. In November 2010, the New York District Court consolidated the two cases and appointed The Pension Trust Fund for Operating Engineers and Employees’ Retirement System of the Government of the Virgin Islands (Virgin Islands Group) to act as Lead Plaintiff. In January 2011, the Lead Plaintiff filed its Consolidated Amended Complaint. Prior to filing its Consolidated Amended Complaint, the Lead Plaintiff requested leave from the New York District Court to transfer this lawsuit to the United States District Court for the Southern District of Texas. The Company opposes the Lead Plaintiff’s request to transfer the case to the District Court for the Southern District of Texas. The parties have submitted briefs to the New York District Court concerning the transfer of venue issue. In March 2011, the Company moved to dismiss the Consolidated Amended Complaint of the Lead Plaintiff, and in April 2011, the Lead Plaintiff filed its opposition to the motion to dismiss.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

Also in June 2010, a shareholder derivative petition was filed in the 152nd Judicial District Court of Harris County, Texas (Harris County District Court), by a shareholder of the Company against Anadarko (as a nominal defendant), certain of its officers, and current and certain former directors. The petition alleged breaches of fiduciary duties, unjust enrichment, and waste of corporate assets in connection with the Deepwater Horizon events. The plaintiffs sought certain changes to the Company’s governance and internal procedures, disgorgement of profits, and reimbursement of litigation fees and costs. In November 2010, the Harris County District Court granted Anadarko’s Motion to Dismiss for Lack of Jurisdiction and Special Exceptions, and granted the plaintiffs 120 days to file an Amended Petition. In March 2011, the plaintiffs filed an Amended Petition. The Company filed Special Exceptions and a Motion to Dismiss the Amended Petition in April 2011. In June 2011, the Harris County District Court heard oral arguments on these matters and granted the motion to dismiss. The time for the plaintiffs to appeal has expired.

In September 2010, a purported shareholder made a demand of the Company’s Board of Directors (Board) to investigate allegations of breaches of duty by members of management. The Board duly considered the demand, and in January 2011 determined that it would not be in the best interest of the Company to pursue the alleged issues in the demand letter.

The Company currently cannot assess the probability of losses, or reasonably estimate a range of any potential losses related to ongoing proceedings. The Company intends to vigorously defend itself, its officers, and directors in all proceedings.

Liability Outlook    As discussed above, the Company’s aggregate Deepwater Horizon event-related liability accrual of zero as of June 30, 2011, is not intended to represent an opinion of the Company that it will not incur any future liability related to the Deepwater Horizon events. The Company’s liability assessment is based on the application of relevant accounting guidance to the Company’s understanding of currently available facts surrounding the Deepwater Horizon events. As more facts become known, it is reasonably possible that the Company may be required to recognize a liability related to the Deepwater Horizon events, and that the liability could be material to the Company’s consolidated financial position, results of operations, or cash flows.

The Company will continue to monitor the MDL and other legal proceedings discussed above as well as federal investigations related to the Deepwater Horizon events, including investigations by The Deepwater Horizon Joint Investigation Team, and the United States Chemical Safety Board. The Company cannot predict the nature of evidence that may be discovered during the course of legal proceedings and investigations, the timing of discovery, or the timing of completion of any legal proceedings or investigations. The Company continues to evaluate its liability assessment based on the accumulation of evidence obtained and expected to be obtained through continued discovery, expert testimony and opinion, and technical analysis.

Additionally, if BP discontinues payment or is otherwise unable to satisfy its obligations, the Company could be required to recognize a liability for OPA-related environmental costs. Similarly, if other identified RPs do not satisfy their obligations under OPA, the Company could incur additional liability. If Anadarko is required to recognize and pay additional liabilities, the Company could pursue remedies under the OA to recover costs from BP or the other party to the OA. In addition, the Company could pursue recovery or contribution from other parties or non-OA RPs.

Insurance Recoveries    The Company carries insurance to protect against potential financial losses. At the time of the Deepwater Horizon events, the Company’s insurance coverage applied to gross covered costs up to a level of approximately $710 million, less up to $60 million of deductibles. Based on Anadarko’s 25% non-operated leasehold interest in the Lease, the Company estimates its potential net insurance coverage could total $178 million, less deductibles of $15 million. The Company has not recognized a receivable for any potential recoveries in its Consolidated Balance Sheets. At this time, recovery of these amounts is not considered probable because the Company has not yet filed a claim, nor has the Company incurred a probable loss under the OA or an insurable loss for unpaid liabilities. If the Company’s current legal assessment changes such that the Company becomes liable under the OA for Deepwater Horizon event-related costs and funds such costs, the Company expects to recover the first $163 million of insured costs under its existing insurance policy. The Company also carries directors’ and officers’ insurance to cover certain risks associated with certain of the above-described legal proceedings.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

In March 2011, the Company was granted leave by the Louisiana District Court to intervene in a declaratory judgment lawsuit brought by excess insurers for Transocean in a lawsuit now pending in the MDL. The Company contends that it is an additional insured party under the Transocean insurance policies and, as such, is a proper party to the lawsuit and is entitled to participate in any legal proceedings in which the liability of insurers is determined for costs and damages arising from the blowout, explosion, and fire related to the Deepwater Horizon events.

3.  Acquisitions

In May 2011, Anadarko increased its ownership interest in a natural-gas processing plant (Wattenberg Plant), located in northeast Colorado, by acquiring an additional 93% interest for $576 million. Anadarko operates and now owns a 100% interest in the Wattenberg Plant.

In February 2011, Western Gas Partners, LP (WES), a consolidated subsidiary of the Company, acquired a natural-gas processing plant and related gathering systems, located in northeast Colorado, for $304 million (Platte Valley).

These acquisitions, along with future expansion plans, align Anadarko’s natural-gas processing capacity with the Company’s anticipated production growth in the Rocky Mountains Region (Rockies). In addition, these acquisitions position the Company to improve field recoveries and realize operational cost efficiencies.

The Wattenberg Plant and Platte Valley acquisitions constitute business combinations and were accounted for using the acquisition method with the assets acquired and liabilities assumed recognized at fair value at the acquisition dates. The following summarizes the preliminary fair value of assets acquired and liabilities assumed at the acquisition dates:

 

millions       

Properties and equipment

   $ 298   

Intangible assets

     167   

Deferred income taxes

     31   

Other assets

      

Other liabilities

     (21)   

Goodwill

     362   
  

 

 

 

Total assets acquired and liabilities assumed

     841   
  

 

 

 

Less: Fair value of Anadarko’s pre-acquisition 7% equity interest in the Wattenberg Plant

     37   
  

 

 

 

Acquisition of midstream businesses

     804   
  

 

 

 

Loss on Anadarko’s preexisting contracts with the previous Wattenberg Plant owner

     76   
  

 

 

 

Total consideration paid

   $             880   
  

 

 

 

All fair-value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value of acquired properties and equipment is based on market and cost approaches. Intangible assets consist of customer contracts, the fair value of which was determined using an income approach. Deferred tax assets represent the tax effects of differences in the tax basis and acquisition-date fair values of assets acquired and liabilities assumed. Liabilities assumed include asset retirement obligations existing at the date of acquisition, and were valued consistent with the Company’s policy for estimating its asset retirement obligations.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

3.  Acquisitions (Continued)

 

Assets acquired and liabilities assumed are included within the midstream reporting segment, except for $362 million of goodwill recognized in connection with the Wattenberg Plant acquisition and the deferred tax asset arising from $469 million of goodwill that is amortizable for tax purposes. The Wattenberg Plant acquisition-related goodwill and related deferred tax asset are reported within the oil and gas exploration and production reporting segment based on the increase in value to that segment. The increase in value is derived from improved NGLs volume retention from equity production and the alignment of Company-controlled natural-gas processing capacity with future production growth plans in the Rockies. Goodwill is not subject to amortization, but will be subject to annual impairment testing (or more frequent testing as circumstances dictate). At June 30, 2011, the Company had $5.6 billion of goodwill allocated to its four reporting units: $5.5 billion to oil and gas exploration and production; $79 million to gathering and processing; $55 million to WES gathering and processing; and $5 million to transportation.

Prior to the Wattenberg Plant acquisition, the Company was party to natural-gas processing contracts with the previous Wattenberg Plant owner. As a result of the acquisition, these preexisting contracts were terminated, causing the Company to recognize a $76 million loss, which is included in gains (losses) on divestitures and other, net in the Consolidated Statements of Income for the three and six months ended June 30, 2011. This loss represents the aggregate amount by which the contracts were unfavorable as compared to current market transactions for the same or similar services.

The Company also recognized a gain of $21 million from the acquisition-date fair-value remeasurement of its pre-acquisition 7% equity interest in the Wattenberg Plant. The gain is included in gains (losses) on divestitures and other, net in the Consolidated Statements of Income for the three and six months ended June 30, 2011.

Results of operations attributable to the Wattenberg Plant and Platte Valley acquisitions are included in the Company’s Consolidated Statements of Income from the dates acquired. The amounts of revenue and earnings included in the Company’s Consolidated Statements of Income for the three and six months ended June 30, 2011, and the amounts of revenue and earnings that would have been recognized had the acquisitions occurred on January 1, 2010, are not material.

