ANADARKO PETROLEUM CORP 3RD QTR 2010 FORM 10-Q

 

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 September 30, 2010

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 September 30, 2010 is shown below:

 

Title of Class   Number of Shares Outstanding
Common Stock, par value $0.10 per share   495,592,465


 

TABLE OF CONTENTS

 

PART I.         Page   

Item 1.

  

Financial Statements

  
  

Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2010 and 2009

     3   
  

Consolidated Balance Sheets as of September 30, 2010, and December 31, 2009

     4   
  

Consolidated Statement of Equity for the Nine Months Ended September 30, 2010

     5   
  

Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2010 and 2009

     6   
  

Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2010 and 2009

     7   
  

Notes to Consolidated Financial Statements

     8   

Item 2.

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     43   
  

Financial Results

     46   
  

Operating Results

     56   
  

Liquidity and Capital Resources

     57   
  

Regulatory Matters, Environmental and Additional Factors Affecting Business

     64   
  

Critical Accounting Estimates

     67   

Item 3.

  

Quantitative and Qualitative Disclosures About Market Risk

     68   

Item 4.

  

Controls and Procedures

     70   
PART II.      

Item 1.

  

Legal Proceedings

     71   

Item 1A.

  

Risk Factors

     74   

Item 2.

  

Unregistered Sales of Equity Securities and Use of Proceeds

     80   

Item 6.

  

Exhibits

     81   

 

2


 

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

 

     Three Months Ended
September 30,
     Nine Months Ended
September 30,
 
millions except per-share amounts    2010      2009      2010      2009  

Revenues and Other

           

Gas sales

   $ 809       $ 614       $ 2,692       $ 2,148   

Oil and condensate sales

     1,298         1,218         4,138         2,768   

Natural-gas liquids sales

     227         166         736         365   

Gathering, processing and marketing sales

     182         169         643         531   

Gains (losses) on divestitures and other, net

     34         50         84         114   

Reversal of accrual for DWRRA dispute (Note 12)

     —         657         —          657   
                                   

Total

     2,550         2,874         8,293         6,583   
                                   

Costs and Expenses

           

Oil and gas operating

     207         201         590         660   

Oil and gas transportation and other

     220         169         607         527   

Exploration

     296         224         649         813   

Gathering, processing and marketing

     134         151         466         469   

General and administrative

     275         223         688         658   

Depreciation, depletion and amortization

     962         909         2,845         2,648   

Other taxes

     240         213         809         543   

Impairments

     20                147         79   
                                   

Total

     2,354             2,095         6,801             6,397   
                                   

Operating Income (Loss)

     196         779         1,492         186   

Other (Income) Expense

           

Interest expense

     218         121         642         504   

(Gains) losses on commodity derivatives, net

     (200)         134         (1,052)         503   

(Gains) losses on other derivatives, net

     221         131         656         (315)   

Other (income) expense, net

     (129)         (20)         (106)         (23)   
                                   

Total

     110         366         140         669   
                                   

Income (Loss) Before Income Taxes

     86         413             1,352         (483)   

Income Tax Expense (Benefit)

     94         207         660         (142)   
                                   

Net Income (Loss)

     (8)         206         692         (341)   

Net Income Attributable to Noncontrolling Interests

     18                42         23   
                                   

Net Income (Loss) Attributable to Common Stockholders

   $ (26)       $ 200       $ 650       $ (364)   
                                   

Per Common Share:

           

   Net income (loss) attributable to common stockholders - basic

   $ (0.05)       $ 0.40       $ 1.30       $ (0.77)   

   Net income (loss) attributable to common stockholders - diluted

   $   (0.05)       $ 0.40       $ 1.30       $ (0.77)   

Average Number of Common Shares Outstanding - Basic

     496         491         495         476   
                                   

Average Number of Common Shares Outstanding - Diluted

     496         493         496         476   
                                   

Dividends (per Common Share)

   $ 0.09       $ 0.09       $ 0.27       $ 0.27   

 

See accompanying notes to consolidated financial statements.

 

3


 

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

millions    September 30,
2010
     December 31,
2009
 

ASSETS

     

Current Assets

     

Cash and cash equivalents

   $ 4,218       $ 3,531   

Accounts receivable, net of allowance:

     

   Customers

     848         1,019   

   Others

     1,221         1,033   

Other current assets

     793         500   
                 

Total

     7,080         6,083   
                 

Properties and Equipment

     

Cost

     53,710         50,344   

Less accumulated depreciation, depletion and amortization

     15,999         13,140   
                 

Net properties and equipment

     37,711         37,204   

Other Assets

     1,723         1,514   

Goodwill and Other Intangible Assets

     5,312         5,322   
                 

Total Assets

   $ 51,826       $ 50,123   
                 

LIABILITIES AND EQUITY

     

Current Liabilities

     

Accounts payable

   $ 2,904       $ 2,876   

Accrued expenses

     1,082         948   

Current portion of long-term debt

     718         —    
                 

Total

     4,704         3,824   
                 

Long-term Debt

     12,753         11,149   

Midstream Subsidiary Note Payable to a Related Party

     —          1,599   

Other Long-term Liabilities

     

Deferred income taxes

     9,820         9,925   

Other

     3,405         3,211   
                 

Total

     13,225         13,136   
                 

Equity

     

Stockholders’ Equity

     

Common stock, par value $0.10 per share (1.0 billion shares authorized, 508.6 million and 505.0 million shares issued as of September 30, 2010, and December 31, 2009, respectively)

     51         50   

Paid-in capital

     7,445         7,243   

Retained earnings

     14,382         13,868   

Treasury stock (13.0 million and 12.4 million shares as of September 30, 2010, and December 31, 2009, respectively)

     (756)         (721)   

Accumulated other comprehensive income (loss)

     (493)         (512)   
                 

Total Stockholders’ Equity

     20,629         19,928   

Noncontrolling Interests

     515         487   
                 

Total Equity

     21,144         20,415   
                 

Commitments and Contingencies (Note 2, Note 3 and Note 12)

     
                 

Total Liabilities and Equity

   $     51,826       $     50,123   
                 

See accompanying notes to consolidated financial statements.

 

4


 

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)
    Total
Stockholders’
Equity
    Noncontrolling
Interests
    Total
Equity
 

millions

               

Balance at December 31, 2009

  $ 50      $ 7,243      $ 13,868      $ (721)      $ (512)      $ 19,928      $ 487      $ 20,415   

Net income (loss)

    —         —         650        —         —         650        42        692   

Common stock issued

          202        —         —         —         203        —         203   

Dividends

    —         —         (136)        —         —         (136)        —         (136)   

Repurchase of common stock

    —         —         —         (35)        —         (35)        —         (35)   

Sale of subsidiary units

    —         —         —         —         —         —         97        97   

Distributions to noncontrolling interest owners and other, net

    —         —         —         —         —         —         (111)        (111)   

Previously deferred losses on derivative instruments

    —         —         —         —         13        13        —         13   

Pension and other postretirement plans adjustments

    —         —         —         —                     —          
                                                               

Balance at September 30, 2010

  $     51      $     7,445      $   14,382      $     (756)      $   (493)      $     20,629      $   515      $   21,144   
                                                               

 

 

 

See accompanying notes to consolidated financial statements.

 

5


 

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

 

     Three Months Ended
September 30,
     Nine Months Ended
September 30,
 
millions    2010      2009      2010      2009  

Net Income (Loss)

   $ (8)       $ 206       $ 692       $ (341)   
           

Other Comprehensive Income (Loss), net of taxes

           

Previously deferred losses on derivative instruments (1)

                   13         17   

Foreign currency translation adjustments

     —                 —           

Pension and other postretirement plans adjustments:

           

   Net gain (loss) incurred during period (2)

     —          —          (21)         —    

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

     —          —          (4)         —    

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

                   31         28   
           
                                   

Total

     14         14         19         46   
                                   
           

Comprehensive Income (Loss)

            220         711         (295)   
           

Comprehensive Income Attributable to Noncontrolling Interests

     18                42         23   
                                   
           

Comprehensive Income (Loss) Attributable to Common Stockholders

   $     (12)       $     214       $     669       $     (318)   
                                   

 

(1)

Net of income tax benefit (expense) of $(2) million and $(3) million for the three months ended September 30, 2010 and 2009, respectively, and $(7) million and $(9) million for the nine months ended September 30, 2010 and 2009, respectively.

(2)

Net of income tax benefit (expense) of $12 million for the nine months ended September 30, 2010.

(3)

Net of income tax benefit (expense) of $2 million for the nine months ended September 30, 2010.

(4)

Net of income tax benefit (expense) of $(5) million and $(4) million for the three months ended September 30, 2010 and 2009, respectively, and $(17) million and $(16) million for the nine months ended September 30, 2010 and 2009, respectively.

 

 

See accompanying notes to consolidated financial statements.

 

6


 

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

         Nine Months Ended    
September  30,
 
millions          2010                  2009        

Cash Flow from Operating Activities

     

Net income (loss)

   $ 692       $ (341)   

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

     

   Depreciation, depletion and amortization

     2,845         2,648   

   Deferred income taxes

     (142)         (8)   

   Dry hole expense and impairments of unproved properties

     473         608   

   Impairments

     147         79   

   (Gains) losses on divestitures, net

     (12)         (44)   

   Unrealized (gains) losses on derivatives

     (66)         1,073   

   Reversal of accrual for DWRRA dispute (Note 12)

     —          (657)   

   Other

     145         131   

   Changes in assets and liabilities:

     

 (Increase) decrease in accounts receivable

     15         (139)   

 Increase (decrease) in accounts payable and accrued expenses

     (291)         (180)   

 Other items - net

     126         (344)   
                 

Net cash provided by (used in) operating activities

     3,932         2,826   
                 

Cash Flow from Investing Activities

     

Additions to properties and equipment and dry hole costs

     (3,563)         (2,934)   

Divestitures of properties and equipment and other assets

     44         113   

Other - net

     (30)         (107)   
                 

Net cash provided by (used in) investing activities

     (3,549)         (2,928)   
                 

Cash Flow from Financing Activities

     

Borrowings, net of issuance costs

     3,199         1,975   

Retirements of debt

     (1,173)         (1,470)   

Retirement / repayment of midstream subsidiary note payable to a related party

     (1,599)         (100)   

Increase (decrease) in accounts payable, banks

     (70)         (270)   

Dividends paid

     (136)         (131)   

Repurchase of common stock

     (35)         (17)   

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

     90         1,360   

Sale of subsidiary units

     97         —    

Distributions to noncontrolling interest owners

     (36)         (22)   

Contributions from noncontrolling interest owners

     —           

Other financing activities

     (24)         —    
                 

Net cash provided by (used in) financing activities

     313         1,328   
                 

Effect of Exchange Rate Changes on Cash

     (9)         —    
                 

Net Increase (Decrease) in Cash and Cash Equivalents

     687         1,226   

Cash and Cash Equivalents at Beginning of Period

     3,531         2,360   
                 

Cash and Cash Equivalents at End of Period

   $       4,218       $       3,586   
                 

 

See accompanying notes to consolidated financial statements.

 

7


 

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). The Company also engages in the gathering, processing and treating of natural gas, and transporting 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.

The accompanying financial statements and notes should be read in conjunction with the Company’s 2009 Annual Report on Form 10-K.

Basis of Presentation    The information, as 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 September 30, 2010, and December 31, 2009, the Consolidated Statements of Income and Comprehensive Income for the three and nine months ended September 30, 2010 and 2009, the Consolidated Statements of Cash Flows for the nine months ended September 30, 2010 and 2009, and the Consolidated Statement of Equity for the nine months ended September 30, 2010. Certain prior-period amounts have been reclassified to conform to the current-period presentation.

In the fourth quarter of 2009, the Company changed the manner in which gains and losses on commodity derivatives, used to economically hedge production, are presented within the Consolidated Statements of Income to provide enhanced transparency into asset operating performance. Prior to this change, all realized and unrealized gains and losses on commodity derivatives were reported in gas sales, oil and condensate sales or NGLs sales. Gains and losses on commodity derivatives are now presented as a separate line item on the Consolidated Statements of Income. Prior periods have been reclassified to conform to this presentation. See Note 9 for disclosures regarding derivative instruments.

