ANADARKO PETROLEUM CORP 2ND QTR 2010 FORM 10-Q
Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

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

EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 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 June 30, 2010 is shown below:

 

Title of Class   Number of Shares Outstanding
Common Stock, par value $0.10 per share   494,929,464


Table of Contents

TABLE OF CONTENTS

 

     Page
PART I
  Item 1.  

Financial Statements

  
 

Consolidated Statements of Income for the Three and Six Months Ended June 30, 2010 and 2009

   3
 

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

   4
 

Consolidated Statement of Equity for the Six Months Ended June 30, 2010

   5
 

Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2010 and 2009

   6
 

Consolidated Statements of Cash Flows for the Six Months Ended June 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

   40
 

Financial Results

   43
 

Operating Results

   52
 

Liquidity and Capital Resources

   53
 

Regulatory Matters, Environmental and Additional Factors Affecting Business

   60
 

Critical Accounting Estimates

   61
  Item 3.  

Quantitative and Qualitative Disclosures About Market Risk

   62
  Item 4.  

Controls and Procedures

   64
PART II   
  Item 1.  

Legal Proceedings

   65
  Item 1A.  

Risk Factors

   68
  Item 2.  

Unregistered Sales of Equity Securities and Use of Proceeds

   75
  Item 6.  

Exhibits

   76

 

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Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
millions except per-share amounts    2010     2009     2010     2009  

Revenues and Other

        

Gas sales

   $ 802      $ 663      $ 1,883      $ 1,534   

Oil and condensate sales

     1,338        914        2,840        1,550   

Natural-gas liquids sales

     235        116        509        199   

Gathering, processing and marketing sales

     188        201        461        362   

Gains (losses) on divestitures and other, net

     41        19        50        64   
                                

Total

     2,604        1,913        5,743        3,709   
                                

Costs and Expenses

        

Oil and gas operating

     196        218        383        459   

Oil and gas transportation and other

     196        184        387        358   

Exploration

     198        288        353        589   

Gathering, processing and marketing

     149        183        332        318   

General and administrative

     203        226        413        435   

Depreciation, depletion and amortization

     902        933        1,883        1,739   

Other taxes

     268        180        569        330   

Impairments

     115        23        127        74   
                                

Total

     2,227        2,235        4,447        4,302   
                                

Operating Income (Loss)

     377        (322     1,296        (593

Other (Income) Expense

        

Interest expense

     200        201        424        383   

(Gains) losses on commodity derivatives, net

     (264     168        (852     369   

(Gains) losses on other derivatives, net

     406        (348     435        (446

Other (income) expense, net

     14        8        23        (3
                                

Total

     356        29        30        303   
                                

Income (Loss) Before Income Taxes

     21        (351     1,266        (896

Income Tax Expense (Benefit)

     49        (135     566        (349
                                

Net Income (Loss)

     (28     (216     700        (547

Net Income Attributable to Noncontrolling Interests

     12        10        24        17   
                                

Net Income (Loss) Attributable to Common Stockholders

   $ (40   $ (226   $ 676      $ (564
                                

Per Common Share:

        

Net income (loss) attributable to common stockholders – basic

   $ (0.08   $ (0.48   $ 1.36      $ (1.21

Net income (loss) attributable to common stockholders – diluted

   $ (0.08   $ (0.48   $ 1.35      $ (1.21

Average Number of Common Shares Outstanding – Basic

     495        477        494        468   
                                

Average Number of Common Shares Outstanding – Diluted

     495        477        496        468   
                                

Dividends (per Common Share)

   $ 0.09      $ 0.09      $ 0.18      $ 0.18   

See accompanying notes to consolidated financial statements.

 

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

millions        June 30,    
2010
        December 31,    
2009
 

ASSETS

    

Current Assets

    

Cash and cash equivalents

   $ 3,374      $ 3,531   

Accounts receivable, net of allowance:

    

Customers

     957        1,019   

Others

     1,149        1,033   

Other current assets

     594        500   
                

Total

     6,074        6,083   
                

Properties and Equipment

    

Cost

     52,654        50,344   

Less accumulated depreciation, depletion and amortization

     15,035        13,140   
                

Net properties and equipment

     37,619        37,204   

Other Assets

     1,541        1,514   

Goodwill and Other Intangible Assets

     5,313        5,322   
                

Total Assets

   $ 50,547      $ 50,123   
                

LIABILITIES AND EQUITY

    

Current Liabilities

    

Accounts payable

   $ 2,778      $ 2,876   

Accrued expenses

     982        948   

Current portion of long-term debt

     909          
                

Total

     4,669        3,824   
                

Long-term Debt

     10,093        11,149   

Midstream Subsidiary Note Payable to a Related Party

     1,349        1,599   

Other Long-term Liabilities

    

Deferred income taxes

     9,746        9,925   

Other

     3,485        3,211   
                

Total

     13,231        13,136   
                

Equity

    

Stockholders’ Equity

    

Common stock, par value $0.10 per share (1.0 billion shares authorized, 507.8 million and 505.0 million shares issued as of June 30, 2010, and December 31, 2009, respectively)

     51        50   

Paid-in capital

     7,407        7,243   

Retained earnings

     14,454        13,868   

Treasury stock (12.9 million and 12.4 million shares as of June 30, 2010, and December 31, 2009, respectively)

     (750     (721

Accumulated other comprehensive income (loss)

     (507     (512
                

Total Stockholders’ Equity

     20,655        19,928   

Noncontrolling Interests

     550        487   
                

Total Equity

     21,205        20,415   
                

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

    
                

Total Liabilities and Equity

   $ 50,547      $ 50,123   
                

See accompanying notes to consolidated financial statements.

 

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

 

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

               676                      676        24        700   

Common stock issued

     1      164                           165               165   

Dividends

               (90                   (90            (90 )

Repurchase of common stock

                      (29            (29            (29

Sale of subsidiary units

                                           97        97   

Distributions to noncontrolling interest owners and other, net

                                           (58     (58

Previously deferred losses

                  

on derivative instruments

                             8        8               8   

Pension and other postretirement plans adjustments

                             (3     (3            (3
                                                              

Balance at June 30, 2010

   $ 51    $ 7,407    $ 14,454      $ (750   $ (507   $ 20,655      $ 550      $ 21,205   
                                                              

See accompanying notes to consolidated financial statements.

 

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
millions    2010     2009     2010     2009  

Net Income (Loss)

   $ (28   $ (216   $ 700      $ (547

Other Comprehensive Income (Loss), net of taxes

        

Previously deferred losses on derivative instruments(1)

     4        6        8        12   

Pension and other postretirement plans adjustments:

        

Net gain (loss) incurred during period (2)

     4               (21       

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

     (4            (4       

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

     11        12        22        20   
                                

Total

     15        18        5        32   
                                

Comprehensive Income (Loss)

     (13     (198     705        (515

Comprehensive Income Attributable to Noncontrolling Interests

     12        10        24        17   
                                

Comprehensive Income (Loss) Attributable to Common Stockholders

   $ (25   $ (208   $ 681      $ (532
                                

 

(1)

Net of income tax benefit (expense) of $(3) million and $(3) million for the three months ended June 30, 2010 and 2009, respectively, and $(5) million and $(6) million for the six months ended June 30, 2010 and 2009, respectively.

(2)

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

(3)

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

(4)

Net of income tax benefit (expense) of $(6) million and $(7) million for the three months ended June 30, 2010 and 2009, respectively, and $(12) million and $(12) million for the six months ended June 30, 2010 and 2009, respectively.

See accompanying notes to consolidated financial statements.

 

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

     Six Months Ended
June 30,
 
millions    2010     2009  

Cash Flow from Operating Activities

    

Net income (loss)

   $ 700      $ (547

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

    

Depreciation, depletion and amortization

     1,883        1,739   

Deferred income taxes

     (97     (242

Dry hole expense and impairments of unproved properties

     244        452   

Impairments

     127        74   

(Gains) losses on divestitures, net

     (15     (18

Unrealized (gains) losses on derivatives

     (240     707   

Other non-cash items

     206        83   

Changes in assets and liabilities:

    

(Increase) decrease in accounts receivable

     5        138   

Increase (decrease) in accounts payable and accrued expenses

     (229     (157

Other items – net

     299        (468
                

Net cash provided by (used in) operating activities

     2,883        1,761   
                

Cash Flow from Investing Activities

    

Additions to properties and equipment and dry hole costs

     (2,413     (2,120

Divestitures of properties and equipment and other assets

     19        61   

Other – net

     (78     (15
                

Net cash provided by (used in) investing activities

     (2,472     (2,074
                

Cash Flow from Financing Activities

    

Borrowings, net of issuance costs

     947        1,975   

Retirements of debt

     (1,173     (1,470

Repayment of midstream subsidiary note payable to a related party

     (250       

Increase (decrease) in accounts payable, banks

     (93     (257

Dividends paid

     (90     (87

Repurchase of common stock

     (29     (9

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

     81        1,342   

Sale of subsidiary units

     97          

Distributions to noncontrolling interest owners

     (22     (14

Other financing activities

     (7       
                

Net cash provided by (used in) financing activities

     (539     1,480   
                

Effect of Exchange Rate Changes on Cash

     (29       
                

Net Increase (Decrease) in Cash and Cash Equivalents

     (157     1,167   

Cash and Cash Equivalents at Beginning of Period

     3,531        2,360   
                

Cash and Cash Equivalents at End of Period

   $ 3,374      $ 3,527   
                

See accompanying notes to consolidated financial statements.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.  Summary of Significant Accounting Policies

General  Anadarko Petroleum Corporation is engaged in the exploration, development, production and marketing of natural gas, crude oil, condensate and natural gas liquids (NGLs). 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 June 30, 2010, and December 31, 2009, the Consolidated Statements of Income and Comprehensive Income for the three and six months ended June 30, 2010 and 2009, the Consolidated Statements of Cash Flows for the six months ended June 30, 2010 and 2009, and the Consolidated Statement of Equity for the six months ended June 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. Previously, 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.

 

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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, but did result in expanded disclosures related to the Company’s maximum exposure to loss and conclusions regarding control and consolidation. See Note 8.