4.  Inventories

The major classes of inventories, included in other current assets, are as follows:

 

millions         June 30,      
2011
      December 31,  
2010
 

Crude oil

  $ 93     $ 126  

Natural gas

    20       64  

NGLs

    58       61  
               

Total

  $ 171     $ 251  
               

5.  Properties and Equipment

Suspended Exploratory Drilling Costs    The Company’s capitalized suspended well costs at June 30, 2011, and December 31, 2010, were $1.2 billion and $935 million, respectively. The increase in suspended exploratory drilling costs during 2011 primarily relates to the capitalization of costs associated with successful exploration drilling in Mozambique, Ghana, Brazil, and the Niobrara area in the Rockies. For the six months ended June 30, 2011, $38 million of exploratory well costs previously capitalized as suspended well costs for greater than one year were charged to dry hole expense and $66 million of capitalized suspended well costs were reclassified to proved properties.

Management believes projects with suspended exploratory drilling costs exhibit sufficient quantities of hydrocarbons to justify potential development and is actively assessing whether reserves can be attributed to these areas. If additional information becomes available that raises substantial doubt regarding the economic or operational viability of any of these projects, the associated costs will be expensed at that time.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

5.  Properties and Equipment (Continued)

 

Impairments    Impairment expense for the three and six months ended June 30, 2011, was $102 million and $104 million, respectively, including $100 million recognized in the second quarter of 2011 related to United States onshore oil and gas exploration and production operating segment properties, based on the change in projected cash flows due to the Company’s intent to divest of the properties. These assets were impaired to fair value, estimated using Level 3 fair-value inputs.

Impairment expense for the three and six months ended June 30, 2010, was $115 million and $127 million, respectively, including $114 million recognized in the second quarter of 2010 related to a production platform included in the oil and gas exploration and production operating segment that remains idle with no identifiable plans for use, and for which a limited market currently exists. The platform was impaired to fair value, estimated using Level 3 fair-value inputs.

6.  Noncontrolling Interests

At June 30, 2011, noncontrolling interests on the Consolidated Balance Sheet includes approximately $146 million, net of tax, related to the effects of changes in the Company’s ownership interest in WES. This amount will be transferred to paid-in capital in the third quarter of 2011 when the WES subordinated limited partner units convert to common units. At June 30, 2011, Anadarko’s ownership interest in WES consists of a 44.3% limited partner interest (common and subordinated units), a 2% general partner interest, and incentive distribution rights.

7.  Derivative Instruments

Objective and Strategy    The Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price and interest-rate risks.

Futures, swaps, and options are used to manage exposure to commodity-price risk inherent in the Company’s oil and natural-gas production and natural-gas processing operations (Oil and Natural-Gas Production/Processing Derivative Activities). Futures contracts and commodity-price swap agreements are used to fix the price of expected future oil and natural-gas sales at major industry trading locations, such as Henry Hub for natural gas and Cushing for oil. Basis swaps are used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and a ceiling price (collar) for expected future oil and natural-gas sales. Derivative instruments are also used to manage commodity-price risk inherent in customer price requirements and to fix margins on the future sale of natural gas and NGLs from the Company’s leased storage facilities (Marketing and Trading Derivative Activities).

Interest-rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to unfavorable interest-rate changes.

The Company does not apply hedge accounting to any of its derivative instruments. As a result, both realized and unrealized gains and losses associated with derivative instruments are recognized in earnings. Net derivative losses attributable to derivatives previously subject to hedge accounting reside in accumulated other comprehensive income (loss) and are reclassified to earnings as the transactions to which the derivatives relate are recognized in earnings. Accumulated other comprehensive loss balances of $117 million ($74 million after tax) and $125 million ($79 million after tax) at June 30, 2011, and December 31, 2010, respectively, relate to interest-rate derivatives that were previously subject to hedge accounting.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

7.  Derivative Instruments (Continued)

 

Oil and Natural-Gas Production/Processing Derivative Activities    Below is a summary of the Company’s derivative instruments at June 30, 2011, related to its oil and natural-gas production/processing activities. The natural-gas prices listed below are New York Mercantile Exchange (NYMEX) Henry Hub prices. The crude-oil prices listed below are NYMEX Cushing.

 

           2011                 2012                  2013        

Natural Gas

       

Three-Way Collars (thousand MMBtu/d)

     480       500        450  

Average price per MMBtu

       

Ceiling sold price (call)

   $ 8.29     $ 9.03      $ 6.57  

Floor purchased price (put)

   $ 6.50     $ 6.50      $ 5.00  

Floor sold price (put)

   $ 5.00     $ 5.00      $ 4.00  

Fixed-Price Contracts (thousand MMBtu/d)

     90                 

Average price per MMBtu

   $ 6.17     $       $   

Basis Swaps (thousand MMBtu/d)

     45                 

Average price per MMBtu

   $ (1.74   $       $   

 

       

MMBtu—million British thermal units

       

MMBtu/d—million British thermal units per day

       
       
           2011      2012  

Crude Oil

       

Three-Way Collars (MBbls/d)

       126        2  

Average price per barrel

       

Ceiling sold price (call)

     $ 99.95      $ 92.50  

Floor purchased price (put)

     $ 79.29      $ 50.00  

Floor sold price (put)

     $ 64.29      $ 35.00  

 

       

MBbls/d—thousand barrels per day

       

A three-way collar is a combination of three options: a sold call, a purchased put, and a sold put. The sold call establishes the maximum price that the Company will receive for the contracted commodity volumes. The purchased put establishes the minimum price that the Company will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price (e.g., NYMEX) plus the excess of the purchased put strike price over the sold put strike price.

Marketing and Trading Derivative Activities    In addition to the positions in the above tables, the Company also engages in marketing and trading activities, which include physical product sales and related derivative transactions used to manage commodity-price risk. At June 30, 2011, and December 31, 2010, the Company had outstanding fixed-price physical transactions related to natural gas for 31 billion cubic feet (Bcf) and 32 Bcf, respectively, offset by derivative transactions for 23 Bcf and 28 Bcf, respectively, for net positions of 8 Bcf and 4 Bcf, respectively.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

7.  Derivative Instruments (Continued)

 

Interest-Rate Derivatives    In 2008 and 2009, Anadarko entered into interest-rate swap agreements to mitigate the risk of rising interest rates on up to $3.0 billion of debt, originally expected to be refinanced in 2011 and 2012, over a reference term of either 10 years or 30 years. The Company locked in a fixed interest rate in exchange for a floating interest rate indexed to the three-month London Interbank Offer Rate (LIBOR). The swap instruments include a provision that requires both the termination of the swaps and cash settlement in full at the start of the reference period. In March 2011, WES entered into a five-year, forward starting interest-rate swap agreement with a notional principal amount of $150 million to mitigate the risk of rising interest rates prior to the issuance of the 5.375% Senior Notes due in 2021. In May 2011, WES terminated the swap at a cost of $1.9 million.

A summary of the swaps outstanding at June 30, 2011, including the outstanding notional principal amounts and the associated reference periods, is presented below.

 

millions except percentages    Reference Period        Weighted-Average    
Interest Rate

Notional Principal Amount:

                   Start                                     End                    

$     750

   October 2011    October 2021    4.72 %

$  1,250

   October 2011    October 2041    4.83 %

$     250

   October 2012    October 2022    4.91 %

$     750

   October 2012    October 2042    4.80 %

Effect of Derivative InstrumentsBalance Sheet    The fair value of the Company’s derivative instruments is presented below.

 

          Gross
             Derivative Assets            
     Gross
        Derivative Liabilities         
 

millions

Derivatives                         

  

Balance Sheet

Classification

         June 30,      
2011
       December 31,  
2010
         June 30,    
2011
       December 31,  
2010
 

Commodity

              
  

Other Current Assets

   $             361      $             444      $ (138)       $ (274)   
  

Other Assets

     147        242        (4)         (56)   
  

Accrued Expenses

     78        89        (116)         (131)   
  

Other Liabilities

     6        26        (13)         (28)   
     

 

 

    

 

 

    

 

 

    

 

 

 
     592        801        (271)         (489)   
     

 

 

    

 

 

    

 

 

    

 

 

 

Interest Rate and Other

              
  

Other Current Assets

     2                —          —    
  

Other Assets

                     —          —    
  

Accrued Expenses

                     (264)         (190)   
  

Other Liabilities

                     (56)         (45)   
     

 

 

    

 

 

    

 

 

    

 

 

 
     2                (320)         (235)   
     

 

 

    

 

 

    

 

 

    

 

 

 

Total Derivatives

      $ 594      $ 801      $ (591)       $ (724)   
     

 

 

    

 

 

    

 

 

    

 

 

 

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

7.  Derivative Instruments (Continued)

 

Effect of Derivative InstrumentsStatement of Income   The realized and unrealized gain or loss amounts and classification related to derivative instruments for the respective three and six months ended June 30 are as follows:

 

        (Gain) Loss  
   

    Classification of (Gain)    

  Three Months Ended
June 30, 2011
    Six Months Ended
June 30, 2011
 
millions      

Derivatives

 

Loss Recognized

  Realized     Unrealized     Total     Realized     Unrealized     Total  

Commodity

             
 

Gathering, Processing, and Marketing
Sales
(1)