In preparing financial statements in accordance with accounting principles generally accepted in the United States, management makes informed judgments and estimates that affect both the reported amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Management reviews its estimates periodically, including those related to the carrying value of properties and equipment, proved reserves, goodwill, intangible assets, asset retirement obligations, litigation reserves, environmental liabilities, pension 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.

Environmental Contingencies    Except for environmental contingencies acquired in a business combination, which are recorded at fair value, the Company accrues losses associated with environmental obligations when such losses are probable and can be reasonably estimated. Accruals for estimated environmental losses are recognized no later than at the time the remediation feasibility study, or the evaluation of response options, is complete. These accruals are adjusted as additional information becomes available or as circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable. See Note 2 and Note 12.

Legal Contingencies    The Company is subject to legal proceedings, claims and liabilities that arise in the ordinary course of its business. Except for legal contingencies acquired in a business combination, which are recorded at fair value, the Company accrues losses associated with legal claims when such losses are probable and reasonably estimable. Estimates are adjusted as additional information becomes available or circumstances change. Legal defense costs associated with loss contingencies are expensed in the period incurred. See Note 2, Note 3 and Note 12.

 

8


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

1.  Summary of Significant Accounting Policies (Continued)

 

Changes in Accounting Principles  Effective January 1, 2010, the Company adopted revised oil and gas reserve estimation standards. These standards allow the use of reliable technology in determining estimates of proved reserve quantities and require the use of a 12-month first-day-of-the-month average price to estimate proved reserves. Adoption of these new standards did not have a material impact on depreciation, depletion and amortization expense.

The Company also adopted amendments to consolidation guidance applicable to variable interest entities, effective January 1, 2010. The revised guidance did not have an impact on the Company’s consolidated financial statements.

2.  Deepwater Horizon Events

Background  In April 2010, the Macondo well in the Gulf of Mexico, in which Anadarko holds a 25% non-operating 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. Response and clean-up efforts are being conducted by BP Exploration & Production Inc. (BP), the operator and 65% owner of the well, and by other parties, all under the direction of the Unified Command of the United States Coast Guard (the Unified Command or USCG). On July 15, 2010, after several attempts to contain the oil spill, BP successfully installed a capping stack that shut in the well and prevented the further release of hydrocarbons. Installation of the capping stack was a temporary solution that was followed by a successful “static kill” cementing operation completed on August 5, 2010. The Macondo well was permanently plugged on September 19, 2010, when BP completed a “bottom kill” cementing operation in connection with the successful interception of the well by a relief well. 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 $12.1 billion (including costs associated with USCG invoices totaling $518 million) through September 30, 2010, related to spill response and containment, relief-well drilling, grants to certain Gulf Coast states for clean-up costs, local tourism promotion, monetary damage claims and federal costs. In addition, BP has incurred more than $3.0 billion of costs since September 30, 2010.

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 joint operating agreement (JOA), which is the contract governing the relationship between BP and the non-operating working interest owners of the Mississippi Canyon block 252 lease and the Macondo well. BP has invoiced the Company an aggregate $2.6 billion for what BP considers to be Anadarko’s 25% proportionate share of actual costs through September 30, 2010. 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 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 JOA.

BP, Anadarko and other parties, including parties that do not own an interest in the Macondo well, such as the drilling contractor, have been notified by the USCG of their status as a “responsible party or guarantor” (RP) under the Oil Pollution Act of 1990 (OPA). Under OPA, RPs may be held 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 directly related to the spill and spill cleanup. The USCG has directly billed the RPs for reimbursement of spill-related response costs incurred by the USCG and other federal and state agencies. The RPs have each received identical invoices for total costs, without specification or stipulation of any allocation of costs between or among the RPs. To date, as operator, BP has paid all USCG invoices, thereby satisfying the joint and several obligation of the RPs to the USCG for these costs. BP has also publicly indicated its intention to continue to pay 100% of all costs associated with clean-up efforts, claims and reimbursements related to the Deepwater Horizon events.

 

9


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

The following analysis applies relevant accounting guidance to the Deepwater Horizon events to determine the Company’s liability accrual as of September 30, 2010. 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 upon the qualitative characteristics of such costs. This is appropriate because satisfaction of liability-recognition criteria may vary depending upon the type of costs being analyzed. For example and as discussed more fully below, contingent contractual liabilities (such as those arising under the JOA) 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.

As discussed and analyzed below, 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 September 30, 2010. The zero 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 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 in situations where a loss is not considered probable or cannot be reasonably estimated.

In quantifying its potential Deepwater Horizon event-related liabilities, the Company has made certain assumptions regarding facts that are the subject of continuing investigations, the duration and extent of ongoing clean-up activities, and current and potential future damage claims. Thus, the Company’s zero liability accrual for the Deepwater Horizon events 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 JOA, (ii) OPA-related environmental liabilities, and (iii) other contingent liabilities.

JOA Contingent Liabilities  JOA contingent liabilities relate to Anadarko’s potential responsibility for a 25% share of costs incurred by BP through September 30, 2010, for which BP has sought reimbursement from Anadarko under the JOA. Accounting standards require the Company to accrue contingent liabilities arising under the terms of the JOA 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 JOA 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.

 

10


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

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 a public statement indicating that it disagrees with this assessment. Under the JOA, 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 JOA parties, including Anadarko.

In light of the above, Anadarko does not consider JOA contingent liabilities for Deepwater Horizon event-related costs billed by BP to the Company to satisfy the standard of “probable” required for loss recognition. Accordingly, as of September 30, 2010, pursuant to applicable accounting guidance, the Company has not recognized a liability in its Consolidated Balance Sheets for amounts invoiced by BP under the JOA. In the future, the Company may recognize a liability for amounts invoiced by BP under the JOA if new information arising from the legal discovery 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 JOA contingent obligations.

OPA-related Environmental Liabilities  Under OPA, Anadarko may be held jointly and severally liable with all RPs for OPA-related costs associated with the Deepwater Horizon events. Anadarko’s designation by the USCG as an RP arises as a result of Anadarko’s status as a co-lessee in the lease block in which the Macondo well is located.

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 Macondo well lease block and the subsequent designation 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 for all RPs, a range of total potential OPA-related environmental liabilities 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 the non-operating working interest owners are accounted for as JOA contingent liabilities (discussed above) rather than OPA-related environmental liabilities (discussed herein). Payment by BP satisfied these liabilities for all RPs, including Anadarko, and resulted in BP seeking reimbursement from Anadarko through the JOA, which created a JOA contingent liability. 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 liabilities for all RPs.

 

11


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

Gross OPA-related Environmental Cost-range Estimate  The Company estimates the range of gross OPA-related environmental liabilities for all RPs to be $6.0 billion to $9.0 billion, excluding (i) $12.1 billion of costs incurred by BP as of September 30, 2010, which are considered and analyzed as JOA contingent liabilities, and (ii) amounts the Company currently cannot reasonably estimate, which, as discussed below, include OPA damage claims that may be made subsequent to the end of 2010, potential costs associated with penalties and fines, natural resource damages (NRD) and future NRD assessments, and civil litigation damages. The costs that the Company currently cannot reasonably estimate may be significant.

Anadarko’s gross OPA-related environmental cost-range estimate is comprised of spill-response costs and OPA damage claims. This cost-range estimate is based on information received from BP to date, certain assumptions discussed below, and publicly available information from the Gulf Coast Claims Facility (GCCF). The GCCF is an independent 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 upon 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 clean-up 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.

Spill-Response Costs and Assumptions  These costs include costs associated with the following:

 

   

relief-well drilling;

   

source containment and well control; and

   

spill mitigation and removal costs.

Estimated spill-response costs are based on cost information received from BP, which was used to estimate activity-based run-rates for various 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 clean up.

Relief-well drilling costs include materials, manpower and day rates for two drilling rigs. BP permanently plugged the Macondo well on September 19, 2010, with a “bottom kill” cementing operation that was conducted subsequent to the successful interception of the Macondo well by a relief well. The September 19, 2010, plugging date is approximately thirty days later than the Company’s previous best-case plugging-date estimate and thirty days earlier than the Company’s previous worst-case plugging-date estimate. The Company’s current cost-range estimate includes a one-week well plug-and-abandon period subsequent to the successful “bottom kill” operation. In addition, the Company’s current cost-range estimate includes a demobilization and decontamination period of six weeks for the low-end cost-range estimate and eleven weeks for the high-end cost-range estimate.

 

12


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

 

Source-containment and well-control costs primarily include amounts related to the following:

 

   

the operation of remote-operated vehicles (ROVs) observing the well’s status and working to shut in the well;

   

the containment and subsea collection efforts; and

   

the operation and decontamination of numerous vessels deployed to support operations and collect and/or flare hydrocarbons.

The Company’s previous estimate of source-containment and well-control costs assumed that much of the source-containment activities and equipment would no longer be required after the well was permanently plugged. However, based on information provided to the Company by BP, source-containment and well-control expenses have continued at a cost rate equal to or greater than the cost rate in effect while the spill was ongoing due to resource demobilization occurring more slowly than originally anticipated. Demobilization delays are largely attributable to a prolonged decontamination period for well-site equipment and vessels. The Company has adjusted its previous cost estimate to reflect this information.

Spill mitigation and removal costs primarily include amounts related to the following:

 

   

labor;

   

materials and equipment associated with dispersant application;

   

containment and boom acquisition and deployment;

   

operation and decontamination of support vessels deployed for marine/open water clean up;

   

operation of aircraft;

   

shoreline clean up; and

   

costs related to federal, state and local efforts to coordinate the response and to control the spill.

The Company’s previous estimate for spill mitigation and removal costs was based on the assumption that offshore resources would begin to demobilize once the well was permanently plugged and oil stopped flowing; however, these costs have continued as a result of resource-demobilization timing. Accordingly, the Company has adjusted its previous cost estimate to reflect actual costs incurred by BP and the assumption that marine/open water clean-up and vessel demobilization and decontamination activities will continue for sixty to ninety days subsequent to the permanent plugging of the Macondo well.

The Company’s assumption that marine/open water clean-up activities will cease within sixty to ninety days subsequent to the permanent plugging of the Macondo well is based on the view that hydrocarbons spilled into open water would have been collected, evaporated, dispersed, or degraded within this sixty- to ninety-day period. Based on publicly available reports by BP and the Unified Command that oil reached the most distant beaches within a sixty- to ninety-day period from the onset of the spill, and that no hydrocarbons were released from the Macondo well subsequent to July 15, 2010, the Company’s high-end and low-end cost-range estimates for marine/open water clean-up costs consider delays in executing complete demobilization and decontamination of support vessels.

Based on additional cost information received from BP during the quarter ended September 30, 2010, the Company’s estimate of shoreline clean-up costs has significantly increased. The Company expects shoreline clean-up activities to continue through the end of 2010 and likely longer in some limited areas. For example, where contamination occurs in areas that require prolonged and/or labor-intensive clean up, such as in wetland areas, clean-up activities could extend well beyond the end of 2010, resulting in significantly higher clean-up costs than if the contamination were confined to beach areas. The Company’s cost estimate assumes shoreline clean-up activities will continue through the end of 2010. The Company believes it will be better positioned to reasonably estimate additional shoreline clean-up costs once the scope and extent of required clean-up activities becomes known.

 

13


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

 

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, and lost profits and earning 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 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 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, the average expected per-claim payout, and costs to administer claims and operate claims offices projected through the end of 2010. During the third quarter of 2010, BP transitioned claims administration for most OPA damage claims to the GCCF, which is administered by an independent third party. Since this transition, both the number of claims paid and the average per-claim payout have increased, resulting in a significant increase to the Company’s previous estimate of potential OPA damage claims. According to public statements made by BP, BP is continuing to administer OPA damage claims made by federal and state governments.

The Company believes that claims will continue beyond the end of 2010, but is currently unable to reasonably estimate the amount and extent of future claims or related administrative costs that may be incurred by BP or others. 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 potential OPA damage claims. Accordingly, the Company’s estimates do not include amounts attributable to damage claims that will likely be made subsequent to the end of 2010.