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 (USCG), which is under the jurisdiction of the United States Department of Homeland Security. BP has made several attempts, with varying degrees of success, to contain the oil spill, including the installation of a capping stack which has at least temporarily shut in the well. Despite this development, efforts to permanently plug the well have not yet been successful. Based on public information, BP currently expects such plugging to occur in connection with the successful completion of at least one of the two relief wells currently drilling. Investigations by the United States 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 incurred costs of approximately $3.0 billion (including costs associated with three USCG invoices totaling $122 million) through June 30, 2010 related to spill response and containment, relief-well drilling, grants to certain of the Gulf Coast states for clean-up costs, local tourism promotion, monetary damage claims and federal costs. In addition, BP has incurred more than $1.5 billion of additional costs since June 30, 2010, including $100 million invoiced by the USCG on July 13, 2010.

BP has sought reimbursement from Anadarko for amounts BP has paid for spill response efforts through 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 (the MC 252 lease) and the Macondo well. A copy of the JOA is filed with this Form 10-Q as Exhibit 10. To date, the Company has received billings from BP under the JOA totaling approximately $1.2 billion for what BP considers to be Anadarko’s 25% proportionate share of costs plus anticipated near-term future costs related to the Deepwater Horizon events. Anadarko has withheld payment of Deepwater Horizon event-related invoices received from BP as of the date of this filing, 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 (certain parties through formal designation and other parties, including Anadarko, through the receipt of invoices from the USCG) of their status as a “responsible party or guarantor” (RP) under the Oil Pollution Act of 1990 (OPA). Through July 13, 2010, the USCG has billed a total of $222 million to these RPs for spill-related response costs incurred by the USCG and other federal and state agencies. The RPs have each been sent identical invoices for the total costs, without specification or stipulation of any allocation of costs between or among the RPs. To date, BP has paid all USCG invoices, thereby relieving the other RPs of the obligation to remit payment to the USCG.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

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. As operator, BP has paid all invoices presented by the USCG as well as other costs and has sought reimbursement from Anadarko for a 25% portion of these costs through the JOA. 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.

The following analysis applies relevant accounting guidance to the Deepwater Horizon events to determine the Company’s liability accrual as of June 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 permits 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 June 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 ongoing investigations and of events that have not yet occurred. 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 being claimed 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 $3.0 billion of costs incurred by BP through June 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 that:

 

   

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.

   

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.

 

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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, thereby affecting the obligations of the parties under the JOA. BP has issued a public statement indicating that it disagrees with this view. Under the JOA, liabilities arising in connection with 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 June 30, 2010, pursuant to applicable accounting guidance, the Company has not recognized a liability in its Consolidated Balance Sheets for amounts claimed by BP under the JOA. In the future, the Company may recognize a liability for amounts claimed by BP under the JOA if, for example, new information arising out of the legal-discovery process alters the Company’s current assessment as to the likelihood of the Company incurring a liability for its existing JOA contingent obligations.

If the parties are unable to reach an agreement on liability, one of the possible outcomes is to pursue arbitration under the JOA. In any arbitration, the weight to be given to evidence would be determined by the arbitrators. The Company cannot guarantee the success of any such arbitration proceeding.

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.

BP’s payment, and subsequent invoicing to the non-operating working interest owners, of OPA-related environmental costs under the JOA, results in these amounts being accounted for as JOA contingent liabilities (discussed above) rather than OPA-related environmental liabilities (discussed herein). Payment by BP satisfies these liabilities for all RPs, including Anadarko, and places BP in a position to seek reimbursement from Anadarko through the JOA, resulting in a JOA contingent liability. The Company assumes that 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.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

Gross OPA-related Environmental Cost-Range Estimate  The Company’s estimated range of gross OPA-related environmental liabilities for all RPs is $6.0 billion to $10.0 billion, and excludes (i) $3.0 billion of costs paid by BP as of June 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 potential costs associated with penalties and fines, natural resource damages (NRD) and NRD assessments, and civil litigation damages. The costs that the Company currently cannot reasonably estimate may ultimately prove to be significant.

Anadarko’s gross OPA-related environmental cost-range estimate is comprised of spill-response costs and OPA damage claims and is based on information received from BP to date and the assumptions discussed below. 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 and unknown. Accordingly, the Company believes that actual gross OPA-related environmental costs may vary, perhaps materially, from the Company’s estimate. Additional factors that contribute to the inherent imprecision of the Company’s estimate include the following:

 

   

The scope and nature of the oil spill continue to evolve, introducing significant uncertainty as to the spill’s ultimate impacts, and costs associated therewith.

   

Additional costs may be incurred if relief-well drilling is either prolonged or ultimately unsuccessful in permanently plugging the Macondo well, or if significant weather or other delays occur, beyond delays already considered by the Company in deriving its estimate.

The Company’s gross OPA-related environmental cost-range estimate is based on cost information received from BP, which was used to estimate activity-based cost 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, spill response and clean up.

Spill-Response Costs and Assumptions  These costs include costs associated with relief-well drilling, source containment and well control, and spill mitigation and removal costs.

Relief-well drilling costs include the costs of materials, manpower and day rates for two drilling rigs. BP has publicly indicated that it expects the Macondo well to be permanently plugged upon the successful completion of ongoing relief-well drilling. Based on information available to it, the Company believes that it is reasonable to expect, with an allowance for potential weather-related and other delays, that the first relief well may successfully intercept and permanently plug the Macondo well by mid-August 2010. Thus, the Company’s low-end estimate assumes that the first relief well is successful in permanently plugging the Macondo well in mid-August 2010, and that the second relief well, which is also in the process of being drilled, ceases drilling at the time the well is permanently plugged. The Company’s high-end estimate assumes that the first relief well is not successful in permanently plugging the well, and that completion of the second relief well is required to permanently plug the Macondo well, which the Company estimates, based on public information and with an allowance for potential weather-related and other delays, could occur in mid-October 2010.

 

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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 current status and working to shut in the well;

   

ongoing containment and subsea-collection efforts; and

   

the deployment of numerous vessels to support operations and collect and/or flare hydrocarbons.

The Company’s estimates assume that a majority of the source-containment activities will no longer be necessary after the well is permanently plugged.

Spill mitigation and removal costs primarily include labor, materials and equipment associated with dispersant application, containment and boom acquisition and deployment, operation of support vessels and aircraft, and shoreline clean up. These costs also include amounts associated with efforts to prevent or minimize hydrocarbons from reaching shorelines, including costs to construct barrier islands and costs related to federal, state and local efforts to coordinate the response and to control the spill. The Company’s estimates for spill mitigation and removal costs are based on the assumption that marine/open water and shoreline clean-up activities are ongoing throughout the relief-well drilling period and continue for sixty to ninety days subsequent to permanently plugging the Macondo well.

After sixty to ninety days, it is assumed that any hydrocarbons remaining in the ocean will have evaporated or degraded to the point where additional marine/open water clean up is either unnecessary or ineffective. The Company expects shoreline clean-up activities to continue beyond the sixty- to ninety-day period subsequent to the permanent plugging of the Macondo well; however, at this time, the Company is unable to reasonably estimate shoreline clean-up costs subsequent to this sixty- to ninety-day period due to uncertainty regarding the location and severity of shoreline soiling, which could significantly impact the completion date of shoreline clean up. For example, if contamination occurs in wetland areas, clean-up activities could extend well beyond sixty to ninety days subsequent to the permanent plugging of the well, resulting in significantly higher expected clean-up costs than if the contamination were on a beach area. The Company believes it will be better positioned to reasonably estimate shoreline clean-up costs to be incurred beyond this initial sixty- to ninety-day period after the well has been permanently plugged and marine-response efforts are substantially complete.

OPA Damage Claims  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 estimates 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. OPA damages (other than NRD, discussed below) include costs associated with increased public-service expenses, damages to real or personal property, damages to subsistence uses of natural resources, lost revenues, and lost profits and earning capacity.

The Company’s estimate includes estimated OPA damage claims and costs to administer those claims based on claims data received from BP to date. This data was used to formulate estimates of the number of claims to be filed, the average expected per-claim payout, and costs to administer claims and operate claims offices projected through the conclusion of marine clean-up activities, that is, through the sixty- to ninety-day period subsequent to permanently plugging the Macondo well. The Company believes that claims will continue well beyond the completion of marine clean-up activities, 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 that is available to both BP and independent parties charged with administering OPA damage claims. This significantly hinders the Company’s ability to formulate a long-term estimate of potential OPA damage claims. Accordingly, the Company’s current estimates do not include amounts attributable to damage claims that could be made subsequent to the Company’s estimate of the completion date of marine clean-up activities.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

Allocable Share of Gross OPA-related Environmental Costs  As discussed above, under applicable accounting guidance the Company is required to determine 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 100% of Deepwater Horizon event-related costs – BP is currently paying 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 100% of these costs, the United States 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 government-designated RPs have been identified for the Deepwater Horizon events (non-lessee RPs). The sharing of costs by all RPs, including the non-lessee RPs, would reduce Anadarko’s potential maximum allocable share of gross OPA-related environmental liabilities to an amount less than Anadarko’s 25% working interest in the Macondo well.

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 its 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 June 30, 2010 for potential OPA-related environmental obligations related to the Deepwater Horizon events.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

Other Contingencies

Penalties and Fines  These costs include amounts that may be assessed as a result of potential civil and/or criminal penalties under various federal, state and/or local statutes and/or regulations as a result of the Deepwater Horizon events, including, for example, 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. It is not possible for the Company to 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.

The Company currently considers its greatest exposure to penalties and fines to be under the CWA. Under the CWA, these include, among other penalties, civil penalties for events such as the Deepwater Horizon events that 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 in the MC 252 lease, 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 be calculated based upon 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 agencies, including the National Incident Command’s Flow Rate Technical Group (Technical Group). The most recent estimated flow rate, as stated by the Technical Group, is 35,000 to 60,000 barrels per day. This flow rate and previously stated flow rates appear to measure the combined flow of oil and natural gas at a single point in time. This is problematic for purposes of estimating the total volume of oil spilled since CWA penalties have not typically been applied to natural gas releases. In addition, published spill-volume calculations do not take into account the varying flow rates over time, which are caused by natural variations in the formation’s production of hydrocarbons, nor do they consider changing physical conditions at the point of release, which likely occurred, for example, in connection with the removal of the riser in advance of implementing alternative subsea collection efforts. These variations may significantly impact the total volume of oil spilled.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

Additional uncertainty exists as to how aggregate spill-volume estimates, once officially determined, would be applied for purposes of calculating potential CWA penalties that may be directly assessed against the Company. Moreover, if these spill-volume estimates were used for purposes of directly assessing a penalty against the Company, the following subjective factors could significantly impact the amount of such penalty:

 

   

the degree of culpability involved;

 

   

the seriousness of the violation;

 

   

the economic benefit to the violator;

 

   

any other penalty(ies) 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 the range of uncertainty surrounding the estimate of the total amount of oil spilled and the applicability of this estimate for purposes of assessing CWA penalties prevents the Company from reasonably estimating its exposure to CWA penalties and fines at this time. Thus, currently, the Company can neither conclude that its exposure to CWA penalties is “probable,” nor can the Company reasonably estimate the amount of its potential liability, if any, for CWA penalties.

