XNYS:APC Anadarko Petroleum Corp Quarterly Report 10-Q Filing - 6/30/2012

Effective Date 6/30/2012

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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, 2012

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 July 31, 2012, is shown below:

 

Title of Class   Number of Shares Outstanding
Common Stock, par value $0.10 per share   499,678,984


Table of Contents

TABLE OF CONTENTS

 

PART I        Page  

Item 1.

 

Financial Statements

  
 

Consolidated Statements of Income for the Three and Six Months Ended June 30, 2012 and 2011

     2  
 

Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2012 and 2011

     3  
 

Consolidated Balance Sheets as of June 30, 2012, and December 31, 2011

     4  
 

Consolidated Statement of Equity for the Six Months Ended June 30, 2012

     5  
 

Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2012 and 2011

     6  
 

Notes to Consolidated Financial Statements

     7  

Item 2.

 

Management’s Discussion and Analysis

     26  
 

Financial Results

     29  
 

Operating Results

     39  
 

Liquidity and Capital Resources

     41  

Item 3.

 

Quantitative and Qualitative Disclosures About Market Risk

     45  

Item 4.

 

Controls and Procedures

     46  
PART II
          

Item 1.

 

Legal Proceedings

     47  

Item 1A. 

 

Risk Factors

     47  

Item 2.

 

Unregistered Sales of Equity Securities and Use of Proceeds

     48  

Item 6.

 

Exhibits

     49  


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    2012     2011     2012     2011  

Revenues and Other

        

Natural-gas sales

   $ 496     $ 870     $ 1,069     $ 1,724  

Oil and condensate sales

         2,222           2,236           4,466           4,043  

Natural-gas liquids sales

     282       370       624       703  

Gathering, processing, and marketing sales

     200       258       453       488  

Gains (losses) on divestitures and other, net

     22       (58     57       (29
  

 

 

   

 

 

   

 

 

   

 

 

 

Total

     3,222       3,676       6,669       6,929  
  

 

 

   

 

 

   

 

 

   

 

 

 

Costs and Expenses

        

Oil and gas operating

     249       236       491       468  

Oil and gas transportation and other

     223       207       463       416  

Exploration

     1,121       236       1,365       415  

Gathering, processing, and marketing

     178       205       367       376  

General and administrative

     262       282       531       491  

Depreciation, depletion, and amortization

     1,027       985       1,957       1,970  

Other taxes

     326       413       703       757  

Impairments

     112       102       162       104  

Algeria exceptional profits tax settlement

                   (1,804       

Deepwater Horizon settlement and related costs

     3       9       11       35  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total

     3,501       2,675       4,246       5,032  
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating Income (Loss)

     (279     1,001       2,423       1,897  

Other (Income) Expense

        

Interest expense

     190       216       376       436  

(Gains) losses on commodity derivatives, net

     (420     (343     (468     (87

(Gains) losses on other derivatives, net

     376       144       140       85  

Other (income) expense, net

     (519     (18     (254     (42
  

 

 

   

 

 

   

 

 

   

 

 

 

Total

     (373     (1     (206     392  
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (Loss) Before Income Taxes

     94        1,002       2,629        1,505  

Income Tax Expense (Benefit)

     164        440       516        706  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net Income (Loss)

     (70     562       2,113        799  

Net Income Attributable to Noncontrolling Interests

     19       18       46       39  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net Income (Loss) Attributable to Common Stockholders

   $ (89   $ 544     $ 2,067      $ 760  
  

 

 

   

 

 

   

 

 

   

 

 

 

Per Common Share

        

Net income (loss) attributable to common stockholders—basic

   $ (0.18   $ 1.09     $ 4.11      $ 1.52  

Net income (loss) attributable to common stockholders—diluted

   $ (0.18   $ 1.08     $ 4.10      $ 1.51  

Average Number of Common Shares Outstanding—Basic

     500       498       499       497  
  

 

 

   

 

 

   

 

 

   

 

 

 

Average Number of Common Shares Outstanding—Diluted

     500       500       501       499  
  

 

 

   

 

 

   

 

 

   

 

 

 

Dividends (per Common Share)

   $ 0.09     $ 0.09     $ 0.18     $ 0.18  

See accompanying Notes to Consolidated Financial Statements.