  $     $ (4)      $ —       $ 16      $ (5)      $ 11   
 

(Gains) Losses on Commodity Derivatives, net

    (27)        (316)        (343)        (84)        (3)        (87)   

Interest Rate and Other

             
 

(Gains) Losses on Other Derivatives, net

          142        144              83        85   
                                                 

Derivative (Gain) Loss, net

  $ (21)      $       (178)      $       (199)      $ (66)      $ 75      $  
                                                 
        (Gain) Loss  
millions       Classification of (Gain)       Three Months Ended
June 30, 2010
    Six Months Ended
June 30, 2010
 

Derivatives

 

Loss Recognized

  Realized     Unrealized     Total     Realized     Unrealized     Total  

Commodity

             
 

Gathering, Processing, and Marketing
Sales
(1)

  $     $     $     $     $ (5)      $ (4)   
 

(Gains) Losses on Commodity Derivatives, net

    (161)        (103)        (264)        (182)        (670)        (852)   

Interest Rate and Other

             
 

(Gains) Losses on Other Derivatives, net

    —         406        406        —         435        435   
                                                 

Derivative (Gain) Loss, net

    $       (160)      $ 305      $ 145      $       (181)      $       (240)      $       (421)   
                                                 

 

(1) 

Represents the effect of marketing and trading derivative activities.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

7.  Derivative Instruments (Continued)

 

Credit-Risk Considerations   The financial integrity of exchange-traded contracts is assured by NYMEX or the Intercontinental Exchange through systems of financial safeguards and transaction guarantees and is subject to nominal credit risk. Over-the-counter traded swaps, options, and futures contracts expose the Company to counterparty credit risk. The Company monitors the creditworthiness of its counterparties, establishes credit limits according to the Company’s credit policies and guidelines, and assesses the impact of a counterparty’s creditworthiness on fair value. The Company has the ability to require cash collateral or letters of credit to mitigate its credit-risk exposure. The Company has netting agreements with financial institutions that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities, and routinely exercises its contractual right to offset net realized gains against realized losses when settling with derivative counterparties.

In addition, the Company has setoff agreements with certain financial institutions that may be exercised in the event of default and provide for contract termination and net settlement across all derivative types. At June 30, 2011, and at December 31, 2010, $333 million of the Company’s $591 million gross derivative liability balance, and $394 million of the Company’s $724 million gross derivative liability balance, respectively, would have been available, in the event of default, for setoff against the Company’s gross derivative asset balance with financial institutions. Other than in the event of default, the Company does not net settle across commodity and interest-rate derivatives, as settlement timing differs.

Some of the Company’s derivative instruments are subject to provisions that can require collateralization of the Company’s obligations. However, most of the Company’s derivative counterparties maintain secured positions with respect to the Company’s derivative liabilities under the Company’s $5.0 billion senior secured revolving credit facility (the $5.0 billion Facility), the available capacity of which is sufficient to secure such obligations.

Derivative counterparties that are not secured under the $5.0 billion Facility may require immediate settlement or full collateralization of derivative liabilities if certain credit-risk-related provisions are triggered, such as the Company’s credit rating declining to a level below investment grade by major credit rating agencies. For these counterparties, at June 30, 2011, and December 31, 2010, the aggregate fair value of all derivative instruments with credit-risk-related contingent features for which a net liability position existed was $6 million (net of collateral) and $10 million (net of collateral), respectively, and is included in accrued expenses on the Company’s Consolidated Balance Sheets.

Fair Value   Fair value of futures contracts is based on quoted prices in active markets for identical assets or liabilities, which represent Level 1 inputs. Valuations of physical-delivery purchase and sale agreements, over-the-counter financial swaps, and commodity option collars are based on similar transactions observable in active markets and industry-standard models that primarily rely on market-observable inputs. Inputs used to estimate the fair value of swaps and options include market-price curves; contract terms and prices; credit-risk adjustments; and, for Black-Scholes option valuations, implied market volatility and discount factors. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

7.  Derivative Instruments (Continued)

 

The following tables set forth, by input level within the fair-value hierarchy, the fair value of the Company’s derivative financial assets and liabilities.

 

June 30, 2011                                         
millions    Level 1      Level 2      Level 3      Netting (1)     Collateral      Total  

Assets:

                

Commodity derivatives

                

Financial institutions

   $      $ 453       $ —        $ (186)      $ (9)       $ 261   

Other counterparties

     —          136         —          (40)        —          96   

Interest-rate and other derivatives

     —                 —          —         —           
                                                    

Total derivative assets

   $      $ 591       $ —        $ (226)      $ (9)       $ 359   
                                                    

Liabilities:

                

Commodity derivatives

                

Financial institutions

   $ (2)       $ (216)       $ —        $ 186       $      $ (27)   

Other counterparties

     —          (53)         —          40         —          (13)   

Interest-rate and other derivatives

     —          (320)         —          —         25         (295)   
                                                    

Total derivative liabilities

   $       (2)       $       (589)       $       —        $       226       $       30       $       (335)   
                                                    

 

(1) 

Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle.

 

December 31, 2010                                          
millions    Level 1      Level 2      Level 3      Netting (1)      Collateral      Total  

Assets:

                 

Commodity derivatives

                 

Financial institutions

   $       $ 557        $ —        $ (298)       $ (15)       $ 247    

Other counterparties

     —          241          —          (148)         —          93    
                                                     

Total derivative assets

   $       $ 798        $ —        $ (446)       $ (15)       $ 340    
                                                     

Liabilities:

                 

Commodity derivatives

                 

Financial institutions

   $ (2)       $ (333)       $ —        $ 298        $ —        $ (37)   

Other counterparties

     —          (154)         —          148          —          (6)   

Interest-rate and other derivatives

     —          (235)         —          —          15          (220)   
                                                     

Total derivative liabilities

   $       (2)       $       (722)       $       —        $       446        $       15        $       (263)   
                                                     

 

(1) 

Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

8.  Debt and Interest Expense

 

Debt   The following presents the Company’s outstanding debt and capital lease obligations. All of the Company’s outstanding debt is senior unsecured.

 

     June 30, 2011    

December 31, 2010

 
millions    Principal      Carrying
Value
    Fair
Value
   

Principal

   Carrying
Value
     Fair
Value
 

Long-term notes and debentures

   $ 14,237      $ 12,504     $ 14,052     $      14,237    $ 12,488      $ 13,459  

WES borrowings

     500        494       515     299      299        299  
                                               

Total borrowings

   $ 14,737      $ 12,998     $ 14,567     $      14,536    $ 12,787      $ 13,758  

Capital lease obligations

     228        228       N/A      226      226        N/A   

Less: Current portion of long-term debt

     424        425       424     289      291        296  
                                               

Total long-term debt

   $       14,541      $ 12,801     $ 14,143     $      14,473    $       12,722      $       13,462  
                                               

Debt Activity    The following presents the Company’s debt activity during the six months ended June 30, 2011.

 

  

millions           Principal     Carrying
Value
   

Description

 

Balance at December 31, 2010

      $ 14,536     $ 12,787          

Borrowings

        560       560     WES credit facility   

Repayments(1)

        (389     (389   WES credit facility and WES term loan   

Other, net

               8     Changes in debt premium or discount   
                           

Balance at March 31, 2011

      $       14,707     $       12,966          
                           

Issuance

        500       494    

WES 5.375% Senior Notes due 2021

  

Repayments(1)

        (470     (470  

WES credit facility

  

Other, net

               8    

Changes in debt premium or discount

  
                           

Balance at June 30, 2011

      $ 14,737     $ 12,998          
                           

 

(1) 

Debt repayment activity includes both scheduled repayments and retirements before scheduled maturity.

WES Revolving Credit Facility   During the first quarter of 2011, WES borrowed $310 million under its $450 million senior unsecured revolving credit facility, primarily to fund the Platte Valley acquisition. In March 2011, WES entered into a five-year $800 million senior unsecured revolving credit facility (RCF), which amended and restated the $450 million senior unsecured revolving credit facility, and borrowed $250 million under the RCF to repay a senior unsecured term loan. During the second quarter of 2011, WES repaid the remaining outstanding RCF borrowings with net proceeds from the public offering of $500 million aggregate principal amount of 5.375% Senior Notes due 2021. At June 30, 2011, WES was in compliance with all covenants contained in the RCF, had no outstanding borrowings under the RCF, and had the full $800 million of RCF borrowing capacity available. Borrowings under the RCF bear interest at LIBOR plus an applicable margin ranging from 1.30% to 1.90%, for a rate of 1.89% at June 30, 2011.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

8.  Debt and Interest Expense (Continued)

 

Interest Expense   The following summarizes the amounts included in interest expense.

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
millions    2011      2010      2011      2010  

Current debt, long-term debt, and other

   $ 250       $ 198       $ 498       $ 407   

Loss on early debt retirements(1)

     —          32         —          72   

Capitalized interest

     (34)         (30)         (62)         (55)   
  

 

 

    

 

 

    

 

 

    

 

 

 

Interest expense

   $       216       $       200       $       436       $       424   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) 

Loss on early debt retirements in 2010 is the result of repurchasing $1.0 billion aggregate principal amount of debt due 2011 and 2012.