Natural Resource Damages  This category includes costs to assess damages to natural resources resulting from the spill and/or spill clean-up activities, as well as the future damage claims that may be made by federal and/or state natural resource trustee agencies at the completion of their assessment of the damages. Natural resources generally include land, fish, water, air, wildlife, or other such resources belonging to, managed by, or 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 June 30, 2010. According to recent 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 and spill clean-up activities, which will not be fully known until the flow of hydrocarbons has permanently ceased and 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  Civil litigation related to the Deepwater Horizon events has commenced. As of June 30, 2010, numerous 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; and other parties in state and federal courts located in Alabama, Florida, Georgia, Louisiana, Mississippi, South Carolina, Tennessee and Texas. 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 injunctive relief.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

2.  Deepwater Horizon Events (Continued)

 

In May and June 2010, various plaintiffs and BP filed motions to consolidate all of the federal cases related to the Deepwater Horizon events before one judge, who would preside over the consolidated Multidistrict Litigation in a single venue (MDL). On July 29, 2010, a public hearing of the United States Judicial Panel on Multidistrict Litigation was held to determine whether to consolidate the lawsuits filed in the various federal courts related to the Deepwater Horizon events into an MDL. A ruling is expected during the third quarter of 2010.

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.

These proceedings are at a very early stage; accordingly, the Company currently cannot assess the probability of losses, or reasonably estimate a range of potential losses related to the proceedings described above. The Company intends to vigorously defend itself, its officers and its directors in these proceedings.

Liability Outlook  As discussed above, the Company’s aggregate Deepwater Horizon event-related liability accrual of zero as of June 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 current understanding of 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 liability could be material to the Company’s consolidated financial position, results of operations and 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 for its existing JOA contingent obligations. 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, and/or 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 existing 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.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

3.  Deepwater Drilling Moratorium

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) prohibit drilling and/or spudding any new wells, and require 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 has 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 does not apply to workovers, completions, plugging and abandonment or production activities; however, in order to continue such activities, the Company is required to comply with additional safety inspection and certification requirements that were set forth in two Notice to Lessees and Operators (NTL) issued by the BOEMRE in June 2010.

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. On June 14, 2010, the Company gave written notice of termination to the drilling contractor of a rig placed in force majeure in May 2010. On June 18, 2010, 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 June 19, 2010. The drilling contractor filed an answer in July 2010 denying the Moratorium constituted a force majeure and asserted that Anadarko had breached the drilling contract.

The Company has $3.3 billion and $377 million of unproved property acquisition costs and exploratory drilling costs, respectively, included in net properties and equipment on the Consolidated Balance Sheets at June 30, 2010, related to properties in the Gulf of Mexico that are subject to the Moratorium. As of June 30, 2010, no impairment of these properties has been recognized due to the Moratorium. The Company’s intent to continue exploration and development of these properties is unchanged at this time.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

4.  Goodwill

At June 30, 2010, the Company had $5.3 billion of goodwill recorded as a result of past business combinations. 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, with goodwill balances of $5.2 billion, $134 million and $5 million, respectively, as of June 30, 2010. The Company’s most recent annual goodwill impairment test was completed on October 1, 2009, with no impairment indicated.

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 a goodwill impairment test as of June 30, 2010, and the results of the test indicated no impairment. Uncertainty related to the Deepwater Horizon events, the Moratorium, 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 Interest

During the three months ended June 30, 2010, Western Gas Partners, LP (WES), a consolidated subsidiary of the Company, issued approximately five million common units, representing limited partner interests, to the public. This offering raised proceeds of $97 million, recorded as noncontrolling interests. As of June 30, 2010, the balance of noncontrolling interests on the Consolidated Balance Sheets includes approximately $64 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 June 30, 2010, Anadarko’s ownership interest in WES consists of a 51.5% limited partner interest (common and subordinated units), a 2% general partner interest and incentive distribution rights.

See Note 17 for discussion regarding WES financing activities subsequent to June 30, 2010.

6. Inventories

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

 

millions    June 30,
2010
   December 31,
2009

Crude oil and NGLs

   $ 121    $ 142

Natural gas

     19      94
             

Total

   $ 140    $ 236
             

 

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(Unaudited)

 

7.  Properties and Equipment

Suspended Exploratory Drilling Costs  The Company’s capitalized suspended well costs at June 30, 2010, and December 31, 2009, were $828 million and $579 million, respectively. The increase primarily relates to capitalization of additional costs associated with successful exploration drilling activities in Brazil, the Maverick basin in the Company’s Southern Region and in the Gulf of Mexico, including $45 million in drilling costs incurred for the Macondo well through April 20, 2010, the date of the Macondo well blowout. See Note 2. For the six months ended June 30, 2010, $2 million of exploratory well costs, previously capitalized as suspended well costs for greater than one year, were charged to dry hole expense, and $75 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 pursuing efforts to assess 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 six months ended June 30, 2010, was $115 million and $127 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 is idle with no immediately identified plans for use, and for which no market or 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 six months ended June 30, 2009, was $23 million and $74 million, respectively, of which $22 million and $69 million, respectively, related to certain transportation contracts included in the marketing operating segment and resulting from 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 June 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 amount reported in other long-term liabilities - other for all periods presented.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8.  Investments (Continued)

 

Interest on the notes issued by Anadarko is variable, based on London Interbank Offered Rate (LIBOR) plus a spread that fluctuates with Anadarko’s credit rating. The applicable interest rate was 1.54% and 1.25% at June 30, 2010, and December 31, 2009, respectively. Other (income) expense, net for the three and six months ended June 30, 2010, includes interest expense on the notes payable to the investee entities of $9 million and $18 million, respectively, and equity in earnings from Anadarko’s investments in the investee entities of $(9) million and $(18) million, respectively. Other (income) expense, net for the three and six months ended June 30, 2009, includes interest expense on the notes payable to the investee entities of $16 million and $36 million, respectively, and equity in earnings from Anadarko’s investments in the investee entities of $(14) million and $(23) 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 and Note 17 for a subsequent event that is expected to affect the Midstream Subsidiary Note Payable to a Related Party.

As of June 30, 2010, Trinity’s assets consist of $100 million invested in the Fund and the $1.3 billion note receivable from Midstream Holding. Trinity’s earnings, which consist primarily of interest income from the note receivable and the Fund, are allocated first to the Investor’s Class B member interest, until its cumulative preferred return is satisfied, with the remaining earnings allocated to Anadarko’s Class A member interest. These earnings-allocation provisions generally result in Anadarko receiving a minor share of Trinity’s total earnings, consistent with the relative sizes of Anadarko’s Class A and the Investor’s Class B member capital account balances. Should Trinity incur a loss, Anadarko would absorb first-dollar losses of Trinity, until its Class A member capital account in Trinity is reduced to zero.

Through its Class A member and managing member interests, Anadarko has significant influence over Trinity; therefore, Anadarko accounts for its investment in Trinity under the equity method of accounting. As of June 30, 2010, the carrying amount of Anadarko’s investment in Trinity, reported in other assets, and the Company’s maximum exposure to loss were each $100 million. Anadarko does not hold a controlling financial interest in Trinity because it does not have the power, without the Investor’s consent, to direct activities that are significant to Trinity’s economic performance. Further, Anadarko’s right to allocated Trinity earnings and its obligation to absorb first-dollar losses of Trinity, if any, do not have the potential to be significant relative to the total potential earnings and losses of Trinity.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

9.  Derivative Instruments

Objective and Strategy  The Company is exposed to commodity price and interest-rate risk, and management considers it prudent to periodically enter into derivative instruments in order to manage the Company’s exposure to cash flow variability resulting from these risks.

Futures, swaps and options are used to manage the Company’s 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 the product price 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).

The Company also enters into physical-delivery sales contracts to manage cash flow variability. These contracts call for the receipt or delivery of physical product at a specified location and price, which may be fixed or market-based.

Interest-rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to mitigate 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. The application of hedge accounting was discontinued by the Company for periods beginning on or after January 1, 2007. 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 in future periods as the economic transactions to which the derivatives relate are recorded in earnings.

The accumulated other comprehensive loss balances related to commodity derivatives at June 30, 2010, and December 31, 2009, were $6 million ($4 million after tax) and $10 million ($7 million after tax), respectively. The accumulated other comprehensive loss balances related to interest-rate derivatives at June 30, 2010, and December 31, 2009, were $132 million ($84 million after tax) and $141 million ($89 million after tax), respectively.

 

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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 June 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 entered into to reduce commodity price risk associated with certain physical product sales. At June 30, 2010, and December 31, 2009, the Company had outstanding physical transactions related to natural gas for 37 billion cubic feet (Bcf) and 46 Bcf, respectively, offset by derivative transactions for 27 Bcf and 17 Bcf, respectively, for net positions of 10 Bcf and 29 Bcf, respectively.

 

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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 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 $397 million and $424 million on these swap agreements are reported in (gains) losses on other derivatives, net for the three and six months ended June 30, 2010, respectively. For the three months ended June 30, 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 $200 million and $90 million for the three and six months ended June 30, 2009, respectively.

A summary of the swaps outstanding as of June 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%

During the first six months of 2009, Anadarko issued fixed-rate senior notes in the aggregate principal amount of $2.0 billion. In advance of these debt issuances, Anadarko entered into derivative financial instruments, effectively hedging the United States Treasury portion of the coupon rate on a portion of this debt. These derivative instruments were settled concurrently with the associated debt issuance, resulting in a realized loss of $3 million and $16 million for the three months and six months ended June 30, 2009, respectively, reflected in (gains) losses on other derivatives, net.