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 liabilities 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 liabilities currently exists. As a result, the Company considered the following factors for purposes of estimating a range of its allocable share of these liabilities:

 

   

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 Company knows of no reason that BP will not continue to pay these costs as they arise. The obligation of the RPs for amounts payable under OPA is satisfied as such amounts are paid. Accordingly, the Company currently estimates its minimum allocable share of gross OPA-related environmental liabilities to be zero, recognizing that once amounts are paid by BP, these liabilities become JOA contingent liabilities (which are discussed above).

 

   

Anadarko’s co-lessee interest in the Macondo well lease block – If BP ceases paying any of these costs, the federal government could seek payment from all RPs (including BP and Anadarko) under the joint and several liability provisions of OPA. Under this scenario, the Company estimates its maximum allocation of gross OPA-related environmental liabilities could be 25%, which is equivalent to Anadarko’s working interest in the Macondo well. This maximum allocation assumes no allocation of costs to non-lessee RPs.

 

   

Allocation to non-lessee RPs – In addition to the three co-lessees of the lease block in which the Macondo well is located (including the Company), two other federal government-designated RPs have been identified for the Deepwater Horizon events (non-lessee RPs). The allocation of costs to all RPs, including the non-lessee RPs, would reduce Anadarko’s potential allocable share of gross OPA-related environmental liabilities to an amount less than Anadarko’s 25% working interest in the Macondo well.

 

14


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

 

Based on the above, the Company has concluded that a range of 0-25% is appropriate for its potential allocable share of gross OPA-related environmental liabilities. Furthermore, due to the potential for BP, despite its statements to the contrary, to cease paying 100% of these costs, and the potential allocation to non-lessee RPs, Anadarko is currently unable to determine that any single allocation percentage within the 0-25% range is more likely to result than another. Accordingly, applicable accounting guidance requires the Company to accrue the liability for its share of allocable gross OPA-related environmental liabilities at the low end of the estimated range, in this case 0%, resulting in zero accrual at September 30, 2010, for potential OPA-related environmental obligations related to the Deepwater Horizon events.

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, Section 311 of 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 the Company. Currently, the Company cannot reasonably estimate the amount of any federal, state or local penalties that could be assessed or the extent to which such penalties 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.

Under the CWA, penalties include civil penalties that apply to events such as the Deepwater Horizon events. Applicable CWA penalties may be assessed in an amount not more than $37,500 per day or $1,100 per barrel of oil discharged. In cases of gross negligence or willful misconduct, such civil penalties may be increased to not less than $140,000 per day and not more than $4,300 per barrel of oil discharged, although several factors (as described below) impact this assessment. At this time, and as discussed more fully below, the Company is unable to determine whether it will be subject to a CWA penalty assessment, and if a CWA penalty were to be individually assessed against the Company, the amount of such penalty.

The CWA states that penalties may be assessed against the “owner, operator or person in charge.” Under the CWA, it is not clear that the Company, as a non-operating interest holder, would, as a matter of law, be assessed penalties based upon the actions of the operator. Accordingly, the Company, as a non-operating working interest owner, does not consider its exposure to potential liability for penalties arising under the CWA to be “probable” at this time.

Notwithstanding the above, the Company has nevertheless considered its potential exposure to a directly assessed CWA penalty, and has concluded that a reasonable estimate of such penalty cannot be made at this time. If assessed, a CWA penalty would likely take into account the total volume of oil spilled. Over the course of the spill, there have been several widely varying estimates of the flow rate from the well 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. Notwithstanding these variables, for the purpose of calculating any potential CWA assessment, the Company has assumed this spill-volume estimate will be utilized, unless a revised or restated spill-volume estimate is released at a later date.

 

15


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

 

Although a spill-volume estimate has been issued, there is significant uncertainty as to the amount of any potential CWA penalty assessment. This uncertainty stems from historic assessments and subsequent settlements of CWA penalties, which generally vary greatly from a simple per-barrel penalty assessment due to the following subjective factors that are routinely taken into account when ultimately determining a CWA penalty:

 

   

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.

The above factors, coupled with general uncertainty as to the federal government’s position regarding the direct assessment of CWA penalties to the Company as a non-operator well owner, and the potential for allocation of CWA penalties among other RPs, prevent the Company from reasonably estimating its exposure to CWA penalties at this time. Thus, the Company currently can neither conclude that its exposure to CWA penalties is “probable” nor reasonably estimate the amount of its potential liability, if any, for CWA penalties.

Natural Resource Damages (NRD)  This category includes costs to assess damages to natural resources resulting from the spill and/or spill clean-up activities as well as future damage claims that may be made by federal and/or state natural resource trustee agencies at the completion of their damage assessments. 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.

Based on information provided by BP to the Company, costs associated with assessing NRD have been incurred by BP through September 30, 2010. According to prior testimony, these amounts are intended to fund costs associated with the trustees’ pre-assessment activities for establishing baseline conditions prior to assessing potential impacts from the spill and spill clean-up efforts. Assessment-funding amounts may change significantly based on the extent and magnitude of the spill impacts and spill clean-up activities, which will not be fully known until the clean-up activities are substantially complete. Thus, the Company is unable to estimate total NRD assessment costs at this time. The Company also anticipates that federal and/or state natural resource trustee agencies may make NRD damage claims against certain parties; however, the Company is unable to reasonably estimate the magnitude of any potential damage claims until spill-response efforts and the NRD assessment is complete, which may take several years.

Civil Litigation Damage Claims  Numerous civil lawsuits have been filed against BP and other parties, including the Company, by fishing, boating and shrimping industry groups; restaurants; commercial and residential property owners; certain rig workers or their families; the city of Greenville, Alabama; the State of Alabama; and certain Mexican states. Many of the lawsuits filed assert various claims of 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.

 

16


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

In July 2010, a public hearing of the United States Judicial Panel on Multidistrict Litigation (JPML) was held to consider motions of various plaintiffs and BP to consolidate Deepwater Horizon event-related lawsuits filed in various federal courts into a consolidated Multidistrict Litigation (MDL) in a single venue. In August 2010, the JPML created MDL No. 2179 to administer essentially all litigation filed in federal court involving Deepwater Horizon event-related claims. Federal Judge Carl Barbier will preside over this MDL in the Eastern District of Louisiana in New Orleans, Louisiana. In October 2010, the court appointed four plaintiffs’ attorneys to serve on a Plaintiff Executive Committee (PEC) and also appointed 15 of the plaintiffs’ attorneys to a Plaintiffs’ Steering Committee (PSC). The PEC will coordinate the responsibilities of the PSC, appear at status conferences representing the PSC, and provide any further administrative or logistical functions as the court may order. In October 2010, the court issued a case management order that initially establishes a schedule for procedural matters, discovery and trial of the MDL cases. The case management order sets, for trial beginning in June 2011, one or more cases brought against BP as an RP under OPA to serve as test cases for liability and damage issues. The court has not yet selected the specific cases to be tried. Also, the court scheduled a February 2012 trial date to determine the limitation and liability allocation issues for the parties involved in the Deepwater Horizon events, which will also address whether Transocean Ltd. can limit its liability under admiralty law to the value of the Deepwater Horizon drilling rig. The parties to the MDL are engaged in document discovery.

Lawsuits seeking to place limitations on the Company’s projects in the Gulf of Mexico have also been filed by non-governmental organizations against various governmental agencies.

In June 2010, a class action complaint was filed in the United States District Court for the Southern District of New York 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 complaint alleges 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.

Also in June 2010, a shareholder derivative petition was filed in the District Court of Harris County, Texas, by a shareholder of the Company against Anadarko (as a nominal defendant) and certain of its officers and current and certain former directors. The petition alleges breaches of fiduciary duties, unjust enrichment, and waste of corporate assets in connection with the Deepwater Horizon events. The plaintiffs seek certain changes to the Company’s governance and internal procedures, disgorgement of profits, and reimbursement of litigation fees and costs. In August 2010, the defendants moved to dismiss the derivative litigation. In September 2010, a purported shareholder made a demand on the Company’s Board of Directors to investigate allegations of breaches of duty by members of management.

These proceedings are at a very early stage; 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.

 

17


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

Liability Outlook  As discussed above, the Company’s aggregate Deepwater Horizon event-related liability accrual of zero as of September 30, 2010, 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. For example, new information arising out of the legal-discovery process could alter the legal assessment as to the likelihood of the Company incurring a liability related to its existing JOA contingent liabilities. Moreover, if BP discontinues payment or is otherwise unable to satisfy its obligations, the Company could be required to recognize an OPA-related environmental liability. Similarly, if other 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 JOA to recover costs from BP or the other working interest owner. In addition, the Company could pursue recovery or contribution from other RPs that are not party to the JOA.

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 interest in the Macondo well, 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 is not considered to have incurred a probable loss under the JOA or an insurable loss for unpaid liabilities. If the Company’s current legal assessment changes such that the Company becomes liable under the JOA for Deepwater Horizon event-related costs and funds such costs, the Company is positioned 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.

 

18


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

 

3.  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 (DOI), 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. These deepwater drilling moratoria (collectively, the Moratorium) prohibited drilling and/or spudding any new wells, and required operators that were in the process of drilling wells to proceed to the next safe opportunity to secure such wells, and to take all necessary steps to cease operations and temporarily abandon the impacted wells. 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, but the Company is unable to resume drilling operations until the BOEMRE approves new 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 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.

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 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 on October 5, 2010. The Company responded to the Motion to Dismiss on October 26, 2010. If the Company does not succeed in its claim, the Company could be obligated to pay the rig contract rate from the contract-termination date through March 2013, the end of the original contract term.

The disputed rentals for the contract periods described above are $90 million and $377 million, respectively, but any potential damages would be reduced by, among other things, any 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 incurred by the drilling contractor by not having to operate the drilling rig on a daily basis. As of September 30, 2010, the Company has not recorded a liability for costs associated with these disputes as management believes payment related to these matters is not probable. The Company intends to vigorously pursue each claim.

In September 2010, the BOEMRE issued a Notice to Lessees that requires lessees to plug all wells that have been idle for the past five years and decommission related equipment. Lessees have 120 days from October 15, 2010, to submit a company-wide plan for decommissioning facilities and wells. The Company is currently evaluating the regulations and is not yet able to determine the effect these new requirements may have on existing asset retirement obligations related to affected wells.

The Company has $3.1 billion and $384 million of unproved property acquisition costs and exploratory drilling costs, respectively, included in net properties and equipment on the Consolidated Balance Sheets at September 30, 2010, related to properties in the Gulf of Mexico that were subject to the Moratorium. As of September 30, 2010, no significant impairment of these properties has been recognized and the Company intends to continue exploration and development of these properties.

 

19


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

 

4.  Goodwill

The Company tests goodwill for impairment annually, at October 1, or more often as facts and circumstances warrant. The first step in the goodwill impairment test is to compare the fair value of each reporting unit to which goodwill has been assigned to the carrying amount of net assets, including goodwill, of the respective reporting unit. Anadarko has allocated goodwill to three reporting units: oil and gas exploration and production; gathering and processing; and transportation. During the second quarter of 2010, a decline in the fair value of Anadarko’s oil and gas exploration and production reporting unit was indicated as a result of the Deepwater Horizon events and general uncertainty arising in connection with the Moratorium and uncertain related regulatory impacts. See Note 2 and Note 3. The Company completed an interim goodwill impairment test of the oil and gas exploration and production reporting unit as of June 30, 2010, and the results of the test indicated no impairment.

At September 30, 2010, the Company had $5.3 billion of goodwill allocated to its three reporting units: $5.2 billion to oil and gas exploration and production; $134 million to gathering and processing; and $5 million to transportation. The Company will complete its annual impairment assessment of goodwill during the fourth quarter of 2010.

Uncertainty related to the Deepwater Horizon events, difficulty or potential delays in obtaining drilling permits, significant declines in commodity prices, or other unanticipated events could result in further goodwill impairment tests in the near term, the results of which may have a material adverse impact on the Company’s results of operations.