 

2


Table of Contents

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

 

                                                                   
      Three Months Ended 
June 30,
       Six Months Ended  
June 30,
 
millions    2012      2011      2012      2011  

Net Income (Loss)

   $     (70   $     562      $     2,113       $     799  

Other Comprehensive Income (Loss), net of taxes

          

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

     2       3        4        5  

Amortization of net actuarial loss and prior service cost to net periodic benefit cost (2)

     15       13        30        27  
  

 

 

   

 

 

    

 

 

    

 

 

 

Total

     17       16        34        32  
  

 

 

   

 

 

    

 

 

    

 

 

 

Comprehensive Income (Loss)

     (53     578        2,147         831  

Comprehensive Income Attributable to Noncontrolling Interests

     19       18        46        39  
  

 

 

   

 

 

    

 

 

    

 

 

 

Comprehensive Income (Loss) Attributable to Common Stockholders

   $ (72   $ 560      $ 2,101       $ 792  
  

 

 

   

 

 

    

 

 

    

 

 

 

 

(1) 

Net of income tax benefit (expense) of $(1) million and $(1) million for the three months ended June 30, 2012 and 2011, respectively, and $(2) million and $(3) million for the six months ended June 30, 2012 and 2011, respectively.

(2) 

Net of income tax benefit (expense) of $(9) million and $(8) million for the three months ended June 30, 2012 and 2011, respectively, and $(17) million and $(16) million for the six months ended June 30, 2012 and 2011, respectively.

See accompanying Notes to Consolidated Financial Statements.

 

3


Table of Contents

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

                                             
millions        June 30,    
2012
     December 31, 
2011
 

ASSETS

    

Current Assets

    

Cash and cash equivalents

   $ 2,794     $ 2,697  

Accounts receivable, net of allowance:

    

Customers

     1,087       1,269  

Others

     1,864        1,990  

Algeria exceptional profits tax settlement

     1,629         

Other current assets

     1,056       975  
  

 

 

   

 

 

 

Total

     8,430        6,931  
  

 

 

   

 

 

 

Properties and Equipment

    

Cost

     60,990       60,081  

Less accumulated depreciation, depletion, and amortization

     23,506       22,580  
  

 

 

   

 

 

 

Net properties and equipment

     37,484       37,501  

Other Assets

     1,661       1,516  

Goodwill and Other Intangible Assets

     5,757       5,831  
  

 

 

   

 

 

 

Total Assets

   $     53,332      $     51,779  
  

 

 

   

 

 

 

LIABILITIES AND EQUITY

    

Current Liabilities

    

Accounts payable

   $ 2,873      $ 3,299  

Accrued expenses

     1,271        1,430  

Current portion of long-term debt

     1,739       170  
  

 

 

   

 

 

 

Total

     5,883        4,899  
  

 

 

   

 

 

 

Long-term Debt

     13,093       15,060  

Other Long-term Liabilities

    

Deferred income taxes

     8,809        8,479  

Asset retirement obligations

     1,662       1,737  

Other

     2,607       2,621  
  

 

 

   

 

 

 

Total

     13,078        12,837  
  

 

 

   

 

 

 

Equity

    

Stockholders’ equity

    

Common stock, par value $0.10 per share
(1.0 billion shares authorized, 517.6 million and 516.0 million shares issued as of June 30, 2012, and December 31, 2011, respectively)

     51       51  

Paid-in capital

     7,995       7,851  

Retained earnings

     13,595        11,619  

Treasury stock (17.9 million and 17.6 million shares as of June 30, 2012, and December 31, 2011, respectively)

     (827     (804

Accumulated other comprehensive income (loss)

     (578     (612
  

 

 

   

 

 

 

Total Stockholders’ Equity

     20,236        18,105  

Noncontrolling interests

     1,042       878  
  

 

 

   

 

 

 

Total Equity

     21,278        18,983  
  

 

 

   

 

 

 

Total Liabilities and Equity

   $ 53,332      $ 51,779  
  

 

 

   

 

 

 

See accompanying Notes to Consolidated Financial Statements.

 

4


Table of Contents

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

 

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

Balance at December 31, 2011

  $     51     $     7,851     $     11,619     $     (804   $     (612   $ 878     $ 18,983  

Net income (loss)

                  2,067                      46       2,113   

Common stock issued

           110                                   110  

Dividends—common

                  (91                          (91

Repurchase of common stock

                         (23                   (23

Subsidiary equity transactions (1)

           34                            159       193  

Distributions to noncontrolling interest owners

                                       (52     (52

Contributions from noncontrolling interest owners

                                       11       11  

Reclassification of previously deferred derivative losses to net income

                                4              4  

Adjustments for pension and other postretirement plans

                                30              30  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at June 30, 2012

  $ 51     $ 7,995     $ 13,595      $ (827   $ (578   $     1,042     $     21,278   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) 

The $34 million increase to paid-in capital, together with the Company’s net income (loss) attributable to common stockholders, totaled $2,101 million for the six months ended June 30, 2012.

See accompanying Notes to Consolidated Financial Statements.