9.  Stockholders’ Equity

The reconciliation between basic and diluted EPS from continuing operations attributable to common stockholders is as follows:

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
millions except per-share amounts    2011      2010      2011      2010  

Income (loss):

           

Net income (loss) attributable to common stockholders

   $ 544       $ (40)       $ 760      $ 676  

Less: Distributions on participating securities

            —           1        1  

Less: Undistributed income allocated to participating securities

            —           4        5  
  

 

 

    

 

 

    

 

 

    

 

 

 

Basic

   $ 540       $ (40)       $ 755      $ 670  
  

 

 

    

 

 

    

 

 

    

 

 

 

Diluted

   $ 540       $ (40)       $ 755      $ 670  
  

 

 

    

 

 

    

 

 

    

 

 

 

Shares:

           

Average number of common shares outstanding—basic

     498         495         497        494  

Dilutive effect of stock options and performance-based stock awards

            —          2        2  
  

 

 

    

 

 

    

 

 

    

 

 

 

Average number of common shares outstanding—diluted

     500         495         499        496  
  

 

 

    

 

 

    

 

 

    

 

 

 

Excluded (1)

            13         6        6  

Income (loss) per common share:

           

Basic

   $ 1.09       $       (0.08)       $       1.52      $       1.36  

Diluted

   $ 1.08       $ (0.08)       $ 1.51      $ 1.35  

Dividends per common share

   $       0.09       $ 0.09       $ 0.18      $ 0.18  

 

(1) 

Inclusion of the average shares for these awards would have had an anti-dilutive effect.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

10.  Commitments

In May 2011, Anadarko entered into two five-year lease agreements for deepwater drilling rigs. The rigs are expected to be delivered in late 2013 and early 2014. The lease obligations total approximately $1.2 billion, with aggregate future annual minimum lease payments of $30 million in 2013, $209 million in 2014, $238 million in 2015, and $715 million for the remaining lease term.

11.  Contingencies

The following discussion of the Company’s contingencies excludes the Deepwater Horizon events discussed in Note 2.

General   The Company is a defendant in a number of lawsuits and is involved in governmental proceedings arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims, and environmental claims. The Company has also been named as a defendant in various personal injury claims, including claims by employees of third-party contractors alleging exposure to asbestos, silica, and benzene while working at refineries previously owned by acquired companies. While the ultimate outcome and impact to the Company cannot be predicted with certainty, management believes that the resolution of these proceedings will not have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows.

Litigation   The Company is subject to various claims by its royalty owners in the regular course of business as an oil and gas producer, including disputes regarding measurement, post-production costs and expenses, and royalty valuations. The Company and Kerr-McGee Corporation (Kerr-McGee), a subsidiary of Anadarko, were named as defendants in a case styled U.S. of America ex rel. Harrold E. Wright v. AGIP Petroleum Co., et al. filed in September 2000 in the United States District Court for the Eastern District of Texas, Lufkin Division. This lawsuit generally alleged that the Company, including Kerr-McGee, and other industry defendants violated the False Claims Act by knowingly undervaluing natural gas in connection with royalty payments on production from federal and Indian lands. In June 2011, the Company finalized its settlement of this litigation for approximately $19 million that was previously accrued. The settlement has been approved by the United States government and resolves all claims related to this litigation, as well as several related administrative matters, against Anadarko and Kerr-McGee.

In January 2009, Tronox Incorporated (Tronox), a former wholly owned subsidiary of Kerr-McGee, and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York (Bankruptcy Court). Subsequently, in May 2009, Tronox and certain of its affiliates filed a lawsuit against Anadarko and Kerr-McGee asserting a number of claims, including claims for actual and constructive fraudulent conveyance (Adversary Proceeding). Tronox alleges, among other things, that it was insolvent or undercapitalized at the time it was spun off from Kerr-McGee. Tronox seeks, among other things, to recover an unspecified amount of damages, including interest, from Kerr-McGee and Anadarko as well as litigation fees and costs. In addition, Tronox seeks to equitably subordinate and/or disallow all claims asserted by Anadarko and Kerr-McGee in the bankruptcy cases. Anadarko and Kerr-McGee moved to dismiss the complaint in its entirety. In March 2010, the Bankruptcy Court issued an opinion granting in part and denying in part Anadarko’s and Kerr-McGee’s motion to dismiss the complaint. Notably, the Bankruptcy Court dismissed, with prejudice, Tronox’s request for punitive damages relating to the fraudulent conveyance claims. The Bankruptcy Court granted Tronox leave to replead certain of its common law claims, and Tronox filed an amended complaint in April 2010. In May 2010, Anadarko and Kerr-McGee moved to dismiss three breach of fiduciary duty claims in the amended complaint. In May 2011, the Bankruptcy Court issued an opinion granting in part and denying in part Anadarko’s and Kerr-McGee’s motion to dismiss the three breach of fiduciary duty claims in the amended complaint. The Bankruptcy Court dismissed two claims against Anadarko for conspiracy and aiding and abetting, and declined to dismiss a breach of fiduciary duty claim against Kerr-McGee. Discovery is ongoing. The Adversary Proceeding is set for trial in April 2012.

The United States government was granted authority to intervene in the Adversary Proceeding, and it has asserted separate claims against Anadarko and Kerr-McGee under the Federal Debt Collection Procedures Act. Anadarko and Kerr-McGee have moved to dismiss the claims of the United States government, but that motion has been stayed by the Bankruptcy Court.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

11.  Contingencies (Continued)

 

In August 2010, the Bankruptcy Court entered a Stipulation and Agreed Order among Tronox, Anadarko, and Kerr-McGee authorizing the rejection of the Master Separation Agreement (together with all annexes, related agreements, and ancillary agreements to it, the MSA). Anadarko and Kerr-McGee filed Proofs of Claim, which included claims for damages arising from the MSA rejection. In January 2011, the Bankruptcy Court entered a Stipulation and Agreed Order approving a settlement of Anadarko and Kerr-McGee’s rejection damage claims against Tronox. The settlement provided Anadarko a general unsecured claim against Tronox. In February 2011, in settlement of its claim, Anadarko received shares of Tronox stock, which were assigned to a financial institution in exchange for $46 million, included as a credit to general and administrative expenses in the Company’s Consolidated Statements of Income for the six months ended June 30, 2011. The Company will continue to monitor the impact that the rejection of the MSA may have on other litigation and other proceedings, including the Adversary Proceeding, and will assess the impact of future events on the Company’s consolidated financial position, results of operations, and cash flows.

In February 2011, in accordance with Chapter 11 of the United States Bankruptcy Code, Tronox emerged from bankruptcy pursuant to an August 2010 Bankruptcy Court approved Plan of Reorganization (Plan). The terms of the Plan, which were confirmed by the Bankruptcy Court in the third-quarter of 2010, contemplate that the claims of the United States government (together with other federal, state, local, or tribal governmental entities having regulatory authority or responsibilities for environmental laws, the Governmental Entities) related to Tronox’s environmental liabilities will be settled through certain environmental response trusts and a litigation trust (Anadarko Litigation Trust). The Plan provides that the Governmental Entities will receive, among other things, 88% of the proceeds from the Adversary Proceeding. Additionally, certain creditors asserting tort claims against Tronox may receive, among other things, 12% of the proceeds from the Adversary Proceeding. Certain documents central to the Plan and the Adversary Proceeding were approved by the Bankruptcy Court in the fourth quarter of 2010 and the first quarter of 2011, including, the Environmental Claims Settlement Agreement, the Tort Claims Trust Agreement, the Environmental Response Trust Agreement, and the Anadarko Litigation Trust Agreement. In accordance with the Plan, the Adversary Proceeding will be prosecuted by representatives of the Anadarko Litigation Trust.

In addition, in July 2009, a consolidated class action complaint was filed in the New York District Court on behalf of purported purchasers of Tronox’s equity and debt securities between November 21, 2005, and January 12, 2009 (Class Period), against Anadarko, Kerr-McGee, several former Kerr-McGee officers and directors, several former Tronox officers and directors, and Ernst & Young LLP. The complaint alleges causes of action arising under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 (Exchange Act) for purported misstatements and omissions regarding, among other things, Tronox’s environmental-remediation and tort claim liabilities. The plaintiffs allege, among other things, that these purported misstatements and omissions are contained in certain of Tronox’s public filings, including filings made in connection with Tronox’s initial public offering. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs. Anadarko, Kerr-McGee and other defendants moved to dismiss the consolidated class action complaint and in August 2010 moved to dismiss an amended consolidated class action complaint that had been filed in July 2010. The New York District Court issued the second of two opinions and orders on the motions (Orders). Following the Orders, only the plaintiffs’ Section 20(a) claims under the Exchange Act remain against Anadarko and Kerr-McGee. The plaintiffs’ claims against Anadarko are limited to the period beginning on August 10, 2006, through the end of the Class Period. The discovery process is ongoing.