 

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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 not designated as hedging instruments (including physical-delivery sales contracts) is included in the table below.

 

        Gross
Derivative Assets
  Gross
Derivative Liabilities
 

millions

Derivatives                         

 

Balance Sheet
Classification

      June 30,    
2010
   December 31, 
2009
      June 30,    
2010
     December 31, 
2009
 

Commodity

         
 

Other Current Assets

  $ 582   $ 140   $ (216   $ (63
 

Other Assets

    278     82     (51     (6
 

Accrued Expenses

    2     195     (7     (417
 

Other Liabilities

    15     25     (19     (52
                             
      877     442     (293     (538
                             

Interest Rate and Other

         
 

Other Assets

        53              
 

Accrued Expenses

            (236       
 

Other Liabilities

            (149     (3
                             
          53     (385     (3
                             

Total Derivatives

    $ 877   $ 495   $ (678   $ (541
                             

Effect of Derivative Instruments – Statement of Income  The unrealized and realized gain or loss amounts and classification related to derivative instruments not designated as hedging instruments are as follows:

 

          (Gain) Loss  
millions    Classification of (Gain)    Three Months Ended
June 30, 2010
    Six Months Ended
June 30, 2010
 

Derivatives

  

Loss Recognized

   Realized     Unrealized         Total         Realized     Unrealized         Total      

Commodity

  

Gathering, Processing and Marketing Sales*

   $ 1      $ 2      $ 3      $ 1      $ (5   $ (4
  

(Gains) Losses on Commodity Derivatives, net

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

Interest Rate and Other

  

(Gains) Losses on Other Derivatives, net

            406        406               435        435   
                                                   

Derivative (Gain) Loss, Net

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

 

*Represents the effect of marketing and trading derivative activities.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

9. Derivative Instruments (Continued)

 

          (Gain) Loss  
millions    Classification of (Gain)    Three Months Ended
June 30, 2009
    Six Months Ended
June 30, 2009
 

Derivatives

  

Loss Recognized

   Realized     Unrealized        Total         Realized     Unrealized        Total      

Commodity

  

Gathering, Processing and Marketing Sales*

   $ 8      $ 4    $ 12      $ (14   $ 33    $ 19   
  

(Gains) Losses on Commodity Derivatives, net

     (98     266      168        (221     590      369   

Interest Rate

  

(Gains) Losses on Other Derivatives, net

     (545     197      (348     (530     84      (446
                                                 

Derivative (Gain) Loss, Net

   $ (635   $ 467    $ (168   $ (765   $ 707    $ (58
                                                 

 

*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 their 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, if any, 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 its counterparties.

Included in the Company’s $877 million gross derivative asset balance at June 30, 2010, is $685 million attributable to open positions with financial institutions. The Company has netting and setoff agreements with certain of these counterparties, which permit the net settlement of gross derivative assets against gross derivative liabilities. As of June 30, 2010, $355 million of the Company’s $678 million gross derivative liability balance is permitted to offset the gross derivative asset balance with financial institutions. The below tables include the financial impact of the Company’s total netting arrangements.

Most of the Company’s derivative instruments are subject to provisions requiring either full or partial collateralization of the Company’s obligations, or the immediate settlement of all such obligations, in the event of a downgrade in the Company’s credit rating to a level below investment grade from major credit rating agencies. The aggregate fair value of all derivative instruments with credit-risk-related contingent features for which a net liability position existed was $177 million, net of collateral, which is included in accrued expenses on the Company’s Consolidated Balance Sheets at June 30, 2010. 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 and required the Company to post collateral under its derivative instruments. As of June 30, 2010, $74 million of cash had been posted as collateral pursuant to contractual requirements applicable to derivative instruments. No counterparties requested termination or full settlement of derivative positions.

As discussed in Note 17, in July 2010, the Company obtained commitments for financing of $6.5 billion under a new senior secured revolving credit facility and senior secured term loan facility (the Facilities). Closing of the Facilities, among other things, would cause certain of the Company’s derivative counterparties (those extending commitments under the Facilities) to receive security interests in specified assets of the Company. The secured position of the lenders participating in the Facilities will also allow the Company to reduce or eliminate its existing requirement to post cash collateral to secure its liabilities, if any, under commodity and other derivative arrangements.

 

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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.

 

June 30, 2010

millions

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

Assets:

           

Commodity derivatives

   $ 2      $ 875      $    $ (294   $ 583  

Interest-rate and other derivatives

                                 
                                       

Total derivative assets

   $ 2      $ 875      $    $ (294   $ 583  
                                       

Liabilities:

           

Commodity derivatives

   $ (3   $ (290   $    $ 358      $ 65  

Interest-rate and other derivatives

            (385                 (385
                                       

Total derivative liabilities

   $ (3   $ (675   $    $ 358      $ (320
                                       

 

(1)

Represents the impact of netting assets, liabilities and collateral with counterparties where the right of setoff exists. Cash collateral held by counterparties from Anadarko was $74 million at June 30, 2010. Anadarko held $10 million of cash collateral from counterparties at June 30, 2010.

 

December 31, 2009

millions

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

Assets:

           

Commodity derivatives

   $ 4      $ 438      $    $ (289   $ 153  

Interest-rate derivatives

            53                    53  
                                       

Total derivative assets

   $ 4      $ 491      $    $ (289   $ 206  
                                       

Liabilities:

           

Commodity derivatives

   $ (6   $ (532   $    $ 333      $ (205

Interest-rate derivatives

            (3                 (3
                                       

Total derivative liabilities

   $ (6   $ (535   $    $ 333      $ (208
                                       

 

(1)

Represents the impact of netting assets, liabilities and collateral with counterparties where the right of setoff exists. Cash collateral held by counterparties from Anadarko was $105 million at December 31, 2009. Anadarko held no cash collateral from counterparties at December 31, 2009.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

10. Debt and Interest Expense

Debt  The following table presents the Company’s outstanding debt as of June 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 do not affect the Company’s reported debt balance or consolidated interest expense. Further, Note 17 provides information about commitments for financing that the Company obtained in July 2010.

 

     June 30, 2010    December 31, 2009

millions

 

   Principal    Carrying
Value
   Fair
Value
   Principal    Carrying
Value
   Fair
Value

Long-term notes and debentures

   $ 12,659    $ 10,892    $ 9,558    $ 12,909    $ 11,149    $ 12,133

Midstream subsidiary note payable to a related party

     1,349      1,349      1,349      1,599      1,599      1,599

WES credit facility borrowing

     110      110      110               
                                         

Total debt

   $ 14,118    $ 12,351    $ 11,017    $ 14,508    $ 12,748    $ 13,732

Less: Current portion of long-term debt

     926      909      910               
                                         

Total long-term debt

   $ 13,192    $ 11,442    $     10,107    $     14,508    $     12,748    $     13,732

The current portion of long-term debt includes $422 million principal amount ($419 million carrying value) of 6.750% Senior Notes due May 2011, and $504 million accreted principal amount ($490 million carrying value) of Zero-Coupon Senior Notes (the Zero Coupons) maturing October 2036. Anadarko originally received $500 million of proceeds upon issuing the Zero Coupons in a 2006 private offering. 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 has an option to put 82% of the principal amount (or $504 million accreted value) to Anadarko in October 2010. As of June 30, 2010, the carrying amount associated with the portion of the Zero Coupons putable to the Company in October 2010 is classified as a current portion of long-term debt on the Company’s Consolidated Balance Sheets because, if the put option is exercised, the Company intends to retire this portion of the Zero Coupons using cash on hand. In addition, pursuant to current terms of the Zero Coupons, there is no put option in 2011, but the holder has the right to cause the Company to repay 100% of any remaining principal at the Zero Coupons’ then-accreted value in October of each year, starting in 2012.

The following table presents the debt activity of the Company for the six months ended June 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 borrowing
   Retirements      (528     (522   Tender-offer repurchases
   Repayment      (250     (250   Midstream subsidiary note repayment
   Other, net             6      Changes in debt premium or discount

Second Quarter 2010

         
   Retirements      (472     (479   Tender-offer repurchases
   WES repayment      (100     (100   WES credit facility repayment
   Other, net             (7   Changes in debt premium or discount
                     

Balance as of June 30, 2010

      $ 14,118      $ 12,351     
                     

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

10. Debt and Interest Expense (Continued)

 

In March 2010, Anadarko commenced a cash tender offer for up to $1.0 billion aggregate principal amount of specified series of its outstanding debt. Pursuant to the tender-offer terms, the Company repurchased $528 million and $472 million principal amount of debt in March 2010 and April 2010, respectively, as summarized in the following table.

 

millions              Principal Amount

Description

   Month of
    Repurchase    
     Early-Tender  
Premium
     Repurchased      Remaining
Outstanding Balance

6.750% Notes due 2011

   March 2010            $ 34        $ 528                $ 422

6.875% Notes due 2011

   April 2010      32      390      285

6.125% Notes due 2012

   April 2010      3      38      132

5.000% Notes due 2012

   April 2010      2      44      38
                       
              $ 71        $ 1,000                $ 877
                       

Midstream Subsidiary Note Payable to a Related Party  In December 2007, Anadarko and the Investor formed Trinity, with initial capitalization totaling $2.3 billion. See Note 8 for additional information regarding the Company’s interest in Trinity. 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 has an initial maturity date of December 27, 2012. Interest on the Midstream Subsidiary Note is based on the three-month LIBOR plus a margin that varies based on Anadarko’s credit rating. The rate in effect as of July 1, 2010, was 1.73%. Following a sale or transfer of assets to third parties or other entities within Anadarko, Midstream Holding and/or its subsidiaries is required to repay a portion of the Midstream Subsidiary Note principal. Midstream Holding may otherwise repay the Midstream Subsidiary Note in whole or in part at any time prior to maturity. Midstream Holdings’ obligation for principal and interest payments is guaranteed by Anadarko Petroleum Corporation. If Anadarko’s senior unsecured credit rating falls below “BB-” by Standard and Poor’s (S&P) or “Ba3” by Moody’s, maturity of the Midstream Subsidiary Note could be accelerated. As of June 30, 2010, the Company was in compliance with all covenants governing the Midstream Subsidiary Note agreement and S&P and Moody’s rated the Company’s debt at “BBB-” and “Ba1,” respectively.