5.  Noncontrolling Interests

In the second quarter of 2010, Western Gas Partners, LP (WES), a consolidated subsidiary, issued approximately five million common units to the public, representing limited partner interests. This offering raised proceeds of $97 million, which were recorded as noncontrolling interests. As of September 30, 2010, the balance of noncontrolling interests on the Consolidated Balance Sheets includes approximately $85 million, net of tax, which will be transferred to paid-in capital if and when the WES subordinated limited partner units convert to common units. As of September 30, 2010, Anadarko’s ownership interest in WES consists of a 52.2% limited partner interest (common and subordinated units), a 2% general partner interest and incentive distribution rights.

6.  Inventories

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

 

millions            September 30,
2010
    December 31,
2009
 
Crude oil and NGLs        $ 150     $ 142  
Natural gas          44       94  
                    
Total        $ 194     $ 236  
                    

 

20


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

 

7.  Properties and Equipment

Suspended Exploratory Drilling Costs  The Company’s capitalized suspended well costs at September 30, 2010, and December 31, 2009, were $955 million and $579 million, respectively. The increase primarily relates to the capitalization of costs associated with successful exploration drilling in Brazil, the Maverick basin in the Company’s Southern and Appalachia Region, and in the Gulf of Mexico. This increase includes $48 million of costs incurred for the drilling of the Macondo well, prior to its blowout on April 20, 2010. See Note 2. For the nine months ended September 30, 2010, $30 million of exploratory well costs previously capitalized as suspended well costs for greater than one year, were charged to dry hole expense, and $87 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 as to the economic or operational viability of any of these projects, the associated costs will be expensed at that time.

Impairments  Impairment expense for the three and nine months ended September 30, 2010, was $20 million and $147 million, respectively, including $114 million recognized in the second quarter 2010 related to a production platform included in the oil and gas exploration and production operating segment that remains idle with no immediate plan for use, and for which a limited market currently exists. The platform was impaired to fair value of $25 million, estimated using inputs characteristic of a Level 3 fair-value measurement.

Impairment expense for the three and nine months ended September 30, 2009, was $5 million and $79 million, respectively, of which $5 million and $74 million, respectively, related to certain transportation contracts included in the marketing operating segment that declined in value as a result of changes in price differentials at specific locations. These assets were impaired to fair value using market-based inputs characteristic of a Level 2 fair-value measurement.

8.  Investments

Noncontrolling Mandatorily Redeemable Interests  In 2007, Anadarko contributed certain of its oil and gas properties and gathering and processing assets, with an aggregate fair value of $2.9 billion at the time of the contribution, to newly formed unconsolidated entities in exchange for noncontrolling mandatorily redeemable interests in those entities. Subsequent to their formation, the investee entities loaned Anadarko an aggregate of $2.9 billion. The Company accounts for its investment in these entities under the equity method of accounting. At September 30, 2010, the carrying amount of these investments was $2.8 billion, while the carrying amount of notes payable to affiliates was $2.9 billion. Anadarko has legal right of setoff and intends to net-settle its obligations under each of the notes payable to the investees with the distributable value of its interest in the corresponding investee. Accordingly, the investments and the obligations are presented net on the Consolidated Balance Sheets with the excess of the notes payable to affiliates over the aggregate investment carrying amounts reported in other long-term liabilities - other for all periods presented.

 

21


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

8.  Investments (Continued)

 

Interest on the notes issued by Anadarko is variable, based on the London Interbank Offered Rate (LIBOR) plus a spread that fluctuates with Anadarko’s credit rating. The applicable interest rate was 1.29% and 1.25% at September 30, 2010, and December 31, 2009, respectively. Other (income) expense, net for the three and nine months ended September 30, 2010, includes interest expense on the notes payable to the investee entities of $11 million and $29 million, respectively, and equity earnings from Anadarko’s investments in the investee entities of $(10) million and $(28) million, respectively. Other (income) expense, net for the three and nine months ended September 30, 2009, includes interest expense on the notes payable to the investee entities of $12 million and $48 million, respectively, and equity in earnings from Anadarko’s investments in the investee entities of $(11) million and $(34)million, respectively.

Midstream Financing Arrangement  In December 2007, Anadarko, and an entity formed by a group of unrelated third-party investors (the Investor), formed Trinity Associates LLC (Trinity), a variable interest entity. Trinity was initially capitalized with a $100 million cash contribution by Anadarko in exchange for Class A member and managing member interests in Trinity, and a $2.2 billion cash contribution by the Investor in exchange for a Class B member cumulative preferred interest. Trinity invested $100 million in a United States Government securities money market fund (the Fund) and loaned $2.2 billion to a wholly owned midstream subsidiary of Anadarko (Midstream Holding). See Note 10 for discussion regarding the midstream financing arrangement (Midstream Subsidiary Note). The remaining outstanding balance on the Midstream Subsidiary Note was repaid in full during the third quarter of 2010.

Immediately preceding the repayment of the Midstream Subsidiary Note, Trinity’s assets consisted of $100 million invested in the Fund and the $1.3 billion note receivable from Midstream Holding. Proceeds from repayment of the Midstream Subsidiary Note were distributed to the Investor. Proceeds from Trinity’s liquidation of its investment in the Fund were distributed to Anadarko. Anadarko accounted for its investment in Trinity under the equity method of accounting, and the $100 million distribution received reduced the carrying amount of that investment to zero.

 

22


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

 

9.  Derivative Instruments

Objective and Strategy  The Company utilizes derivative instruments to manage its exposure to cash-flow variability resulting 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 gas production and gas-processing operations (Oil and Gas Production/Processing Derivative Activities). Futures contracts and commodity price swap agreements are used to fix the price of expected future oil and gas sales at major industry trading locations, such as Henry Hub, Louisiana for gas and Cushing, Oklahoma 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 and a ceiling price (collar) for expected future oil and gas sales. Derivative instruments are also used to manage commodity price risk inherent in customer pricing 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 economic transactions to which the derivatives relate are recorded to earnings.

Accumulated other comprehensive loss balances of $131 million ($83 million after tax) and $151 million ($96 million after tax), at September 30, 2010, and December 31, 2009, respectively, primarily relate to interest-rate derivatives that were previously designated as cash-flow hedges.

 

23


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

9.  Derivative Instruments (Continued)

 

Oil and Gas Production/Processing Derivative Activities  Below is a summary of the Company’s derivative instruments related to its oil and gas production as of September 30, 2010. The natural-gas prices listed below are New York Mercantile Exchange (NYMEX) Henry Hub prices. The crude-oil prices listed below reflect a combination of NYMEX Cushing and London Brent Dated prices.

 

                          2010                  2011                  2012        

Natural Gas

               

   Three-Way Collars (thousand MMBtu/d)

        1,630         480         500  

   Average price per MMBtu

             

      Ceiling sold price (call)

        $ 8.23       $ 8.29       $     9.03  

      Floor purchased price (put)

        $ 5.59       $ 6.50       $ 6.50  

      Floor sold price (put)

        $ 4.22       $ 5.00       $ 5.00  

   Fixed-Price Contracts (thousand MMBtu/d)

        90         90           

   Average price per MMBtu

        $ 6.10       $ 6.17       $   

   Basis Swaps (thousand MMBtu/d)

          620         45           

   Average price per MMBtu

        $     (0.98)       $     (1.74)       $   

MMBtu - million British thermal units

  

MMBtu/d - million British thermal units per day

  

     
                    2010      2011      2012  

Crude Oil

               

   Three-Way Collars (MBbls/d)

          129         126         2  

   Average price per barrel

             

      Ceiling sold price (call)

        $ 90.73       $ 99.95       $ 92.50  

      Floor purchased price (put)

        $ 64.34       $ 79.29       $ 50.00  

      Floor sold price (put)

        $ 49.34       $ 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 derivative transactions used to manage commodity price risk. At September 30, 2010, and December 31, 2009, the Company had outstanding physical transactions related to natural gas for 35 billion cubic feet (Bcf) and 46 Bcf, respectively, offset by derivative transactions for 22 Bcf and 17 Bcf, respectively, for net positions of 13 Bcf and 29 Bcf, respectively.

 

24


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

9.  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 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.

Unrealized (gains) losses of $231 million and $655 million on these swap agreements are reported in (gains) losses on other derivatives, net for the three and nine months ended September 30, 2010, respectively. During the second quarter of 2009, the Company realized $552 million in cash after revising the contractual terms of this swap portfolio, increasing the weighted-average interest rate from approximately 3.25% to approximately 4.80%. The realized gains were partially offset by unrealized losses on these agreements of $130 million and $220 million for the three and nine months ended September 30, 2009, respectively.

A summary of the swaps outstanding as of September 30, 2010, including the outstanding notional principal amounts and the associated reference periods, is presented below.

 

millions except percentages    Reference Period          Weighted-Average      

Notional Principal Amount:

                   Start                                     End                     Interest Rate

$       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 %

 

25


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

9.  Derivative Instruments (Continued)

 

Effect of Derivative Instruments - Balance Sheet  The fair value of all derivative instruments is included in the table below.

 

          Gross
Derivative Assets
     Gross
Derivative Liabilities
 

millions

Derivatives

  

Balance Sheet
Classification

   September 30,
2010
     December 31,
2009
     September 30,
2010
     December 31,
2009
 

Commodity

              
  

Other Current Assets

   $       663       $       140       $       (247)       $ (63)   
  

Other Assets

     266         82         (38)         (6)   
  

Accrued Expenses

     38         195         (44)         (417)   
  

Other Liabilities

     26         25         (31)         (52)   
                                      
     993         442         (360)         (538)   
                                      

Interest Rate and Other

              
  

Other Assets

     —          53         —          —    
  

Accrued Expenses

     —          —          (404)         —    
  

Other Liabilities

     —          —          (202)         (3)   
                                      
     —          53         (606)         (3)   
                                      

Total Derivatives

      $ 993       $ 495       $ (966)       $       (541)   
                                      

Effect of Derivative Instruments - Statement of Income  The unrealized and realized gain or loss amounts and classification related to derivative instruments are as follows:

 

          (Gain) Loss  
millions    Classification of (Gain)    Three Months Ended
September 30, 2010
     Nine Months Ended
September 30, 2010
 

Derivatives

  

Loss Recognized

   Realized      Unrealized      Total      Realized      Unrealized      Total  

Commodity

  

Gathering, Processing and Marketing Sales*

   $ —        $ (4)       $ (4)       $      $ (9)       $ (8)   
  

(Gains) Losses on Commodity Derivatives, net

     (157)         (43)             (200)         (339)         (713)             (1,052)   

Interest Rate and Other

  

(Gains) Losses on Other Derivatives, net

     —          221         221         —          656         656   
                                                        

Derivative (Gain) Loss, Net

   $     (157)       $ 174       $ 17       $     (338)       $ (66)       $ (404)   
                                                        

 

*Represents the effect of marketing and trading derivative activities.

 

26


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

9.  Derivative Instruments (Continued)

 

          (Gain) Loss  
millions          Classification of (Gain)          Three Months Ended
September 30, 2009
     Nine Months Ended
September 30, 2009
 

Derivatives

  

Loss Recognized

   Realized      Unrealized      Total      Realized      Unrealized      Total  

Commodity

  

Gathering, Processing and Marketing Sales*

   $      $ 13       $ 20       $ (7)       $ 46       $ 39   
  

(Gains) Losses on Commodity Derivatives, net

     (93)         227         134         (314)         817         503   

Interest Rate

  

(Gains) Losses on Other Derivatives, net

            126         131         (525)         210             (315)   
                                                        

Derivative (Gain) Loss, Net

   $     (81)       $     366       $     285       $     (846)       $     1,073       $ 227   
                                                        

 

*Represents the effect of marketing and trading derivative activities.

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 credit-risk exposure. The Company also routinely exercises its contractual right to net realized gains against realized losses when settling with counterparties.

The Company has netting agreements with financial institutions that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities. In addition, the Company has setoff agreements with certain financial institutions that are triggered in the event of default and provide for contract termination and net settlement across all derivative types. As of September 30, 2010, $528 million of the Company’s $966 million gross derivative liability balance would be 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 the timing of settlement differs.