Given that discovery and motion practice are still underway in the Tronox proceedings, these matters are at a relatively early stage in the litigation process; accordingly, the Company currently cannot assess the probability of losses, or reasonably estimate a range of any potential losses related to the proceedings described above. The Company intends to vigorously defend itself, its officers, and its directors in these proceedings.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

11.  Contingencies (Continued)

 

Deepwater Drilling Moratorium and Other Related Matters   In May and July 2010, the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), previously known as the Minerals Management Service, an agency of the Department of the Interior, issued directives requiring lessees and operators of federal oil and gas leases in the Outer Continental Shelf regions of the Gulf of Mexico and Pacific Ocean to cease drilling all new deepwater wells, including wellbore sidetracks and bypasses, through November 30, 2010 (the Moratorium). Anadarko ceased all drilling operations in the Gulf of Mexico in accordance with the Moratorium, which resulted in the suspension of operations of two operated deepwater wells (Lucius and Nansen) and one non-operated deepwater well (Vito). The Moratorium was lifted effective October 12, 2010; however, Anadarko is awaiting BOEMRE approvals for new and revised exploration plans and drilling permits.

As a result of the Moratorium and additional inspection and safety requirements issued by the BOEMRE in May and June 2010, the Company provided notification of force majeure to drilling contractors of four of the Company’s contracted deepwater rigs in the Gulf of Mexico. Some of the contracts have provisions that authorize contract termination by either party if force majeure conditions continue for a specified number of consecutive days.

In June 2010, the Company gave written notice of termination to the drilling contractor of a rig placed in force majeure in May 2010, and filed a lawsuit in the United States District Court for the Southern District of Houston, Texas (Houston, Texas District Court) against the drilling contractor seeking a judicial declaration that the Company’s interpretation of the drilling contract was correct and that the contract terminated on June 19, 2010. The drilling contractor filed an Original Answer in July 2010 denying the Moratorium constituted a force majeure event and asserted that Anadarko had breached the drilling contract. If the Company does not prevail in its claim, the Company could be obligated to pay the rig contract rate from the contract-termination date through March 2011, the end of the original contract term. The disputed rental for the contract period is $116 million; however, any potential damages would be reduced by, among other things, amounts resulting from the drilling contractor’s ability to mitigate damages by leasing the drilling rig to another third party, as well as cost savings realized by the drilling contractor as a result of not operating the drilling rig for the entire original contract period. At June 30, 2011, the Company has not recognized a liability for costs associated with this dispute as management believes payment related to this matter is not probable. The Company intends to vigorously pursue this claim.

In September 2010, the Company gave written notice of termination to another drilling contractor of a rig that had been placed in force majeure, and the Company filed a lawsuit in the Houston, Texas District Court against the drilling contractor seeking a judicial declaration that the Company’s interpretation of the drilling contract was correct and that the contract terminated on September 18, 2010. The drilling contractor filed a Motion to Dismiss and an Original Answer in October 2010. The Houston, Texas District Court, acting on its discretion, converted the Motion to Dismiss into a Motion for Summary Judgment and entered a scheduling order for submission of briefs during February and March 2011. In May 2011, the Company and the drilling contractor mutually agreed to dismiss all claims related to this dispute. The resolution of this dispute did not have an impact on Anadarko’s consolidated financial position, results of operations or cash flows.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

12.  Income Taxes

Following is a summary of income tax expense (benefit) and effective tax rates.

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
millions except percentages    2011      2010      2011      2010  

Total income tax expense (benefit)

   $       440           $       49          $       706           $       566      

Effective tax rate

     44 %         233 %         47 %         45 %   

The increase from the 35% statutory rate for the three and six months ended June 30, 2011, is primarily attributable to tax expense associated with the accrual of the Algerian exceptional profits tax (which is non-deductible for Algerian income tax purposes), U.S. tax on foreign income, foreign tax rates in excess of the U.S. statutory rate, valuation allowances on foreign losses, state income taxes, and items resulting from business combinations. The increase from the 35% statutory rate for the three and six months ended June 30, 2011, is partially reduced by U.S. income tax benefits associated with foreign losses and the restructuring of foreign operations, and other items.

The increase from the 35% statutory rate for the three and six months ended June 30, 2010, is primarily attributable to tax expense associated with the accrual of the Algerian exceptional profits tax, U.S. tax on foreign income, foreign tax rates in excess of the U.S. statutory rate, valuation allowances on foreign losses, and unfavorable resolution of tax contingencies. The increase from the 35% statutory rate for the three and six months ended June 30, 2010, is partially reduced by U.S. income tax benefits associated with foreign losses, the federal manufacturing deduction, and other items.

13.  Supplemental Cash Flow Information

The following presents cash paid for interest (net of amounts capitalized) and income taxes, as well as non-cash investing transactions.

 

     Six Months Ended
June 30,
 
millions    2011      2010  

Cash paid:

     

Interest

   $       415      $       343  

Income taxes

   $ 82      $ 153  

Non-cash investing activities:

     

Fair value of properties and equipment received in non-cash exchange transactions

   $ 4      $ 18  

Gain related to the fair-value remeasurement of Anadarko’s pre-acquisition 7% equity interest in the Wattenberg Plant

   $ 21      $   

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

14.  Segment Information

Anadarko’s primary business segments are vertically integrated within the oil and gas industry. These segments are separately managed due to distinct operational differences and unique technology, distribution, and marketing requirements. The Company’s three reporting segments are oil and gas exploration and production, midstream, and marketing. The oil and gas exploration and production segment explores for and produces natural gas, crude oil, condensate, and NGLs. The midstream segment engages in gathering, processing, treating, and transporting Anadarko and third-party oil, natural-gas, and NGLs production. The marketing segment sells most of Anadarko’s production, as well as third-party purchased volumes.

During the first quarter of 2011, the chief operating decision maker (CODM) began separately assessing the performance of, and resource allocation to, the WES operating segment. As a result, the midstream operating segment was separated into two operating segments, WES and other midstream activities. The WES and other midstream activities operating segments are aggregated into a single midstream reporting segment due to similar financial and operating characteristics.

To assess the performance of Anadarko’s operating segments, the CODM analyzes income (loss) before income taxes, interest expense, exploration expense, depreciation, depletion, and amortization (DD&A), impairments, and unrealized (gains) losses on derivative instruments, net, less net income attributable to noncontrolling interests (Adjusted EBITDAX). The Company’s definition of Adjusted EBITDAX excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Anadarko’s definition of Adjusted EBITDAX also excludes exploration expense, as exploration expense is not an indicator of operating efficiency for a given reporting period. However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly, DD&A and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. Finally, unrealized (gains) losses on derivative instruments, net are excluded from Adjusted EBITDAX because unrealized (gains) losses are not considered a measure of asset operating performance. Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions to stockholders.

Adjusted EBITDAX may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) attributable to common stockholders and other performance measures, such as operating income or cash flows from operating activities. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes.

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
millions    2011      2010      2011      2010  

Income (loss) before income taxes

   $ 1,002       $ 21      $ 1,505      $ 1,266   

Exploration expense

     236         198        415        353   

DD&A

     985         902        1,970        1,883   

Impairments

     102         115        104        127   

Interest expense

     216         200        436        424   

Unrealized (gains) losses on derivative instruments, net(1)

     (178)         305        75        (240)   

Less: Net income attributable to noncontrolling interests

     18         12        39        24   
  

 

 

    

 

 

    

 

 

    

 

 

 

Consolidated Adjusted EBITDAX

   $       2,345       $       1,729      $       4,466      $       3,789   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) 

In the fourth quarter of 2010, the Company revised the definition of Adjusted EBITDAX to exclude the impact of unrealized (gains) losses on derivative instruments, net. The prior periods have been adjusted to reflect this change.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

14.  Segment Information (Continued)

 

The following presents selected financial information for Anadarko’s reporting segments. Information presented below as “Other and Intersegment Eliminations” includes results from hard-minerals non-operated joint ventures and royalty arrangements, and corporate, financing, and certain hedging activities.

 

millions    Oil and Gas
Exploration
& Production
     Midstream      Marketing      Other and
Intersegment
Eliminations
     Total  

Three Months Ended June 30, 2011:

              

Sales revenues

   $       2,071       $ 98      $       1,565       $       —        $       3,734   

Intersegment revenues

     1,330         223        (1,448)         (105)         —    

Gains (losses) on divestitures and other, net

     (114)         20        —          36         (58)   
                                            

Total revenues and other

     3,287         341        117         (69)         3,676   
                                            

Operating costs and expenses(1)

     930         199        135         88         1,352   

Realized (gains) losses on derivatives, net

     —                  —          (25)         (25)   

Other (income) expense, net

     —                  —          (18)         (18)   

Net income attributable to noncontrolling interests

     —          18        —          —          18   
                                            

Total expenses and other

     930         217        135         45         1,327   
                                            

Unrealized (gains) losses on derivatives, net included in marketing revenue

     —                  (4)         —          (4)   
                                            

Adjusted EBITDAX

   $ 2,357       $       124      $ (22)       $ (114)       $ 2,345   
                                            

Three Months Ended June 30, 2010:

              

Sales revenues

   $ 1,252       $ 45      $ 1,266       $ —        $ 2,563   

Intersegment revenues

     1,058         208        (1,165)         (101)         —    

Gains (losses) on divestitures and other, net

                    —          40         41   
                                            

Total revenues and other

     2,311         253        101         (61)         2,604   
                                            

Operating costs and expenses(1)

     713         162        113         24         1,012   

Realized (gains) losses on derivatives, net

     —                  —          (161)         (161)   

Other (income) expense, net

     —                  —          14         14   

Net income attributable to noncontrolling interests

     —          12        —          —          12   
                                            

Total expenses and other

     713         174        113         (123)         877   
                                            

Unrealized (gains) losses on derivatives, net included in marketing revenue

     —                         —           
                                            

Adjusted EBITDAX

   $ 1,598       $ 79      $ (10)       $ 62       $ 1,729   
                                            

 