As discussed in Note 17, in July 2010, the Company obtained commitments for financing of $6.5 billion under the Facilities, and repayment of the Midstream Subsidiary Note is a condition to closing on the Facilities.

Anadarko Revolving Credit Agreement  At June 30, 2010, Anadarko was in compliance with the covenants contained in its $1.3 billion revolving credit agreement (RCA), which matures in March 2013. At June 30, 2010, the RCA was undrawn with available capacity of $1.1 billion ($1.3 billion undrawn capacity less $196 million in outstanding letters of credit supported by the RCA). Subsequent to June 30, 2010, $100 million of additional letters of credit, which are also supported by the RCA, were provided to counterparties. As discussed in Note 17, in July 2010, the Company obtained commitments for financing of $6.5 billion under the Facilities (including $5.0 billion under a five-year senior secured revolving credit facility). The RCA will be terminated upon closing of the Facilities and outstanding letters of credit will be cancelled and replaced with letters of credit provided under the Facilities.

WES Revolving Credit Facility  At June 30, 2010, WES was in compliance with the covenants contained in its $350 million senior unsecured revolving credit facility (RCF). Outstanding borrowings under the RCF, which carry an annual interest rate of 2.72%, were $110 million at June 30, 2010. See Note 17 for WES financing activities subsequent to June 30, 2010.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

10. Debt and Interest Expense (Continued)

 

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

 

     Three Months Ended
June 30,
      Six Months Ended  
June 30,
 

millions

 

   2010     2009     2010     2009  

Current debt, long-term debt and other

   $ 192      $ 206      $ 394      $ 393   

Midstream subsidiary note payable to a related party

     6        11        13        23   

(Gain) loss on early retirements of debt (1)

     32        (1     72        (2

Capitalized interest

     (30     (15     (55     (31
                                

Interest expense

   $ 200      $ 201      $ 424      $ 383   
                                

 

(1)

(Gain) loss on early retirements of debt in 2010 are the result of repurchasing $1.0 billion aggregate principal amount of debt under the tender offer discussed above.

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
June 30,
    Six Months Ended
June 30,
 
millions except per-share amounts    2010     2009     2010    2009  

Income (loss):

         

Net income (loss) attributable to common stockholders

   $ (40   $ (226   $ 676    $ (564

Less: Distributions on participating securities

                   1        

Less: Undistributed income allocated to participating securities

                   5        
                               

Basic

   $ (40   $ (226   $ 670    $ (564
                               

Diluted

   $ (40   $ (226   $ 670    $ (564
                               

Shares:

         

Basic

         

Weighted-average common shares outstanding

     495        477        494      468   

Dilutive effect of stock options and performance-based stock awards

                   2        
                               

Diluted

     495        477        496      468   
                               

Excluded (1)

     13        15        6      14   

Income (loss) per common share:

         

Basic

   $ (0.08   $ (0.48   $ 1.36    $ (1.21

Diluted

   $ (0.08   $ (0.48   $ 1.35    $ (1.21

Dividends per common share

   $ 0.09      $ 0.09      $ 0.18    $ 0.18   

 

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

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

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 decreased income and $3 million increased income for the three and six months ended June 30, 2010, respectively. Litigation charges and adjustments of $58 million and $45 million decreased income for the three and six months ended June 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) 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). In connection with those bankruptcy cases, Tronox 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.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

12.   Commitments and Contingencies (Continued)

 

The United States filed a motion to intervene in the Tronox lawsuit, 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 Tronox’s pending bankruptcy litigation. Anadarko and Kerr-McGee have moved to dismiss the United States’ intervention complaint, 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). On July 21, 2010, in response to this motion, Tronox announced to the Court that it would reject the MSA effective as of July 22, 2010. Anadarko, Kerr-McGee and Tronox have agreed to prepare a joint Stipulation and Agreed Order for entry by the Court. When the order is entered, Anadarko and Kerr-McGee will have 30 days from the date the order is entered to file a claim for damages caused by the rejection. On July 7, 2010, Tronox filed a Joint Plan of Reorganization of Tronox, Inc. et al. (the Plan) and a Disclosure Statement regarding the Plan. The Plan proposes to address Tronox’s legacy liabilities by transferring these liabilities to trusts formed for this purpose. The Plan also contemplates entry into an Environmental Claims Settlement Agreement with the United States, the Navajo Nation, and certain other governmental claimants. Tronox has been negotiating with the United States, the Ad Hoc Noteholders Committee, the Equity Committee, and certain governmental claimants. The interested parties continue to negotiate the terms of such a settlement. The form of such a settlement will be filed with the Plan Supplement, which will be filed no later than 14 days before a hearing on Plan confirmation. Tronox has proposed that as part of the settlement, the United States will receive, in addition to other consideration, the right to 88% of the proceeds of the Adversary Proceeding pending in the Court (Anadarko Litigation). If certain tort claimants vote in favor of the Plan, the remaining 12% interest in any recovery will be distributed to those claimants. An Anadarko Litigation Trust would be established pursuant to the Plan and governed by an Anadarko Litigation Trust Agreement to be filed with the Plan Supplement. The Anadarko Litigation Trust Agreement will provide that the United States will have the right to approve or reject any proposed settlement of the Anadarko Litigation, after consultation with certain other government entities and with certain representatives of holders of tort claims. Tronox will have no responsibility, obligation, or liability with respect to the Anadarko Litigation Trust. The Disclosure Statement and the Plan could be opposed by interested parties, including Anadarko and Kerr-McGee. Therefore, it is unclear whether those or any other such agreements between Tronox and the United States and others will be approved or implemented, or what, if any, effect such agreements might have on the course, cost or outcome of the bankruptcy litigation.

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 on July 30, 2010.

The Company intends to continue to defend itself vigorously.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

12.   Commitments and Contingencies (Continued)

 

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.

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, a former wholly owned subsidiary that held Kerr-McGee’s chemical business, 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 is limited to a maximum aggregate reimbursement of $100 million. As of June 30, 2010, the Company has a $95 million liability recorded for the guarantee obligation. See Litigation section of this Note 12 and Note 17 for a discussion of events occurring subsequent to June 30, 2010, related to this guarantee obligation.

The Company is guarantor for specific financial obligations of a trona mining affiliate. The investment in this entity is accounted for under the equity method. The Company has guaranteed a portion of amounts due under a term loan. The Company’s guarantee under the term loan expires in the fourth quarter of 2010, coinciding with the maturity of that agreement. The Company would be obligated to pay $15 million under the term loan if the affiliate defaulted on the obligation. No liability has been recognized for this guarantee as of June 30, 2010.

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 June 30, 2010, other long-term liabilities include a $50 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 June 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 June 30, 2010, the Company’s Consolidated Balance Sheets include a $90 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.

 

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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     Six Months Ended  
     June 30,     June 30,  
millions except percentages    2010     2009     2010     2009  

Income tax expense (benefit)

     $ 49        $ (135     $     566        $ (349

Effective tax rate

         233             38     45             39

The increase in the Company’s effective tax rate as compared to the 35% statutory rate for the three months ended June 30, 2010, is primarily attributable to 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 unfavorable resolution of tax contingencies. This increase in the effective tax rate is partially reduced by U.S. tax on losses from foreign operations, the federal manufacturing deduction, state income taxes (due to a decrease in the Company’s estimate of deferred state income taxes) and other items. The increase in the Company’s effective tax rate as compared to the 35% statutory rate for the six months ended June 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 unfavorable resolution of tax contingencies. This increase in the effective tax rate is partially reduced by U.S. tax on losses from foreign operations, federal manufacturing deduction and other items. The increase in the Company’s effective tax rate as compared to the 35% statutory rate for the three and six months ended June 30, 2009, is primarily attributable to changes in uncertain tax positions and state income taxes, partially reduced by the accrual of the Algerian exceptional profits tax, other foreign taxes in excess of federal statutory rates, 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.

 

     Six Months Ended
     June 30,
millions    2010    2009

Cash paid:

     

Interest

    $       343     $       348

Income taxes

    $       153     $       195

Non-cash investing activities:

     

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

    $       18     $ 38

 

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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    Six Months Ended
     June 30,    June 30,
millions    2010    2009    2010    2009

Income (loss) before income taxes

     $ 21      $ (351)     $ 1,266     $ (896)

Exploration expense

     198      288      353      589

Depreciation, depletion and amortization expense

     902      933      1,883      1,739

Impairments

     115      23      127      74

Interest expense

     200      201      424      383

Less: Net income attributable to noncontrolling interests

     12      10      24      17
                           

Consolidated Adjusted EBITDAX

     $     1,424      $     1,084     $     4,029     $     1,872
                           

 

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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 June 30, 2010:

         

Sales revenues

   $ 1,223    $ 45    $     1,295       $         —       $         2,563   

Intersegment revenues

    1,058     208     (1,165     (101       

Gains (losses) on divestitures and other, net

    1                40        41   
                                   

Total revenues and other

  $         2,282    $         253    $ 130       $ (61    $ 2,604   
                                   

Operating costs and expenses (1)

    730     145     113        24        1,012   

(Gains) losses on commodity derivatives, net

                   (264     (264

(Gains) losses on other derivatives, net

                   406        406   

Other (income) expense, net

                   14        14   

Net income attributable to noncontrolling interests

        12                   12   
                                   

Total

    730     157     113        180        1,180   
                                   

Adjusted EBITDAX

   $ 1,552    $ 96    $ 17       $ (241    $ 1,424   
                                   

Three Months Ended June 30, 2009:

         

Sales revenues

   $ 829    $ 64    $ 1,001       $ —         $ 1,894   

Intersegment revenues

    782     175     (886     (71       

Gains (losses) on divestitures and other, net

    4     4            11        19   
                                   

Total revenues and other

   $ 1,615    $ 243    $ 115       $ (60    $ 1,913   
                                   

Operating costs and expenses (1)

    644     151     119        77        991   

(Gains) losses on commodity derivatives, net

                   168        168   

(Gains) losses on other derivatives, net

                   (348     (348

Other (income) expense, net

                   8        8   

Net income attributable to noncontrolling interests

        10                   10   
                                   

Total

    644     161     119        (95     829   
                                   

Adjusted EBITDAX

   $ 971    $ 82    $ (4    $ 35       $ 1,084   
                                   

 