Most of the Company’s derivative instruments are subject to provisions that can require collateralization of the Company’s obligations. In the event of a credit-rating downgrade to a level below investment grade by major credit rating agencies, the Company’s counterparties may require immediate settlement or full collateralization. In June 2010, the Company’s credit rating was downgraded from “Baa3” to “Ba1” by Moody’s Investors Service (Moody’s), which triggered credit-risk-related features with certain derivative counterparties, resulting in the Company posting additional collateral under its derivative instruments. No counterparties have requested termination or full settlement of derivative positions. As of September 30, 2010, the aggregate fair value of all derivative instruments with credit-risk-related contingent features for which a net liability position existed was $181 million (net of collateral) and is included in accrued expenses on the Company’s Consolidated Balance Sheet.

As discussed in Note 10, in September 2010, the Company closed a $5.0 billion senior secured revolving credit facility (the $5.0 billion Facility), which permits certain of the Company’s derivative counterparties (those extending commitments under the $5.0 billion Facility) to receive security interests in specified assets of the Company, thereby reducing the Company’s requirements to post cash collateral for net derivative liability positions. The Company is actively negotiating the execution of security-interest amendments to the International Swaps and Derivatives Association, Inc. (ISDA) agreements with these counterparties. As these amendments are executed, the Company’s cash collateral requirements will decrease.

 

27


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

9.  Derivative Instruments (Continued)

 

Fair Value  Fair value of futures contracts is based on inputs that represent quoted prices in active markets for identical assets or liabilities, resulting in Level 1 categorization of such measurements. 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 in the Company’s derivative valuations include market-price curves, contract terms and prices, credit-risk adjustments, and, for Black-Scholes option valuations, implied market volatility and discount factors. Because substantially all of the assumptions and inputs for industry-standard models are observable in active markets throughout the full term of the instruments, the Company categorizes each of these measurements as Level 2.

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

 

                                         
September 30, 2010                                        
millions      Level 1          Level 2          Level 3          Netting (1)         Collateral (2)           Total      

Assets:

               

   Commodity derivatives

               

      Financial institutions

   $      $ 744       $ —        $ (269)      $ (20)      $ 461   

      Other counterparties

     —          243         —          (80)               163   

   Interest-rate and other derivatives

     —          —          —                        —    
                                                   

Total derivative assets

   $      $ 987       $ —        $       (349)      $       (20)      $ 624   
                                                   

Liabilities:

               

   Commodity derivatives

               

      Financial institutions

   $ (3)       $ (272)       $ —        $ 269       $      $ (6)   

      Other counterparties

     —          (85)         —          80                (5)   

   Interest-rate and other derivatives

     —          (606)         —          —         222        (384)   
                                                   

Total derivative liabilities

   $       (3)       $       (963)       $       —        $ 349       $ 222      $       (395)   
                                                   

 

(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.

(2)

Cash collateral held by counterparties from Anadarko was $229 million at September 30, 2010, including $7 million for which no net liability position existed at September 30, 2010. Anadarko held $20 million of cash collateral from counterparties at September 30, 2010.

 

28


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

9.  Derivative Instruments (Continued)

 

 

December 31, 2009

                                       
millions      Level 1          Level 2          Level 3          Netting (1)         Collateral (2)         Total    

Assets:

               

   Commodity derivatives

               

      Financial institutions

   $      $ 385       $       —        $       (284)      $     —       $ 105   

      Other counterparties

     —          53         —          (5)        —         48   

   Interest-rate derivatives

     —          53         —          —         —         53   
                                                   

Total derivative assets

   $      $ 491       $ —        $ (289)      $ —       $ 206   
                                                   

Liabilities:

               

   Commodity derivatives

               

      Financial institutions

   $       (6)       $       (520)       $ —        $ 284      $ 44      $ (198)   

      Other counterparties

     —          (12)         —          5        —         (7)   

   Interest-rate derivatives

     —          (3)         —          —         —         (3)   
                                                   

Total derivative liabilities

   $ (6)       $ (535)       $ —        $ 289      $ 44      $       (208)   
                                                   

 

(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.

(2)

Cash collateral held by counterparties from Anadarko was $105 million at December 31, 2009, including $61 million for which no net liability position existed at December 31, 2009. Anadarko held no cash collateral from counterparties at December 31, 2009.

10.  Debt and Interest Expense

Debt  The following table presents the Company’s outstanding debt as of September 30, 2010, and December 31, 2009. See Note 8 for disclosure regarding Anadarko’s notes payable related to its ownership of certain noncontrolling mandatorily redeemable interests that are not included in the Company’s reported debt balance and do not affect consolidated interest expense.

 

     September 30, 2010      December 31, 2009  
millions      Principal          Carrying  
Value
     Fair
  Value  
       Principal          Carrying  
Value
     Fair
  Value  
 

Long-term notes and debentures

   $ 14,659      $ 12,901      $ 13,832      $ 12,909      $ 11,149      $ 12,133  

Midstream subsidiary note payable to a related party

     —          —          —          1,599        1,599        1,599  

WES borrowings

     570        570        570        —          —          —    
                                                     

Total debt

   $ 15,229      $ 13,471      $ 14,402      $ 14,508      $ 12,748      $ 13,732  

Less: Current portion of long-term debt

     717        718        741        —          —          —    
                                                     

Total long-term debt

   $ 14,512      $ 12,753      $ 13,661      $ 14,508      $ 12,748      $ 13,732  
                                                     

 

29


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

10.  Debt and Interest Expense (Continued)

 

In a 2006 private offering, Anadarko received $500 million of loan proceeds upon issuing Zero-Coupon Senior Notes (the Zero Coupons) maturing October 2036. The Zero Coupons have an aggregate principal amount due at maturity of $2.4 billion, reflecting a yield to maturity of 5.24%. The holder had an option to put 82% of the then-accreted value of the Zero Coupons to Anadarko in October 2010 by providing a notice of exercise in September 2010. The holder did not exercise this put right and does not hold a similar put right for 2011; therefore, the full accreted value of the Zero Coupons is reported in long-term debt at September 30, 2010. The holder has the right to cause the Company to repay up to 100% of the then-accreted value of the Zero Coupons in October of each year starting in 2012.

Debt Activity  In March and April 2010, Anadarko completed the repurchase of $1.0 billion aggregate principal amount of its 6.750% and 6.875% Notes due 2011 and 6.125% and 5.000% Notes due 2012 (together, the Notes due 2011 and 2012). The following table presents the debt activity of the Company for the nine months ended September 30, 2010.

 

millions   

Activity

     Principal         Carrying  
Value
   

Description

Balance as of December 31, 2009

      $ 14,508      $ 12,748     

   First Quarter 2010

         
  

Issuance

     750        745     

6.200% Senior Notes due 2040

  

WES borrowing

     210        210     

WES credit facility

  

Retirements

     (528)        (522)     

6.750% Notes due 2011

  

Repayment

     (250)        (250)     

Midstream Subsidiary Note

  

Other, net

     —             

Changes in debt premium or discount

   Second Quarter 2010

         
  

Retirements

     (472)        (479)     

Notes due 2011 and 2012

  

WES repayment

     (100)        (100)     

WES credit facility

  

Other, net

     —          (7)     

Changes in debt premium or discount

   Third Quarter 2010

         
  

Issuance

     2,000        2,000     

6.375% Senior Notes due 2017

  

WES borrowings

     460        460     

WES credit facility and term loan

  

Retirements

     (1,349)        (1,349)     

Midstream Subsidiary Note

  

Other, net

     —             

Changes in debt premium or discount

                     

Balance as of September 30, 2010

      $ 15,229      $ 13,471     
                     

In August 2010, Anadarko issued $2.0 billion principal amount of 6.375% Senior Notes due 2017 (the $2.0 billion Senior Notes) and used $1.3 billion of the proceeds to fully retire the Midstream Subsidiary Note. As a result of issuing the $2.0 billion Senior Notes, Anadarko did not enter into a previously contemplated term-loan facility. In October 2010, the Company redeemed the $422 million outstanding principal balance of 6.750% Senior Notes due in May 2011 for $435 million, including a make-whole redemption premium.

 

30


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

10.  Debt and Interest Expense (Continued)

 

Midstream Subsidiary Note Payable to a Related Party  The principal balance owed by Midstream Holding to Trinity is described in the accompanying Consolidated Balance Sheets as Midstream Subsidiary Note Payable to a Related Party (Midstream Subsidiary Note). The Midstream Subsidiary Note, which had an initial maturity date of December 27, 2012, was retired during the quarter ended September 30, 2010. See Note 8 for additional information regarding the Company’s investment in Trinity.

Anadarko Revolving Credit Facility  As discussed in Note 9, in September 2010, the Company entered into the $5.0 billion Facility, and terminated its $1.3 billion revolving credit agreement, scheduled to mature in 2013. At September 30, 2010, the $5.0 billion Facility was undrawn with available capacity of $4.6 billion ($5.0 billion undrawn capacity less $399 million in outstanding letters of credit supported by the $5.0 billion Facility).

Borrowings under the $5.0 billion Facility will bear interest, at the Company’s election, at (i) LIBOR plus a margin ranging from 2.75% to 3.75%, based on the Company’s credit rating, or (ii) the greatest of (a) the JPMorgan Chase Bank prime rate, (b) the federal funds rate plus 0.50%, and (c) one-month LIBOR plus 1%, and in each case, plus an applicable margin.

Obligations incurred under the $5.0 billion Facility, as well as certain obligations Anadarko has to lenders or their affiliates pursuant to certain derivative instruments discussed in Note 9, are guaranteed by certain of the Company’s wholly owned domestic subsidiaries, and are secured by a perfected first-priority security interest in certain exploration and production assets located in the United States and 65% of the capital stock of certain wholly owned foreign subsidiaries.

The $5.0 billion Facility contains various customary covenants with which Anadarko must comply, including, but not limited to, limitations on incurrence of indebtedness, liens on assets, and asset sales. Anadarko is also required to maintain, at the end of each quarter, (i) a Consolidated Leverage Ratio of no more than 4.5 to 1.0 (relative to Consolidated EBITDAX for the most recent period of four calendar quarters), (ii) a ratio of Current Assets to Current Liabilities of no less than 1.0 to 1.0, and (iii) a Collateral Coverage Ratio of no less than 1.75 to 1.0, in each case, as defined in the $5.0 billion Facility. The Collateral Coverage Ratio is the ratio of an annually redetermined value of pledged assets to outstanding loans under the $5.0 billion Facility. Additionally, to borrow from the $5.0 billion Facility, the Collateral Coverage Ratio must be no less than 1.75 to 1.0 after giving pro forma effect to the requested borrowing. The Company was in compliance with all applicable covenants at September 30, 2010, and there were no restrictions on its ability to utilize the available capacity of the $5.0 billion Facility.

 

31


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

10.  Debt and Interest Expense (Continued)

 

 

WES Revolving Credit Facility   In connection with the acquisition of certain midstream assets from Anadarko in August 2010, WES borrowed $200 million under its senior unsecured revolving credit facility (the RCF). At September 30, 2010, WES was in compliance with the covenants contained in its RCF and had outstanding borrowings of $320 million, with $130 million of available borrowing capacity. The RCF matures in October 2012 and bears interest at LIBOR plus an applicable margin ranging from 2.375% to 3.250%, for a rate of 2.63% at September 30, 2010.

WES Term Loan   Also in August 2010, WES borrowed $250 million under a three-year, unsecured term loan from a group of banks (the Term Loan). The Term Loan contains various customary covenants and bears interest at LIBOR plus an applicable margin ranging from 2.50% to 3.50% (for a rate of 3.26% at September 30, 2010) depending upon WES’s consolidated leverage ratio, as defined in the agreement governing the Term Loan.

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

 

          Three Months Ended      
September 30,
          Nine Months Ended      
September 30,
 
millions         2010                 2009                 2010                 2009        

Current debt, long-term debt and other(1)

  $ 224      $ 129      $ 618      $ 522   

Midstream subsidiary note payable to a related party(2)

    11              24        32   

(Gain) loss on early debt retirements and commitment
termination
(3)

    17        —         89        (2)   

Capitalized interest

    (34)        (17)        (89)        (48)   
                               

Interest expense

  $ 218      $ 121      $ 642      $ 504   
                               

 

(1)

Included in the three- and nine-month periods ended September 30, 2009, is the reversal of the $78 million liability for unpaid interest related to the DWRRA dispute.