(1) 

Operating costs and expenses exclude exploration expense, DD&A, and impairments since these expenses are excluded from Adjusted EBITDAX. For the three months ended June 30, 2010, $17 million has been reclassified from the oil and gas exploration and production segment to the midstream segment to properly reflect the previously reported amounts.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

14.  Segment Information (Continued)

 

millions   Oil and Gas
Exploration
& Production
      Midstream         Marketing       Other and
Intersegment
Eliminations
    Total  

Six Months Ended June 30, 2011:

         

Sales revenues

  $ 3,867      $ 162     $ 2,929      $ —       $ 6,958   

Intersegment revenues

    2,455        433       (2,680)        (208)        —    

Gains (losses) on divestitures and other, net

    (114)        20       —         65        (29)   
                                       

Total revenues and other

    6,208        615       249        (143)        6,929   
                                       

Operating costs and expenses(1)

    1,797        365       271        110        2,543   

Realized (gains) losses on derivatives, net

    —                —         (82)        (82)   

Other (income) expense, net

    —                —         (42)        (42)   

Net income attributable to noncontrolling interests

    —         39       —         —         39   
                                       

Total expenses and other

    1,797        404       271        (14)        2,458   
                                       

Unrealized (gains) losses on derivatives, net included in marketing revenue

    —                (5)        —         (5)   
                                       

Adjusted EBITDAX

  $ 4,411      $ 211     $ (27)      $ (129)      $ 4,466   
                                       

Six Months Ended June 30, 2010:

         

Sales revenues

  $ 2,799      $ 100     $ 2,794      $ —       $ 5,693   

Intersegment revenues

    2,309        432       (2,542)        (199)        —    

Gains (losses) on divestitures and other, net

    (12)               —         62        50   
                                       

Total revenues and other

    5,096        532       252        (137)        5,743   
                                       

Operating costs and expenses(1)

    1,446        349       233        56        2,084   

Realized (gains) losses on derivatives, net

    —                —         (182)        (182)   

Other (income) expense, net

    —                —         23        23   

Net income attributable to noncontrolling interests

    —         24       —         —         24   
                                       

Total expenses and other

    1,446        373       233        (103)        1,949   
                                       

Unrealized (gains) losses on derivatives, net included in marketing revenue

    —                (5)        —         (5)   
                                       

Adjusted EBITDAX

  $     3,650      $         159     $ 14      $         (34)      $         3,789   
                                       

 

(1)

Operating costs and expenses exclude exploration expense, DD&A, and impairments since these expenses are excluded from Adjusted EBITDAX. For the six months ended June 30, 2010, $32 million has been reclassified from the oil and gas exploration and production segment to the midstream segment to properly reflect the previously reported amounts.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

15.  Pension Plans and Other Postretirement Benefits

The Company has non-contributory U.S. defined-benefit pension plans, including both qualified and supplemental plans, and a foreign contributory defined-benefit pension plan. The Company also provides certain health care and life insurance benefits for certain retired employees. Retiree health care benefits are generally funded by contributions from the retiree, and in certain circumstances, contributions from the Company. The Company’s retiree life insurance plan is noncontributory.

During the six months ended June 30, 2011, the Company made contributions of $267 million to its funded pension plans, $2 million to its unfunded pension plans, and $8 million to its unfunded other postretirement benefit plans. Contributions to funded plans increase plan assets while contributions to unfunded plans are used to fund current benefit payments. During the remainder of 2011, the Company expects to contribute approximately $5 million to its funded pension plans, approximately $27 million to its unfunded pension plans, and approximately $10 million to its unfunded other postretirement benefit plans.

The following sets forth the Company’s pension and other postretirement benefit costs.

 

            Pension Benefits                      Other Benefits           
    Three Months Ended
June 30,
    Three Months Ended
June 30,
 
millions   2011     2010     2011     2010  

Components of net periodic benefit cost

       

Service cost

  $ 19      $ 18      $ 2     $  

Interest cost

    22        21        4        

Expected return on plan assets

    (22)        (20)               —    

Amortization of net actuarial loss (gain)

    21        17               —    

Amortization of net prior service cost (credit)

    —         —                (1)   
                               

Net periodic benefit cost

  $         40      $         36      $         6     $         5   
                               
    Pension Benefits     Other Benefits  
    Six Months Ended
June 30,
    Six Months Ended
June 30,
 
millions   2011     2010     2011     2010  

Components of net periodic benefit cost

       

Service cost

  $ 39      $ 35      $ 4     $  

Interest cost

    43        42        8        

Expected return on plan assets

    (43)        (41)               —    

Amortization of net actuarial loss (gain)

    42        34               (1)   

Amortization of net prior service cost (credit)

                       (1)   
                               

Net periodic benefit cost

  $         82      $         71      $         12     $         10   
                               

 

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Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

The Company has made in this report, and may from time to time otherwise make in other public filings, press releases, and management discussions, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning the Company’s operations, economic performance, and financial condition. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, marketing and midstream activities, and also include those statements preceded by, followed by, or that otherwise include the words “may,” “could,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should,” or similar expressions or variations on such expressions. For such statements, the Company claims the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Anadarko undertakes no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events, or otherwise.

These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, the following risks and uncertainties:

 

   

the Company’s assumptions about the energy market;

 

   

production levels;

 

   

reserve levels;

 

   

operating results;

 

   

competitive conditions;

 

   

technology;

 

   

the availability of capital resources, capital expenditures, and other contractual obligations;

 

   

the supply and demand for, the price of, and the commercializing and transporting of natural gas, oil, natural gas liquids (NGLs), and other products or services;

 

   

volatility in the commodity-futures market;

 

   

the weather;

 

   

inflation;

 

   

the availability of goods and services;

 

   

drilling risks;

 

   

future processing volumes and pipeline throughput;

 

   

general economic conditions, either internationally or nationally or in the jurisdictions in which the Company or its subsidiaries are doing business;

 

   

legislative or regulatory changes, including retroactive royalty or production tax regimes; hydraulic-fracturing regulation; deepwater drilling and permitting regulations; derivatives reform; changes in state, federal, and foreign income taxes; environmental regulation; environmental risks; and liability under federal, state, foreign, and local environmental laws and regulations;

 

   

the outcome of events in the Gulf of Mexico related to the Deepwater Horizon events;

 

   

the success of BP Exploration & Production Inc.’s (BP) cleanup efforts related to the Deepwater Horizon events;

 

   

current and potential legal proceedings, and environmental or other obligations arising from the Deepwater Horizon events, the Oil Pollution Act of 1990 (OPA) and other regulatory obligations, and the operating agreement (OA) for the Macondo well;

 

   

the legislative and regulatory changes that may impact the Company’s Gulf of Mexico and international offshore operations resulting from the Deepwater Horizon events;

 

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the Company’s ability to resume drilling operations in the Gulf of Mexico;

 

   

current and potential legal proceedings, environmental or other obligations related to or arising from Tronox Incorporated (Tronox);

 

   

civil or political unrest in a region or country;

 

   

the creditworthiness and performance of the Company’s counterparties, including financial institutions, operating partners, and other parties;

 

   

the securities, capital, or credit markets;

 

   

the Company’s ability to repay its debt;

 

   

the impact of downgrades to the Company’s credit rating, including the ability of the Company to access capital and remain liquid;

 

   

international crude cargo shipping activities;

 

   

physical and electronic cyber security;

 

   

the general economic, supply and demand, technological, political, and commercial conditions associated with long-term development and production projects in domestic and international locations;

 

   

the outcome of any proceedings related to the Algerian exceptional profits tax; and

 

   

other factors discussed below and elsewhere in “Risk Factors” and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates” included in the Company’s 2010 Annual Report on Form 10-K, the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, this Form 10-Q, and in the Company’s other public filings, press releases, and discussions with Company management.

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this report in Item 1, and the information set forth in Risk Factors under Item 1A as well as the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in Item 8 of the 2010 Annual Report on Form 10-K, and the information set forth in the Risk Factors under item 1A of the 2010 Annual Report on Form 10-K. Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.

OVERVIEW

Anadarko Petroleum Corporation is among the world’s largest independent oil and natural-gas exploration and production companies. Anadarko is engaged in the exploration, development, production, and marketing of natural gas, crude oil, condensate, and NGLs. The Company also engages in the gathering, processing, and treating of natural gas, and the transporting of natural gas, crude oil, and NGLs. The Company operates worldwide, including activities in the United States, Algeria, Brazil, East and West Africa, China, Indonesia, and New Zealand.

 

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Operating Highlights

Significant operating highlights during the second quarter of 2011 include the following:

Overall

 

   

The Company achieved liquid sales volumes of 297 thousand barrels of oil equivalent per day (MBOE/d), representing a 13% increase over the second quarter of 2010.

United States Onshore

 

   

The Company’s Rocky Mountains Region (Rockies) achieved second-quarter sales volumes of 299 MBOE/d, representing an 8% increase over the second quarter of 2010.

 

   

The Company’s Southern and Appalachia Region achieved second-quarter sales volumes of 140 MBOE/d, representing a 12% increase over the second quarter of 2010 primarily due to increased drilling in the Maverick basin and Marcellus shale.