(1)

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

 

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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  

Six Months Ended June 30, 2010:

         

Sales revenues

   $     2,744       $ 100    $     2,849       $         —       $     5,693   

Intersegment revenues

    2,309        432     (2,542     (199       

Gains (losses) on divestitures and other, net

    (12                62        50   
                                     

Total revenues and other

   $ 5,041       $         532    $ 307       $ (137    $ 5,743   
                                     

Operating costs and expenses (1)

    1,478        317     233        56        2,084   

(Gains) losses on commodity derivatives, net

                      (852     (852

(Gains) losses on other derivatives, net

                      435        435   

Other (income) expense, net

                      23        23   

Net income attributable to noncontrolling interests

           24                   24   
                                     

Total

    1,478        341     233        (338     1,714   
                                     

Adjusted EBITDAX

   $ 3,563       $ 191    $ 74       $ 201       $ 4,029   
                                     

Six Months Ended June 30, 2009:

         

Sales revenues

   $ 1,280       $ 123    $ 2,242       $       $ 3,645   

Intersegment revenues

    1,824        333     (1,982     (175       

Gains (losses) on divestitures and other, net

    14        4            46        64   
                                     

Total revenues and other

   $ 3,118       $ 460    $ 260       $ (129    $ 3,709   
                                     

Operating costs and expenses (1)

    1,241        288     235        136        1,900   

(Gains) losses on commodity derivatives, net

                      369        369   

(Gains) losses on other derivatives, net

                      (446     (446

Other (income) expense, net

                      (3     (3

Net income attributable to noncontrolling interests

           17                   17   
                                     

Total

    1,241        305     235        56        1,837   
                                     

Adjusted EBITDAX

   $ 1,877       $ 155    $ 25       $ (185    $ 1,872   
                                     

 

(1)

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

 

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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 funded by contributions from the Company and the retiree. The Company’s retiree life insurance plan is noncontributory.

During the six months ended June 30, 2010, the Company made contributions of $70 million to its funded pension plans, $2 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 approximately $23 million to its funded pension plans, approximately $17 million to its unfunded pension plans and approximately $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     Three Months Ended  
    June 30,     June 30,  
millions   2010     2009     2010     2009  

Components of net periodic benefit cost

       

Service cost

  $ 18      $ 14      $ 2      $ 3   

Interest cost

    21        19        4        5   

Expected return on plan assets

    (20     (18              

Amortization of actuarial loss (gain)

    15        12               (1

Amortization of prior service cost (credit)

           1        (1     (1

Settlements

           10                 
                               

Net periodic benefit cost

  $         34      $         38      $         5      $         6   
                               
    Pension Benefits     Other Benefits  
    Six Months Ended     Six Months Ended  
    June 30,     June 30,  
millions   2010     2009     2010     2009  

Components of net periodic benefit cost

       

Service cost

  $ 35      $ 27      $ 4      $ 5   

Interest cost

    42        39        8        9   

Expected return on plan assets

    (41     (36              

Amortization of actuarial loss (gain)

    32        25        (1     (1

Amortization of prior service cost (credit)

    1        1        (1     (1

Settlements

           10                 
                               

Net periodic benefit cost

  $ 69      $ 66      $ 10      $ 12   
                               

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

17. Subsequent Events

Anadarko Financing Activities In July 2010, the Company obtained commitments for $6.5 billion in new financing in the form of a $5.0 billion senior secured revolving credit facility that matures in five years, and a $1.5 billion senior secured term-loan facility that matures in six years (the Facilities). Upon closing, expected to occur in the third quarter of 2010, the new senior secured revolving credit facility will replace the Company’s existing $1.3 billion RCA, currently scheduled to mature in March 2013, and the proceeds of the new senior secured term loan will be used to refinance the Midstream Subsidiary Note. The Midstream Subsidiary Note matures in December 2012 and had $1.3 billion outstanding at June 30, 2010.

Borrowings under the Facilities will bear interest, at the Company’s election, based on LIBOR, the JPMorgan Chase Bank prime rate, or the federal funds rate, plus a margin. LIBOR-based borrowings under the revolving credit facility are expected to include a margin ranging from 2.75% to 4.00%, based on the Company’s credit rating. Borrowings under the six-year term-loan facility will amortize in quarterly installments of 0.25% of the original principal amount. The Company may elect to repay any borrowings outstanding under the Facilities at any time, in whole or in part.

Borrowings and other obligations that may be incurred by the Company under the Facilities will be secured by liens on certain of the Company’s exploration and production assets located in the United States, and 65% of the capital stock of certain of the Company’s foreign subsidiaries. The secured position of the lenders under the Facilities will be subject to existing liens and customary exceptions, and limitations on the incurrence of debt secured by certain assets, as provided in the indentures under which the Company’s existing senior unsecured notes were issued. Accordingly, the senior unsecured notes currently outstanding will remain unsecured after closing of the Facilities.

The terms of the Facilities are expected to include customary representations and warranties, conditions precedent, events of default, affirmative and negative covenants and financial covenants, and are subject to customary closing conditions.

WES Financing Activities In connection with the acquisition of certain midstream assets from Anadarko on August 2, 2010, WES borrowed $250 million under a three-year, unsecured term loan with a group of banks (the Term Loan). The Term Loan bears interest at LIBOR plus an applicable margin ranging from 2.50% to 3.50% depending on WES’s consolidated leverage ratio, as defined in the Term Loan agreement. The Term Loan contains various customary covenants for WES, which are substantially similar to those in WES’s RCF. Also, on August 2, 2010, WES exercised the accordion feature of its RCF, expanding its borrowing capacity under the RCF from $350 million to $450 million, and subsequently borrowed $200 million under the RCF, bringing aggregate borrowings outstanding under the RCF to $310 million, with $140 million of remaining capacity.

Tronox Obligation In June 2010, Anadarko and Kerr-McGee moved to compel Tronox to assume or reject the MSA. On July 21, 2010, in response to this motion Tronox announced to the Court that it would reject the MSA effective as of July 22, 2010. Anadarko, Kerr-McGee, and Tronox have agreed to prepare a joint Stipulation and Agreed Order for entry by the Court. When the order is entered, Anadarko and Kerr-McGee will have 30 days from the date the order is entered to file a claim for damages caused by the rejection. The Company is currently analyzing any impact the rejection of the MSA may have on the Company’s consolidated financial position, results of operations and cash flows. See Note 12.

 

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

The Company has made in this report, and may from time to time otherwise make in other public filings, press releases and 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 and federal corporate 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 the Gulf of Mexico relief wells in permanently plugging the Macondo well and BP Exploration & Production Inc.’s (BP) related response and clean-up efforts;

 

   

the impact of the deepwater drilling moratoria (collectively, the Moratorium) and resulting legislative and regulatory changes on the Company’s Gulf of Mexico and International offshore operations;

 

   

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

 

   

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

 

   

the securities, capital or credit markets;

 

   

the Company’s ability to repay its debt;

 

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the closing of a $5.0 billion senior secured revolving credit facility that matures in five years and a $1.5 billion senior secured term-loan facility that matures in six years for which the Company has received commitments;

 

   

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 quarter ended March 31, 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. Refer to Note 2—Deepwater Horizon Events in the Notes to the Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for discussion and analysis of these events.

DEEPWATER DRILLING MORATORIUM

Anadarko has 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). Refer to Note 3—Deepwater Drilling Moratorium in the Notes to the Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information on the Moratorium.

 

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OPERATING HIGHLIGHTS

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

United States Onshore

   

The Company’s Rocky Mountain Region (Rockies) achieved second-quarter sales volumes of 278 thousand barrels of oil equivalent per day (MBOE/d), representing a 10% increase over the second quarter of 2009.

   

The Company’s Southern Region achieved second-quarter sales volumes of 125 MBOE/d, representing a 6% increase over the second quarter of 2009.

Gulf of Mexico

   

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

   

The Company encountered more than 650 net feet of oil pay to date in three of the primary targets in the Lucius appraisal well (50% working interest) in the Keathley Canyon block 875. As a result of the Moratorium, drilling was suspended approximately 2,000 feet from total depth with one additional target yet to test. For information on the Moratorium, see Note 3—Deepwater Drilling Moratorium in the Notes to the Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

   

The Company encountered approximately 250 net feet of pay in the second Vito appraisal well (20% working interest) in a shallower Miocene reservoir. As a result of the Moratorium, drilling was suspended prior to reaching the main objectives.

   

The Company successfully completed the Callisto discovery well (100% working interest) and expects to tie the well back to the Independence Hub natural gas platform. The well is expected to begin production later this year at an anticipated rate of approximately 40 million cubic feet of natural gas per day.

International

   

The Company encountered 75 net feet of oil pay in the successful Mahogany-5 appraisal well (30.9% working interest) in the West Cape Three Points block offshore Ghana.

   

The Wahoo #1 drillstem test (30% working interest) located on block BM-C-30 in the deepwater Campos Basin offshore Brazil flowed at a sustained rate of approximately 7,500 barrels of oil per day and approximately 4 million cubic feet of natural gas per day.

FINANCIAL HIGHLIGHTS

Significant financial highlights during the second quarter of 2010 and through the date of filing this Form 10-Q include the following:

 

   

The Company generated $1.6 billion of cash flow from operations and ended the quarter with $3.4 billion of cash on hand.

   

The Company completed a $1.0 billion cash tender offer in March and April 2010 by repurchasing $472 million principal amount of debt during the second quarter of 2010.

   

In June 2010, Moody’s Investor Services (Moody’s) lowered the Company’s senior unsecured credit rating from “Baa3” to “Ba1” and placed the Company’s long-term ratings under review for further possible downgrade, while Standard & Poor’s (S&P) and Fitch Ratings (Fitch) each affirmed their “BBB-” rating with a negative outlook.

   

In late July 2010, the Company obtained commitments for $6.5 billion in new financing, including a five-year secured revolving credit facility of $5.0 billion, which would replace the Company’s existing $1.3 billion Revolving Credit Agreement (RCA) with the remaining three-year term. For additional information, see Liquidity and Capital Resources.