(2)

Included in the three- and nine-month periods ended September 30, 2010, is $7 million and $9 million, respectively, of unamortized debt issuance costs associated with the retirement of the Midstream Subsidiary Note.

(3)

(Gain) loss on early retirements of debt in 2010 are the result of repurchasing $1.0 billion aggregate principal amount of debt discussed above. Also included in the three- and nine-month periods ended September 30, 2010, is $17 million for upfront commitment and structuring costs associated with a previously contemplated term-loan facility.

 

32


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

 

11.  Stockholders’ Equity

Common Stock   The reconciliation between basic and diluted earnings per share (EPS) from income attributable to common stockholders is as follows:

 

    Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
millions except per-share amounts         2010                 2009                 2010                 2009        

Income (loss):

  

     

   Net income (loss) attributable to common stockholders

  $ (26)      $ 200      $ 650      $ (364)   

   Less: Distributions on participating securities

    —         —               —    

   Less: Undistributed income allocated to participating securities

    —                     —    
                               

Basic

  $ (26)      $ 198      $ 645      $ (364)   
                               

Diluted

  $ (26)      $ 198      $ 645      $ (364)   
                               

Shares:

       

   Basic

       

 Weighted-average common shares outstanding

    496        491        495        476   

 Dilutive effect of stock options and performance-based stock awards

    —                     —    
                               

   Diluted

    496        493        496        476   
                               

   Excluded (1)

    12                    14   

Income (loss) per common share:

       

   Basic

  $ (0.05)      $ 0.40      $ 1.30      $ (0.77)   

   Diluted

  $ (0.05)      $ 0.40      $ 1.30      $ (0.77)   

   Dividends per common share

  $ 0.09      $ 0.09      $ 0.27      $ 0.27   

 

(1)

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

 

33


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

 

12.  Commitments and Contingencies

The following discussion of the Company’s commitments and contingencies excludes discussion related to the Deepwater Horizon events and the Moratorium. See Note 2 and Note 3.

General  Litigation charges and adjustments of $1 million and $4 million increased income before income taxes for the three and nine months ended September 30, 2010, respectively. Litigation charges and adjustments of $1 million and $46 million decreased income before income taxes for the three and nine months ended September 30, 2009, respectively. The Company is a defendant in a number of lawsuits and is involved in governmental proceedings, 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 predecessors of acquired companies) located in Texas, California and Oklahoma. While the ultimate outcome and impact on 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 was named as a defendant 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. Kerr-McGee Corporation (Kerr-McGee) was also named as a defendant in this legal proceeding. This lawsuit generally alleges that the Company, including Kerr-McGee, and other industry defendants knowingly undervalued natural gas in connection with royalty payments on production from federal and Indian lands. Based on the Company’s present understanding of these various governmental and False Claims Act proceedings, the Company believes that it has substantial defenses to these claims and is vigorously asserting such defenses. However, if the Company is found to have violated the False Claims Act, the Company could be subject to a variety of damages, including treble damages and substantial monetary fines. The claims against the Company have not been set for trial. The Company has reached a tentative settlement with the United States Government and the Relators, which, if finalized, will resolve this litigation against Anadarko and Kerr-McGee, as well as several administrative actions. The tentative settlement must be approved by various levels of authority within the United States Government, which could take up to a year. Management has accrued a liability for the estimated settlement amount. The Company believes that an additional loss, in excess of the amount accrued, is unlikely to have a material adverse effect on Anadarko’s consolidated financial position, results of operations or cash flows.

In January 2009, Tronox Incorporated (Tronox), a former wholly owned subsidiary of Kerr-McGee that held Kerr-McGee’s chemical business, 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 (the 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 (the 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 punitive damages, and 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 Court issued an opinion granting in part and denying in part Anadarko’s and Kerr-McGee’s motion to dismiss the complaint. Notably, the Court dismissed Tronox’s request for punitive damages relating to their fraudulent conveyance claims with prejudice. The Court granted Tronox leave to replead certain of its common law claims, and Tronox filed an amended complaint in April 2010. Anadarko and Kerr-McGee have moved to dismiss three breach of fiduciary duty-related claims in the amended complaint. That motion has been briefed and is awaiting disposition by the Court.

 

34


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

12.  Commitments and Contingencies (Continued)

 

The United States filed a motion to intervene in the Adversary Proceeding, asserting that it has an independent cause of action against Anadarko, Kerr-McGee and Tronox under the Federal Debt Collection Procedures Act relating primarily to environmental cleanup obligations allegedly owed to the United States by Tronox. That motion to intervene has been granted, and the United States is now a co-plaintiff against Anadarko and Kerr-McGee in the Adversary Proceeding. Anadarko and Kerr-McGee have moved to dismiss the United States’ complaint-in-intervention, but that motion currently has been stayed by order of the Court.

In June 2010, Anadarko and Kerr-McGee filed a motion in Tronox’s Chapter 11 cases to compel Tronox to assume or reject the Master Separation Agreement (together with all annexes, related agreements, and ancillary agreements thereto, the MSA). In July 2010, in response to this motion, Tronox announced to the Court that it would reject the MSA effective as of July 22, 2010. In August 2010, the Court entered into a Stipulation and Agreed Order among Tronox, Anadarko, and Kerr-McGee authorizing the rejection of the MSA. Anadarko and Kerr-McGee subsequently filed amended proofs of claim, which include claims for damages arising from such rejection of the MSA. During the quarter ended September 30, 2010, the Company reversed a $95 million liability for the reimbursement obligation that was provided by Kerr-McGee to Tronox pursuant to the terms of the MSA. The Company will continue to monitor events subsequent to the MSA rejection and will assess the impact of future events on the Company’s consolidated financial position, results of operations and cash flows. See Guarantees and Indemnifications section of this Note 12.

In August 2010, Tronox filed a motion seeking, among other things, (i) authority to enter into a certain plan support agreement and equity-commitment agreement (together, the Plan Support Agreements) and (ii) approval of procedures for a rights offering. Anadarko and Kerr-McGee filed an objection to the motion. In the objection, Anadarko and Kerr-McGee requested that the Court order mediation of the Adversary Proceeding. Tronox and the United States opposed mediation, citing, in support of their position, a lack of sufficient discovery. The Court declined to order mediation at this time. In September 2010, the Court entered an order authorizing Tronox to enter into the Plan Support Agreements and approved the rights offering procedures. Anadarko and Kerr-McGee, however, are not subject to the rights offering procedures.

In September 2010, Tronox filed a Proposed First Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy Code (the Plan) and a related disclosure statement (the Disclosure Statement), which modify and supersede the terms of the earlier plan and disclosure statement filed in July 2010. The Plan contemplates, among other things, that (a) the claims of the United States (as well as other federal, state, local or tribal governmental entities having regulatory authority or responsibilities with respect to environmental laws) related to Tronox’s environmental liabilities at legacy sites, will be settled through the creation of certain environmental response trusts and a litigation trust to which Tronox will contribute the following consideration: (i) $270 million in cash, (ii) 88% of the proceeds from the Adversary Proceeding, (iii) certain Nevada assets, including the real property located in Henderson, Nevada, and (iv) certain other insurance and financial assurance assets worth at least $50 million; (b) certain creditors who have asserted tort claims against Tronox will receive the following consideration from a trust to be created under the Plan: (i) $13 million in cash, (ii) 12% of the proceeds from the Adversary Proceeding, and (iii) certain insurance assets, including the net proceeds of certain insurance settlements; (c) certain creditors who have asserted general unsecured claims against Tronox will receive the following consideration: (i) their pro rata share of 16.9% of the common equity of reorganized Tronox and (ii) the right to purchase additional common equity of reorganized Tronox up to a certain amount; (d) certain parties who have asserted claims against Tronox for breach of contract, indemnification, contribution, reimbursement or cost recovery related to environmental monitoring or remediation will receive the following bifurcated consideration: (i) 50% of the claim will receive the same treatment as holders of Class 3 general unsecured claims and (ii) 50% of the claim will receive the same treatment as holders of Class 4 tort claims; and (e) existing equity holders will receive their pro rata share of warrants to purchase the number of shares equivalent to 5% of the common equity of reorganized Tronox if they vote to accept the Plan. Objections to the Disclosure Statement were filed by various interested parties, including Anadarko and Kerr-McGee. The Court has approved the Disclosure Statement and authorized Tronox to begin soliciting votes to accept or reject the Plan. The hearing to consider confirmation of the Plan is currently scheduled for November 17, 2010. It is unclear whether the current Plan will be approved or implemented, and what, if any, effect the Plan might have on the course, cost or outcome of the Adversary Proceeding.

 

35


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

12.  Commitments and Contingencies (Continued)

 

In addition, a consolidated class action complaint has been filed in the United States District Court for the Southern District of New York on behalf of purported purchasers of Tronox’s equity and debt securities between November 21, 2005, and January 12, 2009, 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 pursuant to the Securities Exchange Act of 1934 for purported misstatements and omissions regarding, among other things, Tronox’s environmental-remediation and tort claim liabilities. The plaintiffs allege that these purported misstatements and omissions are contained in certain of Tronox’s public filings, including 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 class action complaint and in June 2010, the Court issued an opinion and order dismissing the plaintiffs’ complaint against Anadarko, but granted the plaintiffs leave to re-plead their claims. The court further granted in part and denied in part the motions to dismiss by Kerr-McGee and certain of its former officers and directors, but permitted plaintiffs leave to re-plead certain of the dismissed claims. Plaintiffs’ amended complaint was filed in July 2010. In August 2010, Anadarko moved to dismiss plaintiffs’ complaint in whole and Kerr-McGee moved to dismiss plaintiffs’ allegations against it in part. The plaintiffs have responded to both motions. Anadarko and Kerr-McGee will file respective briefs in reply during the fourth quarter of 2010.

The Company intends to continue to defend itself vigorously.

Deepwater Royalty Relief Act  In 1995, the United States Congress passed the Deepwater Royalty Relief Act (DWRRA) to stimulate exploration and production of oil and natural gas by providing relief from the obligation to pay royalties on certain federal leases located in the deep waters of the Gulf of Mexico. The Company currently owns interests in several deepwater Gulf of Mexico leases. After the passage of the DWRRA, the Minerals Management Service (MMS) (which was recently renamed the BOEMRE) inserted price thresholds into leases issued in 1996, 1997 and 2000 that effectively eliminated the DWRRA royalty relief if these price thresholds were exceeded.

In January 2006, the DOI issued an order (the 2006 Order) to Kerr-McGee Oil and Gas Corporation (KMOG), a subsidiary of Kerr-McGee, to pay oil and gas royalties and accrued interest on KMOG’s deepwater Gulf of Mexico production associated with eight 1996, 1997 and 2000 leases, for which KMOG considered royalties to be suspended under the DWRRA. KMOG successfully appealed the 2006 Order, and the DOI’s petition for a writ of certiorari with the United States Supreme Court was denied on October 5, 2009.

 

36


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

12.  Commitments and Contingencies (Continued)

 

The MMS issued two additional orders to Anadarko in 2008 and 2009 to pay “past-due” royalties and interest covering several deepwater Gulf of Mexico leases. Anadarko filed administrative appeals with the MMS for the 2008 and 2009 orders (which were stayed pending a final non-appealable judgment relating to the 2006 Order). As a result of the Supreme Court’s denial of certiorari, the MMS notified Anadarko on February 25, 2010, that the 2008 and 2009 orders had been withdrawn.

Guarantees and Indemnifications  Under the terms of the MSA entered into between Kerr-McGee and Tronox, Kerr-McGee agreed to reimburse Tronox for 50% of certain qualifying environmental-remediation costs incurred and paid by Tronox and its subsidiaries before November 28, 2012, subject to certain limitations and conditions. The reimbursement obligation under the MSA was limited to a maximum aggregate reimbursement of $100 million. During the quarter ended September 30, 2010, the Company reversed to non-operating income the remaining $95 million liability recorded for this reimbursement obligation as a result of a court-authorized rejection of the MSA. See Litigation section of this Note 12.