 

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Table of Contents

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

     Six Months Ended
June 30,
 
millions    2012     2011  

Cash Flows from Operating Activities

    

Net income (loss)

   $ 2,113      $ 799  

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

    

Depreciation, depletion, and amortization

     1,957       1,970  

Deferred income taxes

     143        258  

Dry hole expense and impairments of unproved properties

     1,187       227  

Impairments

     162       104  

(Gains) losses on divestitures, net

     29       18  

Unrealized (gains) losses on derivatives, net

     83       75  

Other

     120       61  

Changes in assets and liabilities:

    

Deepwater Horizon settlement and related costs

     24         

Algeria exceptional profits tax settlement

     (1,691       

Tronox-related contingent loss

     (250       

(Increase) decrease in accounts receivable

     351        (535

Increase (decrease) in accounts payable and accrued expenses

     (486     241  

Other items—net

     148       (92
  

 

 

   

 

 

 

Net cash provided by (used in) operating activities

     3,890       3,126  
  

 

 

   

 

 

 

Cash Flows from Investing Activities

    

Additions to properties and equipment and dry hole costs

     (3,553     (2,799

Acquisition of midstream businesses

            (804

Divestitures of properties and equipment and other assets

     258       55  

Other—net

     (112     (41
  

 

 

   

 

 

 

Net cash provided by (used in) investing activities

         (3,407         (3,589
  

 

 

   

 

 

 

Cash Flows from Financing Activities

    

Borrowings, net of issuance costs

     886       1,046  

Repayments of debt

     (1,305     (859

Increase (decrease) in accounts payable, banks

     (39     (38

Dividends paid

     (91     (90

Repurchase of common stock

     (23     (30

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

     38       49  

Sale of subsidiary units

     212       130  

Distributions to noncontrolling interest owners

     (52     (37

Contributions from noncontrolling interest owners

     11       4  
  

 

 

   

 

 

 

Net cash provided by (used in) financing activities

     (363     175  
  

 

 

   

 

 

 

Effect of Exchange Rate Changes on Cash

     (23     14  
  

 

 

   

 

 

 

Net Increase (Decrease) in Cash and Cash Equivalents

     97       (274

Cash and Cash Equivalents at Beginning of Period

     2,697       3,680  
  

 

 

   

 

 

 

Cash and Cash Equivalents at End of Period

   $ 2,794     $ 3,406  
  

 

 

   

 

 

 

See accompanying Notes to Consolidated Financial Statements.

 

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Table of Contents

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.  Summary of Significant Accounting Policies

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

Basis of Presentation  The information furnished herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the Company’s Consolidated Balance Sheets as of June 30, 2012, and December 31, 2011, the Consolidated Statements of Income and Comprehensive Income for the three and six months ended June 30, 2012 and 2011, the Consolidated Statements of Cash Flows for the six months ended June 30, 2012 and 2011, and the Consolidated Statement of Equity for the six months ended June 30, 2012. Certain prior-period amounts have been reclassified to conform to the current-period presentation.

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

2.  Acquisitions

The acquisitions of the Platte Valley assets in February 2011 and the Wattenberg Plant in May 2011 constitute business combinations and were accounted for using the acquisition method. Preliminary fair-value measurements made at the acquisition dates were finalized in the first quarter of 2012. There were no changes to the fair value of assets acquired and liabilities assumed from the amounts included on the Company’s Consolidated Balance Sheet as of December 31, 2011.

3.  Inventories

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

 

millions          June 30,      
       2012      
       December 31,  
  2011  
 

Crude oil

   $ 69      $ 103  

Natural gas

     31        49  

NGLs

     41        59  
  

 

 

    

 

 

 

Total

   $     141      $     211  
  

 

 

    

 

 

 

 

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Table of Contents

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

4.  Properties and Equipment

Suspended Exploratory Well Costs  The Company’s suspended exploratory well costs at June 30, 2012, and December 31, 2011, were $1.9 billion and $1.4 billion, respectively. The increase in suspended exploratory well costs during 2012 primarily relates to the capitalization of costs associated with successful exploration drilling in Mozambique, the Gulf of Mexico, the Utica and Marcellus shales in the Southern and Appalachia Region, Ghana, and Côte d’Ivoire. For the six months ended June 30, 2012, $39 million of exploratory well costs previously capitalized as suspended well costs for greater than one year were charged to dry hole expense and $82 million of capitalized suspended well costs were reclassified to proved properties.