 

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The following discussion pertains to Anadarko’s financial condition, results of operations and changes in financial condition. Any increases or decreases “for the three months ended June 30, 2010” refer to the comparison of the three months ended June 30, 2010 to the three months ended June 30, 2009, and any increases or decreases “for the six months ended June 30, 2010” refer to the comparison of the six months ended June 30, 2010 to the six months ended June 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 costs required for operations.

RESULTS OF OPERATIONS

Selected Data

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
millions except per-share amounts    2010     2009     2010    2009  

Financial Results

         

Total revenues and other(1)

     $ 2,604      $ 1,913      $ 5,743    $ 3,709   

Costs and expenses

     2,227        2,235        4,447      4,302   

Other (income) expense(1)

     356        29        30      303   

Income tax expense (benefit)

     49        (135     566      (349

Net income (loss) attributable to common stockholders

     $ (40   $ (226   $ 676    $ (564

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

     $ (0.08   $ (0.48   $ 1.35    $ (1.21

Average number of common shares outstanding – diluted

     495        477        496      468   

 

Operating Results

         

Adjusted EBITDAX(2)

     $ 1,424      $ 1,084      $ 4,029    $ 1,872   

Sales volumes (MMBOE)    

     59        56        121      110   

 

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 second quarter of 2010, Anadarko’s net loss attributable to common stockholders was $40 million or $0.08 per share (diluted). This compares to a net loss attributable to common stockholders of $226 million or $0.48 per share (diluted) for the second quarter of 2009. For the six months ended June 30, 2010, Anadarko’s net income attributable to common stockholders was $676 million or $1.35 per share (diluted), compared to a net loss attributable to common stockholders of $564 million or $1.21 per share (diluted) for the same period of 2009.

 

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Sales Revenues, Volumes and Prices

 

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

Gas sales

   $ 802    21   $ 663    $ 1,883    23   $ 1,534

Oil and condensate sales

     1,338    46        914      2,840    83        1,550

Natural-gas liquids sales

     235    103        116      509    156        199
                               

Total

   $     2,375    40      $ 1,693    $     5,232    59      $     3,283
                               

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

 

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

2009 sales revenues

   $ 663      $ 914    $ 116    $ 1,693

Changes associated with sales volumes

     (3     82      50      129

Changes associated with prices

     142        342      69      553
                            

2010 sales revenues

   $     802      $     1,338    $     235    $     2,375
                            
     Six Months Ended June 30,
     Natural
Gas
    Oil and
Condensate
   NGLs    Total

2009 sales revenues

   $ 1,534      $ 1,550    $ 199    $ 3,283

Changes associated with sales volumes

     22        281      104      407

Changes associated with prices

     327        1,009      206      1,542
                            

2010 sales revenues

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

 

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

 

     Three Months Ended
June 30,
   Six Months Ended
June  30,
          Inc/(Dec)              Inc/(Dec)     
       2010      vs. 2009      2009        2010      vs. 2009      2009  

Barrels of Oil Equivalent

                 

(MMBOE except percentages)

                 

United States

   53    7%    49    107    10%    97

International

   6    (4)      7    14    7        13
                         

Total

   59    6       56    121    10        110
                         

Barrels of Oil Equivalent per Day

                 

(MBOE/d except percentages)

                 

United States

   583    7       546    592    10        537

International

   68    (4)      71    76    7        71
                         

Total

   651    6       617    668    10        608
                         

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
June  30,
   Six Months Ended
June  30,
          Inc/(Dec)              Inc/(Dec)     
       2010      vs. 2009      2009        2010      vs. 2009      2009  

United States

                 

Sales volumes—Bcf

     211    (1)%      213      427    1%      421

             MMcf/d

         2,324    (1)             2,336          2,358    1             2,325

Price per Mcf

   $ 3.79    21        $ 3.12    $ 4.41    21       $ 3.64

    Gas sales revenue (millions)    

   $ 802    21        $ 663    $ 1,883    23       $ 1,534

 

Bcf—billion cubic feet

MMcf/d—million cubic feet per day

The Company’s daily natural-gas sales volumes decreased 12 MMcf/d for the three months ended June 30, 2010. This decrease was primarily a result of lower sales volumes in the Gulf of Mexico due to a natural decline at Independence Hub, partially offset by higher volumes from the Haynesville and Marcellus shale plays in the Southern Region and higher volumes in the Rockies due to increased drilling activity. The Company’s daily natural-gas sales volumes increased 33 MMcf/d for the six months ended June 30, 2010. The increase was primarily a result of increased production in the Southern Region and Rockies as discussed above, partially offset by a decrease in the Gulf of Mexico due to a natural decline at Independence Hub.

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

 

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

 

     Three Months Ended
June 30,
   Six Months Ended
June 30,
          Inc/(Dec)              Inc/(Dec)     
       2010      vs. 2009      2009        2010      vs. 2009      2009  

United States

                 

Sales volumes—MMBbls

     12    17%      9      24    26%      19

             MBbls/d

     130    17          111      133    26          106

Price per barrel

   $ 73.89    34        $ 55.31    $ 74.45    58        $ 47.23

International

                 

Sales volumes—MMBbls

     6    (4)         7      14    7          13

             MBbls/d

     68    (4)         71      76    7          71

Price per barrel

   $ 75.66    36        $ 55.64    $ 75.59    52        $ 49.81

Total

                 

Sales volumes—MMBbls

     18    9          16      38    18          32

             MBbls/d

     198    9          182      209    18          177

Total price per barrel

   $     74.49    34        $     55.44    $     74.86    55        $     48.26

Total oil and condensate sales

        revenues (millions)                

   $ 1,338    46        $ 914    $ 2,840    83        $ 1,550

 

MMBbls—million barrels

MBbls/d—thousand barrels per day

Anadarko’s daily crude-oil and condensate sales volumes increased 16 MBbls/d and 32 MBbls/d for the three and six months ended June 30, 2010, respectively. These increases were primarily due to higher crude-oil sales volumes of 13 MBbls/d and 22 MBbls/d, respectively, in the Gulf of Mexico due to the completion of prolonged repairs of third-party downstream infrastructure during the third quarter of 2009 that was damaged during the 2008 hurricane season, and additional production that came online during the second quarter of 2009. Algerian crude-oil sales volumes also increased 6 MBbls/d for the six months ended June 30, 2010, due to the scheduling of cargo liftings. In addition, crude-oil sales volumes increased for the three and six months ended June 30, 2010, as a result of shifting drilling from gas to liquid-rich areas in the Rockies and Southern Region.

Anadarko’s average crude-oil price increased for the three and six months ended June 30, 2010, as a result of increased global demand and tightening supply from conventional non-OPEC production.

 

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Natural-Gas Liquids Sales Volumes, Average Prices and Revenues

 

     Three Months Ended
June  30,
   Six Months Ended
June  30,
          Inc/(Dec)              Inc/(Dec)     
       2010      vs. 2009      2009        2010      vs. 2009      2009  

United States

                 

Sales volumes—MMBbls

     6    43%      4      12    52%      8

             MBbls/d

     66    43         46      66    52         43

Price per barrel

   $     39.05    41       $     27.64    $     42.80    68       $     25.52

Natural-gas liquids sales revenues (millions)

   $ 235    103       $ 116    $ 509    156       $ 199

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 six months ended June 30, 2010, increased 20 MBbls/d and 23 MMBbls/d, respectively. These increases were primarily in the Rockies and resulted from a new natural-gas processing train brought online late in the second quarter of 2009, the implementation of new processing agreements late in 2009 and increased natural-gas production in the Rockies.

The average NGLs price increased for the three and six months ended June 30, 2010, primarily due to a sustained increase in the spread between crude oil and natural gas prices and sustained global petrochemical demand.

Gathering, Processing and Marketing Margin

 

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

Gathering, processing and marketing sales

   $     188    (6)%    $     201    $ 461    27%    $     362

Gathering, processing and marketing expenses

     149    (19)         183      332    4          318
                                 

Margin

   $ 39    117        $ 18    $ 129    193        $ 44
                                 

For the three and six months ended June 30, 2010, gathering, processing and marketing margin increased $21 million and $85 million, respectively. These increases were primarily related to higher prices for NGLs and condensate, which increased revenue under percent-of-proceeds and keep-whole contracts, higher margins and volumes associated with natural-gas sales from inventory, and lower transportation costs, partially offset by an increase in cost of product as well as margins associated with assets divested in 2009. For the three months ended June 30, 2009, gathering, processing and marketing revenues and expenses are higher due to an adjustment to revenues and expenses that did not affect the margin.

 

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Costs and Expenses

 

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

Oil and gas operating

   $     196    (10)%    $     218    $     383    (17)%    $     459

Oil and gas transportation and other

     196    7           184      387    8           358

Exploration

     198    (31)         288      353    (40)         589

For the three and six months ended June 30, 2010, oil and gas operating expenses decreased primarily due to cost savings that continued to be realized from programs initiated in response to lower oil and gas prices in early 2009. These cost savings programs initiated in 2009 included deferrals of certain workovers, favorable vendor negotiations and other operating efficiencies. Oil and gas operating expenses also decreased due to lower surface maintenance and outside-operated expenses in the Gulf of Mexico, primarily due to timing of well work.

For the three months ended June 30, 2010, oil and gas transportation and other expenses increased due to $12 million of costs related to force majeure invoked on contracted drilling rigs in the Gulf of Mexico that would have otherwise been capitalized as drilling costs. For additional information, see Note 3—Deepwater Drilling Moratorium in the Notes to the Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. For the six months ended June 30, 2010, oil and gas transportation and other expenses increased primarily due to higher third-party gas gathering and transportation costs attributable to increased production in both the Rockies and Southern Region, and costs related to the Company invoking force majeure as discussed above. Partially offsetting the increase for the six months ended June 30, 2010, were costs associated with drilling rig contract termination fees incurred in 2009 as a result of lower 2009 commodity prices.

Exploration expense decreased by $90 million for the three months ended June 30, 2010, primarily due to lower dry hole expense in the Gulf of Mexico of $56 million, as well as lower impairments of unproved properties in Nigeria of $20 million and China of $19 million. Exploration expense decreased by $236 million for the six months ended June 30, 2010, primarily due to lower dry hole expense in the Gulf of Mexico of $139 million, Alaska of $26 million and Indonesia of $13 million, as well as lower impairments of unproved properties in Nigeria of $20 million and in China of $19 million.