The Company also provides certain indemnifications in relation to asset dispositions. These indemnifications typically relate to disputes, litigation or tax matters existing at the date of disposition. In connection with the 2006 sale of its Canadian subsidiary, the Company indemnified the purchaser for audit adjustments that may be imposed by the Canadian taxing authorities for periods prior to the sale. At September 30, 2010, other long-term liabilities include a $53 million liability for this contingency. The Company believes it is probable that the remaining indemnification will be settled with the purchaser in cash.

Other  The Company’s Consolidated Balance Sheets at September 30, 2010, include a long-term asset and corresponding long-term liability of $237 million, representing the Company’s 27% ownership in and obligation for construction costs to date of a floating production, storage and offloading vessel (FPSO) to be used in its Ghana operations. At December 31, 2009, the Company’s Consolidated Balance Sheets include a liability of $129 million for the Company’s share of FPSO construction costs incurred through December 31, 2009. In May 2010, a lease agreement was executed by the FPSO operator, with lease commencement expected to occur in the fourth quarter 2010, once the vessel has been delivered and accepted. The Company expects to record a capital lease asset and obligation when the lease term begins.

The Company is subject to other legal proceedings, claims and liabilities which arise in the ordinary course of its business. In the opinion of Anadarko, the liability (if any) with respect to these claims will not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.

Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state and local laws and regulations. At September 30, 2010, the Company’s Consolidated Balance Sheets include an $89 million liability for remediation and reclamation obligations. The Company continually monitors the remediation and reclamation process and adjusts its liability for these obligations as necessary.

 

37


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

 

13.  Income Taxes

The following table is a summary of the Company’s income tax expense (benefit) and effective tax rates.

 

     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
millions except percentages        2010             2009             2010             2009      

Income tax expense (benefit)

   $ 94      $ 207      $ 660      $ (142)   

Effective tax rate

     109      50      49      29 

The increase from the 35% statutory rate for the three months ended September 30, 2010, 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 inclusions and distributions, other foreign taxes in excess of the federal statutory rate, and the unfavorable resolution of tax contingencies. This increase in the effective tax rate is partially reduced by U.S. income tax benefits associated with foreign exploration, the federal manufacturing deduction, state income taxes and other items. The increase in the Company’s effective tax rate as compared to the 35% statutory rate for the nine months ended September 30, 2010, is primarily attributable to the accrual of the Algerian exceptional profits tax, U.S. tax on foreign income inclusions and distributions, other foreign taxes in excess of the federal statutory rate, state income taxes and the unfavorable resolution of tax contingencies. This increase in the effective tax rate is partially reduced by U.S. income tax benefits associated with foreign exploration, the federal manufacturing deduction and other items.

The increase from the 35% statutory rate for the three months ended September 30, 2009, is primarily attributable to the accrual of the Algerian exceptional profits tax, U.S. tax on foreign income inclusions and distributions, other foreign taxes in excess of the federal statutory rate, and changes in tax contingencies, partially reduced by U.S. income tax benefits associated with foreign exploration, state income taxes and other items. The decrease from the 35% statutory rate for the nine months ended September 30, 2009, is primarily attributable to benefits associated with changes in tax contingencies and state income taxes, partially reduced by the accrual of the Algerian exceptional profits tax, other foreign taxes in excess of the federal statutory rate, U.S. tax on foreign income inclusions and distributions, and other items.

14.  Supplemental Cash Flow Information

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

 

         Nine Months Ended
September 30,
 
millions             2010               2009       

Cash paid:

      

   Interest

     $ 579      $ 593   

   Income taxes

     $ 209      $ 145   

Non-cash investing activities:

      

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

   $ 32      $ 39   

 

38


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

 

15.  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 reportable operating segments are oil and gas exploration and production, midstream, and marketing. The 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, gas and NGLs production. The marketing segment sells most of Anadarko’s production, as well as third-party purchased volumes.

To assess the operating results of Anadarko’s segments, the chief operating decision maker analyzes income (loss) before income taxes, interest expense, exploration expense, depreciation, depletion and amortization (DD&A) expense and impairments, less net income attributable to noncontrolling interests (Adjusted EBITDAX). Anadarko’s definition of Adjusted EBITDAX 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 expense 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. The Company’s definition of Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. 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 flow from operating activities. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes.

 

           Three Months Ended      
September 30,
          Nine Months Ended      
September 30,
 
millions          2010                 2009                 2010                 2009        

Income (loss) before income taxes

   $ 86      $ 413      $ 1,352      $ (483)   

Exploration expense

     296        224        649        813   

Depreciation, depletion and amortization expense

     962        909        2,845        2,648   

Impairments

     20              147        79   

Interest expense

     218        121        642        504   

Less: Net income attributable to noncontrolling interests

     18              42        23   
                                

Consolidated Adjusted EBITDAX

   $ 1,564      $ 1,666      $ 5,593      $ 3,538   
                                

 

39


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

15.  Segment Information (Continued)

 

 

The following table presents selected financial information for Anadarko’s operating segments. Information presented below as “Other and Intersegment Eliminations” includes results from hard minerals non-operated joint ventures and royalty arrangements, operating activities that are not considered operating segments, as well as corporate, financing and certain hedging activities.

 

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

Three Months Ended September 30, 2010:

         

Sales revenues

  $ 1,320      $ 45      $ 1,151      $ —       $ 2,516   

Intersegment revenues

    950        198        (1,051)        (97)        —    

Gains (losses) on divestitures and other, net

    (3)        —         —         37        34   
                                       

   Total revenues and other

    2,267        243        100        (60)        2,550   
                                       

Operating costs and expenses(1)

    750        127        116        83        1,076   

(Gains) losses on commodity derivatives, net

    —         —         —         (200)        (200)   

(Gains) losses on other derivatives, net

    —         —         —         221        221   

Other (income) expense, net

    —         —         —         (129)        (129)   

Net income attributable to noncontrolling interests

    —         18        —         —         18   
                                       

   Total

    750        145        116        (25)        986   
                                       

Adjusted EBITDAX

  $ 1,517      $ 98      $ (16)      $ (35)      $ 1,564   
                                       

Three Months Ended September 30, 2009:

         

Sales revenues

  $ 1,092      $ 49      $ 1,026      $ —       $ 2,167   

Intersegment revenues

    835        178        (931)        (82)        —    

Gains (losses) on divestitures and other, net

    27        (1)        —         24        50   

Reversal of accrual for DWRRA dispute

    657        —         —         —         657   
                                       

   Total revenues and other

    2,611        226        95        (58)        2,874   
                                       

Operating costs and expenses(1)

    646        135        121        55        957   

(Gains) losses on commodity derivatives, net

    —         —         —         134        134   

(Gains) losses on other derivatives, net

    —         —         —         131        131   

Other (income) expense, net

    —         —         —         (20)        (20)   

Net income attributable to noncontrolling interests

    —               —         —          
                                       

   Total

    646        141        121        300        1,208   
                                       

Adjusted EBITDAX

  $ 1,965      $ 85      $ (26)      $ (358)      $ 1,666   
                                       

 

(1)

Operating costs and expenses exclude exploration, DD&A and impairment expenses since these expenses are excluded from Adjusted EBITDAX.

 

40


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

15.  Segment Information (Continued)

 

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

Nine Months Ended September 30, 2010:

          

Sales revenues

   $ 4,116      $ 145      $ 3,948      $ —       $ 8,209   

Intersegment revenues

     3,259        630        (3,593)        (296)        —    

Gains (losses) on divestitures and other, net

     (15)        —         —         99        84   
                                        

   Total revenues and other

     7,360        775        355        (197)        8,293   
                                        

Operating costs and expenses (1)

     2,228        444        349        139        3,160   

(Gains) losses on commodity derivatives, net

     —         —         —         (1,052)        (1,052)   

(Gains) losses on other derivatives, net

     —         —         —         656        656   

Other (income) expense, net

     —         —         —         (106)        (106)   

Net income attributable to noncontrolling interests

     —         42        —         —         42   
                                        

   Total

     2,228        486        349        (363)        2,700   
                                        

Adjusted EBITDAX

   $ 5,132      $ 289      $     $ 166      $ 5,593   
                                        

Nine Months Ended September 30, 2009:

          

Sales revenues

   $ 2,372      $ 172      $ 3,268      $ —       $ 5,812   

Intersegment revenues

     2,659        511        (2,913)        (257)        —    

Gains (losses) on divestitures and other, net

     41              —         70        114   

Reversal of accrual for DWRRA dispute

     657        —         —         —         657   
                                        

   Total revenues and other

     5,729        686        355        (187)        6,583   
                                        

Operating costs and expenses(1)

     1,887        423        356        191        2,857   

(Gains) losses on commodity derivatives, net

     —         —         —         503        503   

(Gains) losses on other derivatives, net

     —         —         —         (315)        (315)   

Other (income) expense, net

     —         —         —         (23)        (23)   

Net income attributable to noncontrolling interests

     —         23        —         —         23   
                                        

   Total

     1,887        446        356        356        3,045   
                                        

Adjusted EBITDAX

   $ 3,842      $ 240      $ (1)      $ (543)      $ 3,538   
                                        

 

(1)

Operating costs and expenses exclude exploration, DD&A and impairment expenses since these expenses are excluded from Adjusted EBITDAX.

 

41


ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

 

16.  Pension Plans and Other Postretirement Benefits

The Company has non-contributory 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 nine months ended September 30, 2010, the Company made contributions of $89 million to its funded pension plans, $7 million to its unfunded pension plans and $15 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 2010, the Company expects to contribute $2 million to its funded pension plans, $12 million to its unfunded pension plans and $4 million to its unfunded other postretirement benefit plans.

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

 

         Pension Benefits     Other Benefits  
           Three Months Ended  
September 30,
      Three Months Ended  
September 30,
 
millions        2010     2009     2010     2009  

Components of net periodic benefit cost

        

Service cost

   $ 17      $ 13      $     $  

Interest cost

     21        20               

Expected return on plan assets

     (21)        (17)        —         —    

Amortization of actuarial loss (gain)

     16        11        (1)        —    

Amortization of prior service cost (credit)

           —         —         —    
                                  

Net periodic benefit cost

   $ 34      $ 27      $     $  
                                  
         Pension Benefits     Other Benefits  
           Nine Months Ended  
September 30,
      Nine Months Ended  
September 30,
 
millions        2010     2009     2010     2009  

Components of net periodic benefit cost

        

Service cost

   $ 52      $ 40      $     $  

Interest cost

     63        59        12        13   

Expected return on plan assets

     (62)        (53)        —         —    

Amortization of actuarial loss (gain)

     48        36        (2)        (1)   

Amortization of prior service cost (credit)

                 (1)        (1)   

Settlements

     —         10        —         —    
                                  

Net periodic benefit cost

   $ 103      $ 93      $ 16      $ 17   
                                  

 

42


 

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 discussions with Company management, 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 and the price 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 and 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) response and clean-up 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 joint operating agreement (JOA) for the Macondo well;

   

the legislative and regulatory changes, such as delays in the processing and approval of drilling permits, that may impact the Company’s Gulf of Mexico and International offshore operations resulting from the deepwater drilling moratoria (collectively, the Moratorium), which was recently lifted;

   

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

   

the creditworthiness of the Company’s financial counterparties and operating partners;

   

the securities, capital or credit markets;

 

43


   

the Company’s ability to repay its debt;

   

the impact of downgrades to the Company’s credit rating, the ability of the Company to post required collateral, if requested, and the Company’s ability to improve its credit rating;

   

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 2009 Annual Report on Form 10-K, the Company’s Quarterly Report on Form 10-Q for the quarters ended March 31 and June 30, 2010, 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 2009 Annual Report on Form 10-K, and the information set forth in Risk Factors under Item 1A of the 2009 Annual Report on Form 10-K.

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 transporting natural gas, crude oil and NGLs. The Company’s operations are located in the United States, Algeria, Brazil, China, Cote d’Ivoire, Ghana, Indonesia, Mozambique, Sierra Leone and several other countries. Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.

DEEPWATER HORIZON EVENTS

In April 2010, the Macondo well in the Gulf of Mexico, in which Anadarko holds a 25% non-operating 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 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, but the Company is unable to resume drilling operations until the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) approves new drilling permits. Refer to Note 3—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.