 

   

The Company increased its ownership interest in a natural-gas processing plant (Wattenberg Plant), located in northeast Colorado, by acquiring an additional 93% interest for $576 million. The Company operates and now owns a 100% interest in the Wattenberg Plant.

Gulf of Mexico

 

   

The Company’s Gulf of Mexico second-quarter sales volumes were 140 MBOE/d, representing a 14% decrease from the second quarter of 2010.

 

   

The Company successfully tested three wells at the Caesar/Tonga project that demonstrated flow rates of approximately 15 MBOE/d.

 

   

The Company surpassed 900 billion cubic feet (Bcf) of cumulative production at Independence Hub, which began producing in 2007.

International

 

   

The Company’s International second-quarter sales volumes were 91 MBOE/d, representing a 35% increase from the second quarter of 2010 primarily due to the start of liftings in Ghana in 2011.

 

   

The Tweneboa-4 appraisal well (18% working interest) in the Deepwater Tano License offshore Ghana encountered gas condensate in good quality sandstone reservoirs.

Financial Highlights

Significant financial highlights during the second quarter of 2011 include the following:

 

   

The Company’s net income attributable to common stockholders for the second quarter of 2011 totaled $544 million.

 

   

The Company generated $1.8 billion of cash flows from operations and ended the quarter with $3.4 billion of cash on hand.

 

   

Western Gas Partners, LP (WES), a consolidated subsidiary of the Company, completed a public offering of $500 million of 5.375% Senior Notes due 2021. Net proceeds from the offering were primarily used to repay $470 million of outstanding borrowings under WES’s five-year, $800 million senior unsecured revolving credit facility (RCF).

 

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Deepwater Horizon Events

In April 2010, the Macondo well in the Gulf of Mexico, in which Anadarko holds a 25% non-operating leasehold interest, discovered hydrocarbon accumulations. During suspension operations, the well blew out, an explosion occurred on the Deepwater Horizon drilling rig, and the drilling rig sank, resulting in the release of hydrocarbons into the Gulf of Mexico. Eleven people lost their lives in the explosion and subsequent fire, and others sustained personal injuries. In September 2010, the Macondo well was permanently plugged. Refer to Note 2—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for discussion and analysis of these events.

Deepwater Drilling Moratorium and Other Related Matters

Anadarko ceased all drilling operations in the Gulf of Mexico in accordance with the deepwater drilling moratorium (the Moratorium), which resulted in the suspension of operations of two operated deepwater wells (Lucius and Nansen) and one non-operated deepwater well (Vito). The Moratorium was lifted effective October 12, 2010, and the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) is continuing to review plans for new drilling and several applications for drilling permits submitted by Anadarko. The Company is currently positioned to resume exploration and development drilling operations in the Gulf of Mexico, pending approvals of drilling permits and exploration and oil spill-response plans. See Note 11—Contingencies—Deepwater Drilling Moratorium and Other Related Matters in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information on the Moratorium.

The following discussion pertains to Anadarko’s financial condition, results of operations, and changes in financial condition. Any increases or decreases “for the three months ended June 30, 2011,” refer to the comparison of the three months ended June 30, 2011, to the three months ended June 30, 2010, and any increases or decreases “for the six months ended June 30, 2011,” refer to the comparison of the six months ended June 30, 2011, to the six months ended June 30, 2010. The primary factors that affect the Company’s results of operations include, among other things, commodity prices for natural gas, crude oil, and NGLs; sales volumes; the Company’s ability to discover additional oil and natural-gas reserves; the cost of finding such reserves; and operating costs.

 

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RESULTS OF OPERATIONS

Selected Data

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
millions except per-share amounts    2011      2010      2011      2010  

Financial Results

           

Revenues and other

   $       3,676       $       2,604       $       6,929       $       5,743   

Costs and expenses

     2,675         2,227         5,032         4,447   

Other (income) expense

     (1)         356         392         30   

Income tax expense (benefit)

     440         49         706         566   

Net income (loss) attributable to common stockholders

   $ 544       $ (40)       $ 760       $ 676   

Net income (loss) per common share attributable to common stockholders—diluted

   $ 1.08       $ (0.08)       $ 1.51       $ 1.35   

Average number of common shares outstanding—diluted

     500         495         499         496   

Operating Results

           

Adjusted EBITDAX(1)

   $ 2,345       $ 1,729       $ 4,466       $ 3,789   

Sales volumes (MMBOE)

     62         59         124         121   

 

MMBOE—millions of barrels of oil equivalent

(1) 

See Operating Results—Segment Analysis—Adjusted EBITDAX for a description of Adjusted EBITDAX, which is not a U.S. Generally Accepted Accounting Principles (GAAP) measure, and a reconciliation of Adjusted EBITDAX to income (loss) before income taxes, which is presented in accordance with GAAP.

FINANCIAL RESULTS

Net Income (Loss) Attributable to Common Stockholders   For the second quarter of 2011, Anadarko’s net income attributable to common stockholders totaled $544 million, or $1.08 per share (diluted), compared to a net loss attributable to common stockholders of $40 million, or $0.08 per share (diluted) for the second quarter of 2010. For the six months ended June 30, 2011, Anadarko’s net income attributable to common stockholders totaled $760 million, or $1.51 per share (diluted), compared to net income attributable to common stockholders of $676 million, or $1.35 per share (diluted) for the same period of 2010.

Sales Revenues and Volumes

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
millions except percentages    2011      Inc/(Dec)
vs. 2010
     2010      2011      Inc/(Dec)
vs. 2010
     2010  

Sales Revenues

                 

Natural-gas sales

   $ 870         8 %        $ 802       $ 1,724         (8)%        $ 1,883   

Oil and condensate sales

     2,236         67              1,338         4,043         42              2,840   

Natural-gas liquids sales

     370         57              235         703         38               509   
  

 

 

       

 

 

    

 

 

       

 

 

 

Total

   $       3,476         46            $       2,375       $       6,470         24             $       5,232   
  

 

 

       

 

 

    

 

 

       

 

 

 

 

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Anadarko’s sales revenues for the three months ended June 30, 2011, increased primarily due to higher commodity prices and increased liquids sales volumes. Anadarko’s sales revenues for the six months ended June 30, 2011, increased primarily due to higher prices for crude oil and NGLs, as well as increased liquids sales volumes. Lower average natural-gas prices for the six months ended June 30, 2011, partially offset these increased sales revenues.

 

     Three Months Ended June 30,  
millions    Natural
Gas
     Oil and
Condensate
     NGLs      Total  

2010 sales revenues

   $       802       $       1,338       $       235       $       2,375   

Changes associated with sales volumes

            190         22         213   

Changes associated with prices

     67         708         113         888   
  

 

 

    

 

 

    

 

 

    

 

 

 

2011 sales revenues

   $ 870       $ 2,236       $ 370       $ 3,476   
  

 

 

    

 

 

    

 

 

    

 

 

 
     Six Months Ended June 30,  
     Natural
Gas
     Oil and
Condensate
     NGLs      Total  

2010 sales revenues

   $ 1,883       $ 2,840       $ 509       $ 5,232   

Changes associated with sales volumes

            126         64         198   

Changes associated with prices

     (167)         1,077         130         1,040   
  

 

 

    

 

 

    

 

 

    

 

 

 

2011 sales revenues

   $ 1,724       $ 4,043       $ 703       $ 6,470   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
Sales Volumes    2011      Inc/(Dec)
vs. 2010
     2010      2011      Inc/(Dec)
vs. 2010
     2010  
Barrels of Oil Equivalent                  

(MMBOE except percentages)

                 

United States

     54        2 %          53        109        1 %          107  

International

     8        35              6        15        14              14  
  

 

 

       

 

 

    

 

 

       

 

 

 

Total

     62        5              59        124        3              121  
  

 

 

       

 

 

    

 

 

       

 

 

 
Barrels of Oil Equivalent per Day                  

(MBOE/d except percentages)

                 

United States

     594        2              583        602        1              592  

International

     91        35              68        86        14              76  
  

 

 

       

 

 

    

 

 

       

 

 

 

Total

     685        5              651        688        3              668  
  

 

 

       

 

 

    

 

 

       

 

 

 

Sales volumes represent actual production volumes adjusted for changes in commodity inventories. Anadarko employs marketing strategies to minimize market-related shut-ins, maximize realized prices, and manage credit-risk exposure. For additional information, see Other (Income) Expense—(Gains) Losses on Commodity Derivatives, net. Production of natural gas, crude oil, and NGLs is usually not affected by seasonal changes in demand.