Management believes projects with suspended exploratory well costs exhibit sufficient quantities of hydrocarbons to justify potential development and is actively pursuing efforts to assess whether reserves can be attributed to these projects. 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 of Unproved Properties  In the second quarter of 2012, the Company recognized a $720 million impairment of unproved Powder River coalbed methane properties primarily due to lower natural-gas prices. The Company also recognized a $124 million impairment of an unproved Gulf of Mexico natural-gas property due to a reduction of estimated recoverable reserves as a result of the forecasted natural-gas price environment. This Gulf of Mexico property is located on a lease that is close to expiration and the Company does not plan to pursue the exploitation of this property under the forecasted natural-gas price environment. These impairments are included in exploration expense in the Company’s Consolidated Statements of Income for the three and six months ended June 30, 2012, and the impacted assets were impaired to fair value, estimated using Level 3 fair-value inputs.

Impairments  Impairment expense for the three and six months ended June 30, 2012, was $112 million and $162 million, respectively. In the second quarter of 2012, due to lower natural-gas prices, the Company recognized impairments of $79 million related to certain onshore domestic oil and gas exploration and production reporting segment properties and $4 million related to midstream reporting segment properties. The Company also recognized impairments of $50 million and $17 million in the first and second quarter of 2012, respectively, related to downward reserves revisions for a Gulf of Mexico property included in the oil and gas exploration and production reporting segment that is near the end of its economic life. These properties were impaired to an aggregate fair value of $41 million based on an income approach, estimated using Level 3 fair-value inputs.

Also in the second quarter of 2012, the Company recognized impairment expense of $11 million ($4 million net of tax) related to the Company’s investment in Venezuelan assets due to declines in estimated recoverable reserves and lower crude-oil prices. These assets are included in the oil and gas exploration and production reporting segment and were impaired to fair value based on an income approach, estimated using Level 3 fair-value inputs. At June 30, 2012, the Company’s after-tax net investment in these assets was $34 million.

Impairment expense for the three and six months ended June 30, 2011, was $102 million and $104 million, respectively, including $100 million recognized in the second quarter of 2011 related to onshore domestic properties due to a change in projected cash flows resulting from the Company’s intent to divest of the properties. These properties were included in the oil and gas exploration and production reporting segment and were impaired to a fair value of $491 million based on an income approach, estimated using Level 3 fair-value inputs.

Assets Held for Sale  In 2011, the Company began marketing domestic properties from the oil and gas exploration and production reporting segment and the midstream reporting segment in order to redirect its operating activities and capital investment to other areas. During the first quarter of 2012, the Company decided not to proceed with the sale of properties from the midstream reporting segment. In 2012, the Company sold certain domestic oil and gas exploration and production reporting segment properties and recognized losses of $13 million and $30 million included in gains (losses) on divestitures and other, net in the Company’s Consolidated Statements of Income for the three and six months ended June 30, 2012, respectively. At June 30, 2012, the remaining balances of assets and liabilities associated with assets held for sale were not material.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

5.  Noncontrolling Interests

Western Gas Partners, LP (WES), a consolidated subsidiary, is a limited partnership formed by Anadarko to own, operate, acquire, and develop midstream assets. In June 2012, WES issued five million common units to the public, raising net proceeds of $212 million, which increased the noncontrolling interest component of total equity. At June 30, 2012, Anadarko’s ownership interest in WES consisted of a 41.4% limited partner interest, the entire 2.0% general partner interest, and incentive distribution rights.

6.  Derivative Instruments

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

Interest-rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to unfavorable interest-rate changes. The fair value of the Company’s interest-rate swap portfolio increases (decreases) when interest rates increase (decrease).

The Company does not apply hedge accounting to any of its derivative instruments. As a result, both realized and unrealized gains and losses associated with derivative instruments are recognized in earnings. Net derivative losses attributable to derivatives previously subject to hedge accounting reside in accumulated other comprehensive income (loss) and are reclassified to earnings as the transactions to which the derivatives relate are recognized in earnings. Accumulated other comprehensive loss balances of $103 million ($66 million after tax) and $109 million ($70 million after tax) at June 30, 2012, and December 31, 2011, respectively, relate to interest-rate derivatives that were previously subject to hedge accounting.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

6.  Derivative Instruments (Continued)

 

Oil and Natural-Gas Production/Processing Derivative Activities  Below is a summary of the Company’s derivative instruments related to its Oil and Natural-Gas Production/Processing Activities at June 30, 2012. The natural-gas prices listed below are New York Mercantile Exchange (NYMEX) Henry Hub prices. The crude-oil prices listed below are a combination of NYMEX Cushing and London Brent Dated prices.