 

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

General and administrative

   $     203    (10)%    $     226    $ 413    (5)%    $ 435

Depreciation, depletion and amortization

     902    (3)         933          1,883    8               1,739

Other taxes

     268    49          180      569    72           330

Impairments

     115    NM          23      127    72           74

 

NM – percentage change does not provide meaningful information

For the three and six months ended June 30, 2010, general and administrative (G&A) expense decreased primarily due to employee expenses, primarily attributable to share-based compensation plans.

For the three months ended June 30, 2010, depreciation, depletion and amortization (DD&A) expense decreased $60 million primarily due to lower DD&A from properties that were fully depleted, partially offset by a $29 million increase attributable to higher sales volumes. For the six months ended June 30, 2010, DD&A expense increased by $144 million of which $131 million was due to higher sales volumes.

For the three months ended June 30, 2010, other taxes increased primarily due to higher commodity prices and higher oil and NGLs volumes resulting in increased Algerian exceptional profits tax expense of $17 million, United States production and severance taxes of $46 million and Chinese windfall profits tax of $10 million, as well as increased ad valorem taxes of $9 million primarily due to higher assessed property values. For the six months ended June 30, 2010, other taxes increased primarily due to higher commodity prices and higher volumes resulting in increased Algerian exceptional profits tax expense of $91 million, United States production and severance taxes of $91 million and Chinese windfall profits tax of $24 million, as well as increased ad valorem taxes of $25 million primarily due to higher assessed property values.

 

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Impairments for the three months ended June 30, 2010, were attributable to $115 million of oil and gas exploration and production operating segment properties in the United States, $114 million of which related to a production platform that is idle with no identifiable plans for use, and for which no market or a limited market currently exists. The platform was impaired to fair value. Impairments for the three months ended June 30, 2009, included $22 million of marketing operating segment intangible assets. Impairments for the six months ended June 30, 2010, included $114 million related to the production platform discussed above, $5 million of other oil and gas exploration and production operating segment properties in the United States and $8 million of marketing operating segment intangible assets. Impairments for the six months ended June 30, 2009, included $69 million of marketing operating segment intangible assets and $5 million of oil and gas exploration and production operating segment properties in the United States. The marketing operating segment impairments related to transportation contracts and were caused by lower margins between certain locations. The oil and gas exploration and production operating segment impairments were primarily a result of the economic and commodity price environment.

Other (Income) Expense

 

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

Interest Expense

               

Current debt, long-term debt and other

   $ 192      (7)%    $ 206    $ 394      —%     $ 393   

Midstream subsidiary note payable to a related party

     6      (45)          11      13      (43)         23   

(Gain) loss on early retirement of debt

     32      NM           (1)      72      NM          (2

Capitalized interest

     (30   100           (15)      (55   77          (31
                                     

Interest expense

   $     200      —         $     201    $     424      11        $     383   
                                     

For the three and six months ended June 30, 2010, Anadarko’s interest expense included losses on early retirements of debt of $32 million and $72 million, respectively, resulting from the repurchase of $1.0 billion principal amount of senior notes pursuant to the Company’s tender offer as discussed under Liquidity and Capital Resources. These losses were partially offset by increases in capitalized interest primarily due to higher construction-in-progress balances related to long-term capital projects.

As further discussed under Liquidity and Capital Resources and Note 17—Subsequent Events in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q, in July 2010, the Company obtained commitments for $6.5 billion in new financing in the form of a $5.0 billion senior secured revolving credit facility that matures in five years, and a $1.5 billion senior secured term-loan facility that matures in six years (the Facilities). Upon closing, the new senior secured revolving credit facility will replace the Company’s existing $1.3 billion RCA and the new senior secured term loan will be used to refinance the Midstream Subsidiary Note Payable to a Related Party (Midstream Subsidiary Note). In connection with these transactions, the Company is expected to incur underwriting, structuring and arrangement and other fees and expenses. The majority of such fees will be initially capitalized and amortized to interest expense over the term of the associated debt or credit commitment. The Company may also incur higher cash interest cost in future periods, depending on the level of borrowings the Company incurs under the Facilities, the ultimate terms of such borrowings, and the prevailing interest rates.

 

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

(Gains) Losses on Commodity Derivatives, net

              

Realized (gains) losses

              

Natural gas

   $ (163   79%    $ (91   $ (182   3%    $     (176

Oil and condensate

     2      (129)        (7     —       (100)        (45
                                      

Total realized (gains) losses

     (161   64         (98     (182   (18)        (221
                                      

Unrealized (gains) losses

              

Natural gas

     166      (66)        100        (400   NM         377   

Oil and condensate

     (269   NM         166        (270   NM         213   
                                      

Total unrealized (gains) losses

     (103   139         266        (670   NM         590   
                                      

Total (gain) loss on commodity derivatives, net

   $     (264   NM       $     168      $     (852   NM       $ 369   
                                      

The Company utilizes commodity derivative instruments to manage the risk of a decrease in the market prices for its anticipated sales of natural gas and crude oil. The change in (gain) loss on commodity derivatives, net includes the impact of derivatives entered into or settled and price changes related to open positions at June 30 of each year. For additional information on (gains) losses on commodity derivatives, see Note 9—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

 

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

(Gains) Losses on Other Derivatives, net

               

Realized (gains) losses – interest rate derivatives and other

   $    (100 )%    $ (545   $    (100)%    $ (530

Unrealized (gains) losses – interest rate derivatives and other

     406    (106     197        435    NM           84   
                                   

Total (gain) loss on other derivatives, net

   $     406    NM      $     (348   $     435    (198)        $     (446
                                   

Anadarko enters into interest-rate swaps to fix or float interest rates on existing or anticipated indebtedness in order to mitigate exposure to unfavorable interest-rate changes. (Gains) losses on other derivatives, net decreased for the three and six months ended June 30, 2010, primarily due to the decline of the three month London Interbank Offered Rate (LIBOR) resulting in a $397 million loss in the second quarter of 2010, as well as the 2009 contract term revisions which increased the weighted-average interest rate of the Company’s swap portfolio from 3.25% to 4.80%, and resulted in a realized gain of $552 million during the second quarter of 2009. For additional information, see Note 9—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

 

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

Other (Income) Expense, net

              

Interest income

   $     (2   (60)%    $     (5   $     (7   (50)%    $     (14

Other

     16      (23)         13        30      (173)         11   
                                      

Total other (income) expense, net

   $ 14      (75)       $ 8      $ 23      NM        $ (3
                                      

For the three months ended June 30, 2010, total other (income) expense, net decreased $6 million primarily due to foreign currency losses of $30 million related to exchange-rate changes applicable to cash held in escrow pending final determination of the Company’s Brazilian tax liability attributable to its 2008 divestiture of the Peregrino field offshore Brazil, and $18 million of losses related to exchange-rate changes applicable to foreign currency purchased in anticipation of future expenditures on major development projects. Partially offsetting this decrease were lower legal reserves of $25 million. For the six months ended June 30, 2010, total other (income) expense, net decreased $26 million primarily due to foreign currency losses of $43 million related to exchange-rate changes applicable to cash held in escrow and $29 million of losses related to exchange-rate changes applicable to foreign currency purchased in anticipation of future expenditures on major development projects, partially offset by lower legal reserves of $27 million.

Income Tax Expense

 

     Three Months Ended
June 30,
   Six Months Ended
June 30,
millions except percentages      2010        2009        2010        2009  

Income tax expense (benefit)

   $ 49        $     (135)      $ 566        $     (349)  

Effective tax rate

         233%      38%      45%      39%

For the three and six months ended June 30, 2010, income tax expense (benefit) increased primarily due to an increase in income before income taxes.

The increase in the Company’s effective tax rate as compared to the 35% statutory rate for the three months ended June 30, 2010, is primarily attributable to 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 unfavorable resolution of tax contingencies. This increase in the effective tax rate is partially reduced by U.S. tax on losses from foreign operations, the federal manufacturing deduction, state income taxes (due to a decrease in the Company’s estimate of deferred state income taxes) and other items. The increase in the Company’s effective tax rate as compared to the 35% statutory rate for the six months ended June 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 unfavorable resolution of tax contingencies. This increase in the effective tax rate is partially reduced by U.S. tax on losses from foreign operations, federal manufacturing deduction and other items. The increase in the Company’s effective tax rate as compared to the 35% statutory rate for the three and six months ended June 30, 2009, is primarily attributable to changes in uncertain tax positions and state income taxes, partially reduced by the accrual of the Algerian exceptional profits tax, other foreign taxes in excess of federal statutory rates, U.S. tax on foreign income inclusions and distributions and other items.

Net Income Attributable to Noncontrolling Interests

For the three and six months ended June 30, 2010, the Company’s net income attributable to noncontrolling interests of $12 million and $24 million, respectively, primarily related to a 46.5% public ownership interest in Western Gas Partners, LP (WES), a consolidated subsidiary of the Company.

 

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OPERATING RESULTS

Segment Analysis—Adjusted EBITDAX  To assess the operating results of Anadarko’s segments, the chief operating decision maker analyzes income (loss) before income taxes, interest expense, exploration expense, DD&A expense and impairments, less net income attributable to noncontrolling interests (Adjusted EBITDAX). Anadarko’s definition of Adjusted EBITDAX, which is not a GAAP measure, 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, as defined by Anadarko, may not be comparable to similarly titled measures used by other companies. Therefore, Anadarko’s consolidated Adjusted EBITDAX should be considered in conjunction with net income (loss) attributable to common stockholders and other performance measures prepared in accordance with GAAP, such as operating income or cash flow from operating activities. Adjusted EBITDAX has important limitations as an analytical tool because it excludes certain items that affect net income (loss) attributable to common stockholders and net cash provided by operating activities. Adjusted EBITDAX should not be considered in isolation or as a substitute for an analysis of Anadarko’s results as reported under GAAP. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) before income taxes.

Adjusted EBITDAX

 

<
     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     Inc/(Dec)     Inc/(Dec)  
millions except percentages    2010     vs. 2009     2009     2010        vs. 2009     2009  

Income (loss) before income taxes

   $ 21      106   $ (351   $ 1,266    NM      $ (896

Exploration expense