 

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Natural-Gas Sales Volumes, Average Prices, and Revenues

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
     2011      Inc/(Dec)
vs. 2010
     2010      2011      Inc/(Dec)
vs. 2010
     2010  

United States

                 

Sales volumes—Bcf

     212        —  %          212        429        — %           427  

        MMcf/d

           2,326        —                     2,324        2,369        —               2,358  

Price per Mcf

   $ 4.11        8             $ 3.79      $ 4.02        (9)           $ 4.41  

Natural-gas sales revenues (millions)

   $ 870        8             $ 802      $       1,724        (8)           $       1,883  

 

Bcf—billion cubic feet

MMcf/d—million cubic feet per day

The Company’s natural-gas sales volumes increased 2 and 11 MMcf/d for the three and six months ended June 30, 2011, respectively, primarily due to increased production in the Rockies of 62 MMcf/d and 63 MMcf/d, respectively, resulting from increased drilling at Greater Natural Buttes, as well as increased production in the Southern and Appalachia Region of 46 MMcf/d and 41 MMcf/d, respectively, associated with increased drilling at the Marcellus shale and Maverick basin. The increase for the three months ended June 30, 2011, was offset by lower sales volumes in the Gulf of Mexico of 106 MMcf/d, primarily due to 2010 natural-gas inventory sales and natural production declines. The increase for the six months ended June 30, 2011, was also partially offset by lower sales volumes in the Gulf of Mexico of 92 MMcf/d, primarily due to 2009 price-related royalty relief that increased 2010 natural-gas sales volumes, and natural production declines.

The average natural-gas price Anadarko received increased for the three months ended June 30, 2011, primarily due to increased demand and lower year-over-year inventory levels. The average natural-gas price Anadarko received decreased for the six months ended June 30, 2011, primarily due to weaker demand at the beginning of 2011 relative to 2010.

 

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Crude-Oil and Condensate Sales Volumes, Average Prices, and Revenues

 

    Three Months Ended
June 30,
    Six Months Ended
June 30,
 
    2011     Inc/(Dec)
vs. 2010
    2010     2011     Inc/(Dec)
  vs. 2010  
    2010  

United States

           

Sales volumes—MMBbls

    12       3 %          12       24       — %          24  

        MBbls/d

    134       3              130       133       —              133  

Price per barrel

  $ 104.68       42            $ 73.89     $ 98.23       32            $ 74.45  

International

           

Sales volumes—MMBbls

    8       35 %          6       15       14 %          14  

        MBbls/d

    91       35              68       86       14              76  

Price per barrel

  $ 115.33       52            $ 75.66     $     107.91       43            $ 75.59  

Total

           

Sales volumes—MMBbls

    20       14 %          18       39       4 %          38  

        MBbls/d

    225       14              198       219       4              209  

Total price per barrel

  $     108.99       46            $ 74.49     $ 102.04       36            $       74.86  

Oil and condensate sales revenues (millions)

  $ 2,236       67            $       1,338     $ 4,043       42            $ 2,840  

 

MMBbls—million barrels

MBbls/d—thousand barrels per day

Anadarko’s crude-oil and condensate sales volumes increased 27 MBbls/d for the three months ended June 30, 2011, primarily due to higher sales volumes of 23 MBbls/d in International, 7 MBbls/d in the Rockies and 6 MBbls/d in the Southern and Appalachia Region, partially offset by a decline of 8 MBbls/d in the Gulf of Mexico. International crude-oil and condensate sales volumes increased with the start of liftings in Ghana in 2011 and as a result of timing of cargo liftings in Algeria. Sales volumes increased in the Rockies at Wattenberg and in the Southern and Appalachia Region at the Maverick basin and Bone Spring as a result of increased drilling in liquids-rich areas. Sales volumes decreased in the Gulf of Mexico at Blind Faith and Garden Banks from natural production declines. For the six months ended June 30, 2011, crude-oil and condensate sales volumes increased 10 MBbls/d due to higher sales volumes of 8 MBbls/d in the Southern and Appalachia Region, primarily in the Maverick basin and Bone Spring and 4 MBbls/d in the Rockies at Wattenberg. Also, International crude-oil and condensate sales volumes increased 10 MBbls/d with the start of liftings in Ghana in 2011, partially offset by lower sales volumes in Algeria due to the timing of cargo liftings. These increases were partially offset by lower sales volumes of 11 MBbls/d in the Gulf of Mexico at Blind Faith from natural production declines and downtime for repairs at the Constitution spar.

Anadarko’s average crude-oil price increased for the three and six months ended June 30, 2011, as a result of increased global demand, as well as supply disruptions and unrest in the Middle East and North Africa. The crude-oil price realized by the Company was enhanced by the widening differential between West Texas Intermediate and Brent crude, as more than 70% of Anadarko’s crude-oil sales volumes are sold based on prices that are either directly indexed or highly correlated to Brent crude.

 

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Natural-Gas Liquids Sales Volumes, Average Prices, and Revenues

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
     2011      Inc/(Dec)
vs. 2010
     2010      2011      Inc/(Dec)
vs. 2010
     2010  

United States

                 

Sales volumes—MMBbls

     6        9 %          6        13        13 %          12  

        MBbls/d

     72        9              66        74        13              66  

Price per barrel

   $       56.21        44            $       39.05      $       52.47        23            $       42.80  

Natural-gas liquids sales revenues (millions)

   $ 370        57            $ 235      $ 703        38            $ 509  

NGLs sales represent revenues from the sale of product derived from the processing of Anadarko’s natural-gas production. The Company’s NGLs sales volumes for the three and six months ended June 30, 2011, increased 6 MBbls/d and 8 MBbls/d, respectively. These increases were the result of the Company’s increased focus on liquids-rich areas and increased drilling at Wattenberg in the Rockies and at the Maverick basin in the Southern and Appalachia Region.

The average NGLs price increased for the three and six months ended June 30, 2011, primarily due to higher crude-oil prices and sustained global petrochemical demand.

Gathering, Processing, and Marketing Margin

 

     Three Months Ended
June  30,
     Six Months Ended
June 30,
millions except percentages    2011      Inc/(Dec)
vs. 2010
     2010      2011      Inc/(Dec)
vs. 2010
    

2010

Gathering, processing, and marketing sales

   $          258        37 %        $          188      $         488        6 %        $         461

Gathering, processing, and marketing expenses

     205        38              149        376        13            332
                                     

Margin

   $ 53        36            $ 39      $ 112         (13)           $         129
                                     

For the three months ended June 30, 2011, the gathering, processing, and marketing margin increased $14 million primarily due to increased natural-gas processing margins resulting from higher NGLs prices and additional margin attributable to newly acquired midstream assets, the Wattenberg Plant and the Platte Valley plant and related gathering systems, both located in northeast Colorado. These increases were partially offset by higher transportation expense due to new transportation agreements effective in January 2011. For the six months ended June 30, 2011, the gathering, processing, and marketing margin decreased $17 million primarily due to lower margins associated with natural-gas sales from inventory and an increase in transportation expense due to new transportation agreements effective January 2011. These decreases were partially offset by increased natural-gas processing margins due to higher NGLs prices, lower prices for natural-gas purchases, and favorable impacts attributable to 2011 asset acquisitions.

Gains (Losses) on Divestitures and Other, net

Gains (losses) on divestitures and other, net for the three and six months ended June 30, 2011, includes a $76 million loss related to the termination of natural-gas processing contracts between the Company and the previous owner of the Wattenberg Plant. The loss represents the aggregate amount by which the contracts were unfavorable as compared to current market transactions for the same or similar services. This loss was partially offset by the recognition of a $21 million gain from the acquisition-date fair-value remeasurement of the Company’s pre-acquisition 7% equity interest in the Wattenberg Plant.

 

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Table of Contents

Costs and Expenses

 

     Three Months Ended
June  30,
     Six Months Ended
June 30,
 
     Inc/(Dec)      Inc/(Dec)  
millions except percentages    2011       vs. 2010       2010      2011       vs. 2010       2010  

Oil and gas operating

   $       236       20 %      $       196      $       468       22 %      $       383  

Oil and gas transportation and other

     207       6            196        416       7            387  

Exploration

     236       19            198        415       18            353  

For the three and six months ended June 30, 2011, oil and gas operating expenses increased by $40 million and $85 million, respectively. The increases for the three and six months ended June 30, 2011, were primarily due to higher workover costs of $20 million and $29 million, respectively, primarily in the Gulf of Mexico and costs associated with first liftings offshore Ghana of $13 million and $27 million, respectively.

For the three and six months ended June 30, 2011, oil and gas transportation and other expenses increased by $11 million and $29 million, respectively, primarily in the Rockies due to increased production volumes, and processing fees that are indexed to NGLs prices. For the three months ended June 30, 2011, oil and gas transportation and other expenses also increased in the Gulf of Mexico due to increased NGLs volumes, and processing fees that are indexed to NGLs prices. In addition, these costs increased for the six months ended June 30, 2011, in the Southern and Appalachia Region primarily due to increased production in the Maverick basin.

For the three and six months ended June 30, 2011, exploration expense increased by $38 million and $62 million, respectively, due to higher geological and geophysical expense of $27 million and $72 million, respectively, primarily associated with increased seismic purchases in the Gulf of Mexico, Rockies, East Africa, and Indonesia, as well as higher dry hole expense of $25 million and $16 million for the three and six months ended June 30, 2011, primarily in West Africa. These increases were partially offset by lower impairments of unproved properties of $19 million and $33 million, respectively, primarily in the Southern and Appalachia Region.

 

     Three Months Ended      Six Months Ended  
     June 30,      June 30,  
     Inc/(Dec)      Inc/(Dec)  
millions except percentages    2011       vs. 2010       2010      2011       vs. 2010       2010  

General and administrative

   $       291       43 %      $       203      $       526       27 %      $       413  

Depreciation, depletion, and amortization

     985       9            902        1,970       5            1,883