 

           2012                  2013        

Natural Gas

    

Three-Way Collars (thousand MMBtu/d)

     (1)      450  

Average price per MMBtu

    

Ceiling sold price (call)

   $      $     6.57  

Floor purchased price (put)

   $      $ 5.00  

Floor sold price (put)

   $      $ 4.00  

Fixed-Price Contracts (thousand MMBtu/d)

     1,000          

Average price per MMBtu

   $ 4.69      $   

Crude Oil

    

Three-Way Collars (MBbls/d)

     62          

Average price per barrel

    

Ceiling sold price (call)

   $     122.30      $   

Floor purchased price (put)

   $ 101.22      $   

Floor sold price (put)

   $ 81.34      $   

Fixed-Price Contracts (MBbls/d)

     60          

Average price per barrel

   $ 107.19      $   

 

(1) 

Includes the effects of offsetting purchased and sold natural-gas three-way collars of 500,000 MMBtu/d.

MMBtu—million British thermal units

MMBtu/d—million British thermal units per day

MBbls/d—thousand barrels per day

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

Marketing and Trading Derivative Activities  In addition to the positions in the above tables, the Company also engages in marketing and trading activities, which include physical product sales and related derivative transactions used to manage commodity-price risk. At June 30, 2012, the Company had fixed-price physical transactions related to natural gas totaling 12 billion cubic feet (Bcf), offset by derivative transactions for 12 Bcf. At December 31, 2011, the Company had fixed-price physical transactions related to natural gas totaling 22 Bcf, offset by derivative transactions for 21 Bcf, for a net position of 1 Bcf.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

6.  Derivative Instruments (Continued)

 

Interest-Rate Derivatives  Anadarko has outstanding interest-rate swap contracts as a fixed-rate payor to mitigate the interest-rate risk associated with anticipated debt issuances. 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.

The Company had the following outstanding interest-rate swaps at June 30, 2012:

 

millions except percentages       Reference Period     Weighted-Average  

Notional Principal Amount

       Start   End   Interest Rate

$                     250

            October 2012                   October 2022           4.91%

$                     750

    October 2012   October 2042   4.80%

$                     750

    June 2014   June 2024   6.00%

$                  1,100

    June 2014   June 2044   5.57%

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

 

                                                                                           
     Gross      Gross  
     Derivative Assets      Derivative Liabilities  
millions        June 30,           December 31,         June 30,        December 31,   

Balance Sheet Classification

       2012           2011         2012       2011  

Commodity derivatives

          

Other current assets

   $     860      $ 924      $ (212   $ (353

Other assets

     111        150        (25     (15

Accrued expenses

     8        5        (18     (33

Other liabilities

     7        1        (14     (17
  

 

 

    

 

 

    

 

 

   

 

 

 
     986        1,080        (269     (418
  

 

 

    

 

 

    

 

 

   

 

 

 

Interest-rate and other derivatives

          

Accrued expenses

                     (439     (391

Other liabilities

                     (898     (808
  

 

 

    

 

 

    

 

 

   

 

 

 
                     (1,337     (1,199
  

 

 

    

 

 

    

 

 

   

 

 

 

Total Derivatives

   $ 986      $     1,080      $     (1,606   $     (1,617
  

 

 

    

 

 

    

 

 

   

 

 

 

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

6.  Derivative Instruments (Continued)

 

Effect of Derivative InstrumentsStatement of Income  The realized and unrealized gain or loss amounts related to derivative instruments are presented below.

 

     Three Months Ended     Six Months Ended  
millions    June 30, 2012     June 30, 2012  

Classification of (Gain) Loss Recognized

   Realized     Unrealized     Total     Realized     Unrealized     Total  

Commodity derivatives

            

Gathering, processing, and marketing sales (1)

   $ (1   $ 8     $ 7     $ (3   $ 13     $ 10  

(Gains) losses on commodity derivatives, net

     (263     (157     (420     (400     (68     (468

Interest-rate and other derivatives

            

(Gains) losses on other derivatives, net

     2       374       376       2           138       140  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Derivative (gain) loss, net

   $     (262   $ 225     $ (37   $ (401   $ 83     $     (318
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

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

Classification of (Gain) Loss Recognized

   Realized     Unrealized     Total     Realized     Unrealized     Total  

Commodity derivatives

            

Gathering, processing, and marketing sales (1)

   $ 4     $ (4   $      $ 16     $ (5   $ 11  

(Gains) losses on commodity derivatives, net

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

Interest-rate and other derivatives

            

(Gains) losses on other derivatives, net

     2       142       144       2       83       85  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Derivative (gain) loss, net

   $ (21   $     (178   $     (199   $     (66   $ 75     $ 9  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) 

Represents the effect of marketing and trading derivative activities.

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

In addition, the Company has setoff agreements with certain financial institutions that may be exercised in the event of default and provide for contract termination and net settlement across all derivative types. At June 30, 2012, $470 million of the Company’s $1.6 billion gross derivative liability balance, and at December 31, 2011, $749 million of the Company’s $1.6 billion gross derivative liability balance, would have been eligible for setoff against the Company’s gross derivative asset balance in the event of default. Other than in the event of default, the Company does not net settle across derivative types, as settlement timing differs.