 

44


 

OPERATING HIGHLIGHTS

Significant operational highlights by area during the third quarter of 2010 include the following:

United States Onshore

   

The Company’s Rocky Mountain Region (Rockies) achieved third-quarter sales volumes of 274 thousand barrels of oil equivalent per day (MBOE/d), representing a 10% increase over the third quarter of 2009.

   

The Company’s Southern and Appalachia Region achieved third-quarter sales volumes of 128 MBOE/d, representing a 9% increase over the third quarter of 2009.

Gulf of Mexico

   

For information on the Deepwater Horizon events, see Note 2—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

   

There was no drilling activity in the third quarter due to the Moratorium, see Note 3—Deepwater Drilling Moratorium and Other Related Matters in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

   

The Company’s Gulf of Mexico third-quarter sales volumes were 148 MBOE/d, representing a 9% decrease from the third quarter of 2009.

International

   

The Owo discovery well (18% working interest) encountered 174 net feet of high-quality oil pay in the Deepwater Tano Block offshore Ghana.

   

The Owo sidetrack well (18% working interest) encountered an additional 115 net feet of pay in the Deepwater Tano Block offshore Ghana, including 52 net feet of high-quality oil pay, 43 net feet of condensate pay and 20 net feet of natural gas pay.

   

The Ironclad prospect (43% working interest) in Mozambique was drilled to a total depth of 17,400 feet. The well encountered oil saturated sands in a tight reservoir, but did not encounter commercial quantities of hydrocarbons and was plugged and abandoned.

   

The Wahoo South well offshore Brazil in BM-C-30 (30% working interest) was drilled to a depth of 17,056 feet. Hydrocarbons were encountered; however, the evaluation program did not prove the hydrocarbons to be recoverable and the well was plugged and abandoned.

FINANCIAL HIGHLIGHTS

Significant financial highlights during the third quarter of 2010 include the following:

 

   

The Company generated $1.0 billion of cash flow from operations and ended the quarter with $4.2 billion of cash on hand.

   

In August 2010, the Company completed a public offering of $2.0 billion of 6.375% Senior Notes due 2017 (the $2.0 billion Senior Notes), and used a portion of the net proceeds to retire $1.3 billion of outstanding indebtedness maturing in 2012. Also, in October 2010, the Company redeemed $422 million of 6.750% Senior Notes due in May 2011.

   

In September 2010, the Company entered into a five-year $5.0 billion senior secured revolving credit facility (the $5.0 billion Facility), which replaced the Company’s $1.3 billion revolving credit agreement scheduled to mature in 2013.

 

45


 

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 September 30, 2010” refer to the comparison of the three months ended September 30, 2010 to the three months ended September 30, 2009, and any increases or decreases “for the nine months ended September 30, 2010” refer to the comparison of the nine months ended September 30, 2010 to the nine months ended September 30, 2009. 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.

RESULTS OF OPERATIONS

Selected Data

 

     Three Months Ended
September 30,
     Nine Months Ended
September 30,
 
millions except per-share amounts    2010      2009      2010      2009  

Financial Results

           

Total revenues and other(1)

   $ 2,550       $ 2,874       $ 8,293       $ 6,583   

Costs and expenses

     2,354         2,095         6,801         6,397   

Other (income) expense(1)

     110         366         140         669   

Income tax expense (benefit)

     94         207         660         (142)   

Net income (loss) attributable to common stockholders

   $ (26)       $ 200       $ 650       $ (364)   

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

   $ (0.05)       $ 0.40       $ 1.30       $ (0.77)   

Average number of common shares outstanding - diluted

     496         493         496         476   

Operating Results

           

Adjusted EBITDAX(2)

   $ 1,564       $ 1,666       $ 5,593       $ 3,538   

Sales volumes (MMBOE)

     58         57         179         167   

 

MMBOE—million barrels of oil equivalent

(1)

Commodity derivative activity previously reported in Total revenues and other, has been reclassified to Other (income) expense. See Basis of Presentation in Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

(2)

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 third quarter of 2010, Anadarko’s net loss attributable to common stockholders was $26 million or $0.05 per share (diluted). This compares to net income attributable to common stockholders of $200 million or $0.40 per share (diluted) for the third quarter of 2009. For the nine months ended September 30, 2010, Anadarko’s net income attributable to common stockholders was $650 million or $1.30 per share (diluted), compared to a net loss attributable to common stockholders of $364 million or $0.77 per share (diluted) for the same period of 2009.

 

46


 

Sales Revenues, Volumes and Prices

 

     Three Months Ended
September 30,
     Nine Months Ended
September 30,
 
millions except percentages    2010        Inc/(Dec)  
vs. 2009
     2009      2010        Inc/(Dec)  
vs. 2009
     2009  

Gas sales

   $ 809         32 %        $ 614       $ 2,692         25 %        $ 2,148   

Oil and condensate sales

     1,298         7             1,218         4,138         49             2,768   

Natural-gas liquid sales

     227         37             166         736         102             365   
                                         

Total

   $     2,334         17           $     1,998       $     7,566         43           $     5,281   
                                         

Anadarko’s sales revenues for the three and nine months ended September 30, 2010, increased primarily due to higher commodity prices and increased production volumes, as follows:

 

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

2009 sales revenues

   $ 614       $ 1,218       $ 166       $ 1,998   

   Changes associated with sales volumes

     25         (80)         34         (21)   

   Changes associated with prices

     170         160         27         357   
                                   

2010 sales revenues

   $ 809       $ 1,298       $ 227       $     2,334   
                                   
     Nine Months Ended September 30,  
     Natural
Gas
     Oil and
Condensate
     NGLs      Total  

2009 sales revenues

   $ 2,148       $ 2,768       $ 365       $ 5,281   

   Changes associated with sales volumes

     49         249         145         443   

   Changes associated with prices

     495         1,121         226         1,842   
                                   

2010 sales revenues

   $     2,692       $     4,138       $     736       $     7,566   
                                   

 

47


 

The following table provides Anadarko’s sales volumes for the three and nine months ended September 30, 2010, compared to 2009.

 

     Three Months Ended
September 30,
     Nine Months Ended
September 30,
 
         2010            Inc/(Dec)  
vs. 2009
         2009              2010            Inc/(Dec)  
vs. 2009
         2009      

Barrels of Oil Equivalent

                 

   (MMBOE except percentages)

                 

United States

     52         4 %          51         160         8 %          148   

International

            (11)                    19         1             19   
                                         

Total

     58         2             57         179         7             167   
                                         

Barrels of Oil Equivalent per Day

                 

   (MBOE/d except percentages)

                 

United States

     568         4             547         584         8             541   

International

     61         (11)             69         71         1             70   
                                         

Total

     629         2             616         655         7             611   
                                         

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 below. Production of natural gas, crude oil and NGLs is usually not affected by seasonal swings in demand.

Natural-Gas Sales Volumes, Average Prices and Revenues

 

     Three Months Ended
September 30,
     Nine Months Ended
September 30,
 
         2010            Inc/(Dec)  
vs. 2009
         2009              2010            Inc/(Dec)  
vs. 2009
         2009      

United States

                 

   Sales volumes—Bcf

     205         4 %          197         632         2 %          618   

                               MMcf/d

     2,234         4             2,144         2,316         2             2,264   

   Price per Mcf

   $ 3.94         27           $ 3.11       $ 4.26         23           $ 3.47   

   Gas sales revenues (millions)  

   $ 809         32           $     614       $     2,692         25           $     2,148   

 

Bcf—billion cubic feet

MMcf/d—million cubic feet per day

The Company’s daily natural-gas sales volumes increased 90 MMcf/d for the three months ended September 30, 2010. This increase was primarily a result of higher volumes in the Rockies due to increased drilling activity, partially offset by lower sales volumes related to maintenance downtime in the Gulf of Mexico. The Company’s daily natural-gas sales volumes increased 52 MMcf/d for the nine months ended September 30, 2010. The increase resulted from higher volumes in the Rockies as discussed above and increased drilling in the Maverick Basin, Haynesville Shale and Marcellus Shale.

The average natural-gas price Anadarko received increased for the three and nine months ended September 30, 2010, primarily attributable to an increase in demand.

 

48


 

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

 

     Three Months Ended
September 30,
     Nine Months Ended
September 30,
 
         2010            Inc/(Dec)  
vs. 2009
         2009              2010            Inc/(Dec)  
vs. 2009
         2009      

United States

                 

   Sales volumes—MMBbls

     12         (4)%          13         37         14 %          32   

                               MBbls/d

     131         (4)             136         133         14              117   

   Price per barrel

   $     72.65         14           $ 63.75       $     73.85         37            $ 53.73   

International

                 

   Sales volumes—MMBbls

            (11)%                 19         1 %          19   

                               MBbls/d

     61         (11)             69         71         1              70   

   Price per barrel

   $ 75.83         14            $ 66.28       $ 75.66         37            $ 55.27   

Total

                 

   Sales volumes—MMBbls

     18         (6)%          19         56         9 %          51   

                               MBbls/d

     192         (6)             205         204         9              187   

   Total price per barrel

   $ 73.67         14           $ 64.60       $ 74.48         37            $ 54.31   

   Total oil and condensate sales

            revenues (millions)                    

   $ 1,298         7           $ 1,218       $ 4,138         49            $ 2,768   

 

MMBbls—million barrels

MBbls/d—thousand barrels per day

Anadarko’s daily crude-oil and condensate sales volumes decreased 13 MBbls/d for the three months ended September 30, 2010, primarily due to natural production declines and construction downtime in the Gulf of Mexico, and scheduling of cargo liftings in Algeria. Partially offsetting these decreases were increases in crude-oil sales volumes as a result of the Company’s migration from drilling in dry-gas areas to drilling in liquid-rich areas in the Rockies and Southern and Appalachia Region. Anadarko’s daily crude-oil and condensate sales volumes increased 17 MBbls/d for the nine months ended September 30, 2010. This increase was primarily due to higher crude-oil sales volumes of 12 MBbls/d in the Gulf of Mexico due to the third-quarter 2009 completion of repairs to third-party downstream infrastructure that was damaged during the 2008 hurricane season, and additional production that came online during the second quarter of 2009. In addition, crude-oil sales volumes increased due to the migration from drilling in dry-gas areas to drilling in liquid-rich areas in the Rockies and Southern and Appalachia Region.

Anadarko’s average crude-oil price increased for the three and nine months ended September 30, 2010, as a result of increased global demand.

 

49


 

Natural-Gas Liquids Sales Volumes, Average Prices and Revenues

 

     Three Months Ended
September 30,
     Nine Months Ended
September 30,
 
         2010            Inc/(Dec)  
vs. 2009
         2009              2010            Inc/(Dec)  
vs. 2009
         2009      

United States

                 

   Sales volumes—MMBbls

            21 %                 18         40 %          13   

                               MBbls/d

     65         21             54         65         40             47   

   Price per barrel

   $     38.11         14           $     33.41       $     41.23         44           $     28.58   

   Natural-gas liquids sales revenues (millions)

   $ 227         37           $ 166       $ 736         102           $ 365   

NGLs sales represent revenues from the sale of product derived from the processing of Anadarko’s natural-gas production. The Company’s daily NGLs sales volumes for the three and nine months ended September 30, 2010, increased 11 MBbls/d and 18 MBbls/d, respectively. These increases were primarily driven by operations in the Rockies where natural-gas production increased, an additional natural-gas processing train was brought online late in the second quarter of 2009 and new processing agreements were entered into late in 2009, partially offset by maintenance downtime on a natural-gas processing train in the Rockies during the three months ended September 30, 2010.

The average NGLs price increased for the three and nine months ended September 30, 2010, primarily due to higher crude-oil prices and sustained global petrochemical demand.

Gathering, Processing and Marketing Margin

 

     Three Months Ended
September 30,
     Nine Months Ended
September 30,
 
millions except percentages        2010            Inc/(Dec)  
vs. 2009
         2009              2010            Inc/(Dec)  
vs. 2009
         2009      

Gathering, processing and marketing sales

   $     182         8 %        $     169       $     643         21 %        $     531   

Gathering, processing and marketing expenses

     134         (11)             151         466         (1)             469