Some of the Company’s derivative instruments are subject to provisions that can require full or partial collateralization or immediate settlement of the Company’s obligations if certain credit-risk-related provisions are triggered. However, most of the Company’s derivative counterparties maintain secured positions with respect to the Company’s derivative liabilities under the Company’s $5.0 billion senior secured revolving credit facility ($5.0 billion Facility), the available capacity of which is sufficient to secure potential obligations to such counterparties.

At June 30, 2012, and December 31, 2011, the aggregate fair value of all derivative instruments with credit-risk-related contingent features for which a net liability position existed was $156 million and $2 million (net of collateral), respectively, included in accrued expenses on the Company’s Consolidated Balance Sheets.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

6.  Derivative Instruments (Continued)

 

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

The fair value of the Company’s derivative financial assets and liabilities, by input level within the fair-value hierarchy, is presented below.

 

                                                                                                                       

millions

June 30, 2012

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

Assets

             

Commodity derivatives

             

Financial institutions

   $ 2     $ 883     $     —       $ (219   $ (41   $ 625  

Other counterparties

            101               (33 )              68  
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Total derivative assets

   $ 2     $ 984     $       $     (252   $ (41   $ 693  
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Liabilities

             

Commodity derivatives

             

Financial institutions

   $ (3   $ (217   $       $ 219      $ 1     $   

Other counterparties

            (49             33               (16

Interest-rate and other derivatives

            (1,337                           (1,337
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Total derivative liabilities

   $     (3   $ (1,603   $       $ 252      $ 1     $ (1,353
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 
December 31, 2011                                      

Assets

             

Commodity derivatives

             

Financial institutions

   $ 3     $ 909     $       $ (323   $ (52   $ 537  

Other counterparties

            168               (51 )              117  
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Total derivative assets

   $ 3     $ 1,077     $       $ (374   $     (52   $ 654  
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Liabilities

             

Commodity derivatives

             

Financial institutions

   $ (4   $ (375   $       $ 361      $ 7     $ (11

Other counterparties

            (39             13               (26

Interest-rate and other derivatives

            (1,199                    130       (1,069
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Total derivative liabilities

   $ (4   $     (1,613   $       $ 374      $ 137     $     (1,106
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

 

(1) 

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

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

7.  Debt and Interest Expense

Debt  All of the Company’s outstanding debt is senior unsecured, except for borrowings under the $5.0 billion Facility. The following presents the Company’s outstanding debt:

 

                                             
millions        June 30,    
    2012     
     December 31, 
 2011 
 

Long-term notes and debentures

   $     15,521     $     16,452  

WES borrowings

     1,020       500  
  

 

 

   

 

 

 

Total debt at face value

   $ 16,541     $ 16,952  

Net unamortized discounts and premiums (1)

     (1,709     (1,722
  

 

 

   

 

 

 

Total borrowings

   $ 14,832     $ 15,230  
  

 

 

   

 

 

 

Less: Current portion of long-term debt

     1,739       170  
  

 

 

   

 

 

 

Total long-term debt

   $ 13,093     $ 15,060  
  

 

 

   

 

 

 

 

(1)

Unamortized discounts and premiums are amortized over the term of the related debt.

Fair Value  The Company uses a market approach to determine fair value of its fixed-rate debt using observable market data, which results in a Level 2 fair-value measurement. The carrying amount of floating-rate debt approximates fair value as the interest rates are variable and reflective of market rates. At June 30, 2012, and December 31, 2011, the estimated fair value of the Company’s total borrowings was $17.1 billion and $17.3 billion, respectively.

Debt Activity  The following presents the Company’s debt activity during the six months ended June 30, 2012.

 

millions        Carrying    
    Value     
   

Description

Balance at December 31, 2011

   $     15,230    

Borrowings

     319    

WES revolving credit facility

Repayments

     (131  

6.125% Senior Notes due 2012

     (40  

WES revolving credit facility

Other, net

     8    

Changes in debt premium or discount

  

 

 

   

Balance at March 31, 2012

   $ 15,386    
  

 

 

   

Issuance

     516    

WES 4.00% Senior Notes due 2022

Borrowings

     55    

WES revolving credit facility

Repayments

     (800  

$5.0 billion Facility

     (334  

WES revolving credit facility

Other, net

     9    

Changes in debt premium or discount

  

 

 

   

Balance at June 30, 2012

   $ 14,832    
  

 

 

   

Anadarko Revolving Credit Facility and Letter of Credit Facility  At June 30, 2012, the Company was in compliance with all applicable covenants contained in the $5.0 billion Facility, had outstanding borrowings of $1.7 billion at an interest rate of 1.75%, and had available borrowing capacity of $3.2 billion ($5.0 billion maximum capacity, less $1.7 billion of outstanding borrowings and $150 million of letter-of-credit capacity required to be maintained pursuant to the terms of the LOC Facility discussed below). The Company intends to repay the outstanding borrowings under the $5.0 billion Facility with cash on hand and cash realized from the resolution of the Algeria exceptional profits tax dispute within the next year and has classified these borrowings as current portion of long-term debt on the Company’s Consolidated Balance Sheet at June 30, 2012.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

7.  Debt and Interest Expense (Continued)

 

In 2011, the Company entered into an agreement with a financial institution to provide up to $400 million of letters of credit. In June 2012, the agreement was amended to reduce the amount of letters of credit to a maximum of $150 million (LOC Facility). Compensating balances deposited with the financial institution provide for reduced fees under the LOC Facility. These compensating balances may be withdrawn at any time, resulting in higher fees. At June 30, 2012, cash and cash equivalents includes $23 million of demand deposits serving as compensating balances for outstanding letters of credit.

WES Revolving Credit Facility  In the second quarter of 2012, WES repaid all outstanding borrowings under its five-year $800 million senior unsecured revolving credit facility (RCF) with net proceeds from its public offering of $520 million aggregate principal amount of 4.00% Senior Notes due 2022. At June 30, 2012, WES was in compliance with all covenants contained in the RCF.

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

 

                                                   
       Three Months Ended  
  June 30,  
        Six Months Ended    
     June 30,    
 
millions    2012     2011     2012     2011  

Current debt, long-term debt, and other

   $ 236     $ 250     $ 486     $ 498  

Capitalized interest

     (46     (34     (110     (62
  

 

 

   

 

 

   

 

 

   

 

 

 

Total interest expense

   $ 190     $ 216     $ 376     $ 436  
  

 

 

   

 

 

   

 

 

   

 

 

 

8.  Stockholders’ Equity

The reconciliation between basic and diluted earnings per share attributable to common stockholders is as follows:

 

                                                                   
       Three Months Ended  
  June 30,  
        Six Months Ended    
     June 30,    
 
millions except per-share amounts      2012        2011       2012       2011   

Net income (loss)

        

Net income (loss) attributable to common stockholders

   $ (89   $ 544     $ 2,067      $ 760  

Less: Distributions on participating securities

            1       1       1  

Less: Undistributed income allocated to participating securities

            3       12        4  
  

 

 

   

 

 

   

 

 

   

 

 

 

Basic

   $ (89   $ 540     $ 2,054      $ 755  
  

 

 

   

 

 

   

 

 

   

 

 

 

Diluted

   $ (89   $ 540      $ 2,054      $ 755   
  

 

 

   

 

 

   

 

 

   

 

 

 

Shares

        

Average number of common shares outstanding—basic

     500       498       499       497  

Dilutive effect of stock options and performance-based stock awards

            2       2       2  
  

 

 

   

 

 

   

 

 

   

 

 

 

Average number of common shares outstanding—diluted

     500       500       501       499  
  

 

 

   

 

 

   

 

 

   

 

 

 

Excluded (1)

     12       6       5       6  

Net income (loss) per common share

        

Basic

   $ (0.18   $ 1.09     $ 4.11      $ 1.52  

Diluted

   $ (0.18   $ 1.08     $ 4.10      $ 1.51  

Dividends per common share

   $ 0.09     $ 0.09     $ 0.18     $ 0.18  

 

(1)

Inclusion of certain shares would have had an anti-dilutive effect.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

9.  Commitments

In January 2012, the Company entered into a two-and-a-half-year lease agreement for a deepwater drilling rig expected to be delivered in late 2012. In July 2012, the Company entered into a three-year lease agreement for a deepwater drilling rig expected to be delivered in late 2013. These lease obligations total approximately $875 million, with aggregate future annual minimum lease payments of $13 million in 2012, $192 million in 2013, $317 million in 2014, $228 million in 2015, and $125 million in 2016.

10.   Contingencies

General  The Company is a defendant in a number of lawsuits and is involved in governmental proceedings and regulatory controls arising in the ordinary course of business, including, but not limited to, personal injury claims, title disputes, tax disputes, royalty claims, contract claims, oil-field contamination claims, and environmental claims, including claims involving assets owned by acquired companies. Anadarko is also subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. While the ultimate outcome and impact on the Company cannot be predicted with certainty, after consideration of recorded expense and liability accruals, management believes that the resolution of pending proceedings will not have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows.

The following discussion of the Company’s contingencies includes material developments with respect to matters previously reported in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011. There have been no new significant matters since the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.

Deepwater Horizon Events  In April 2010, the Macondo well in the Gulf of Mexico blew out and an explosion occurred on the Deepwater Horizon drilling rig. The well was operated by BP Exploration and Production Inc. (BP) and Anadarko held a 25% non-operated interest. In October 2011, the Company and BP entered into a settlement agreement, mutual releases, and agreement to indemnify, relating to the Deepwater Horizon events (Settlement Agreement). Pursuant to the Settlement Agreement, the Company is fully indemnified by BP against claims and damages arising under the Oil Pollution Act of 1990 (OPA), claims for natural resource damages (NRD) and assessment costs, and other potential damages. This indemnification is guaranteed by BP Corporation North America Inc. (BPCNA) and, in the event that the net worth of BPCNA declines below an agreed-upon amount, BP p.l.c. has agreed to become the sole guarantor. The Settlement Agreement does not indemnify Anadarko against potential fines, penalties, or punitive damages. The Company has not recorded a liability for any costs that are subject to indemnification by BP. For additional disclosure of the Deepwater Horizon events, the Company’s Settlement Agreement with BP, environmental claims under OPA, NRD claims, potential penalties and fines, and civil litigation, see Note 2—Deepwater Horizon Events in the Notes to the Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.

Penalties and Fines  In December 2010, the U.S. Department of Justice, on behalf of the United States, filed a civil lawsuit in the U.S. District Court in New Orleans, Louisiana (Louisiana District Court) against several parties, including Anadarko Petroleum Corporation and Anadarko E&P Company LP (AE&P), a subsidiary of Anadarko, seeking an assessment of civil penalties under the Clean Water Act (CWA) in an amount to be determined by the Louisiana District Court. In February 2012, the Louisiana District Court entered a declaratory judgment that, as a partial owner of the Macondo well, Anadarko is liable for civil penalties under Section 311 of the CWA and denied both the Company’s and the United States’ motions for summary judgment with respect to the liability of AE&P. The declaratory judgment addresses liability only, and does not address the amount of any civil penalty. In February 2012, the Louisiana District Court entered a stipulated order (Stipulated Order), agreed to by the Company and the United States, that the United States will not assert any claim for a CWA penalty against AE&P, and that the United States will not assert any other theories of liability under the CWA (e.g., operator or person-in-charge liability) against either Anadarko or AE&P. Further, the Stipulated Order reserved the issue of an assessment of a civil penalty against Anadarko until a later proceeding to be scheduled by the Louisiana District Court. The Company believes that the Stipulated Order does not have a material impact on Anadarko’s potential liability.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

10.   Contingencies (Continued)

 

As discussed below, numerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company. Certain state and local governments have appealed, or have provided indication of a likely appeal of the Louisiana District Court’s decision that only federal law, and not state law, applies to Deepwater Horizon event-related claims. If such an appeal is successful, state and/or local laws and regulations could become sources of penalties or fines against the Company.

Applicable accounting guidance requires the Company to accrue a liability if it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. The Louisiana District Court’s declaratory judgment in February 2012, satisfies the requirement that a loss, arising from the future assessment of a civil penalty against Anadarko, is probable. Notwithstanding, the Company currently cannot estimate the amount of any potential civil penalty. The CWA sets forth subjective criteria, including degree of fault and history of prior violations, which significantly influence the magnitude of CWA penalty assessments. As a result of the subjective nature of CWA penalty assessments, the Company currently cannot estimate the amount of any such penalty. Furthermore, the February 2012 settlement of Deepwater Horizon-related civil penalties (including those under the CWA) by the other non-operating partner with the United States and five affected Gulf states (Texas, Louisiana, Mississippi, Alabama, and Florida) does not affect the Company’s current conclusion regarding its ability to estimate potential fines and penalties. The Company lacks insight into those settlement discussions, retains legal counsel separate from the other non-operating party, and was not involved in any manner with respect to that settlement.

Given the Company’s lack of direct operational involvement in the event, as confirmed by the Louisiana District Court, and the subjective criteria of the CWA, the Company believes that its exposure to CWA penalties will not materially impact the Company’s consolidated financial position, results of operations, or cash flows.

Civil Litigation Damage Claims  Numerous Deepwater Horizon event-related civil lawsuits have been filed against BP and other parties, including the Company. This litigation has been consolidated into a federal Multidistrict Litigation (MDL) action pending before Judge Carl Barbier in the Louisiana District Court. Only OPA claims seeking economic loss damages against the Company remain. In addition, certain state and local governments have appealed, or have provided indication of a likely appeal of, the MDL court’s decision that only federal law, and not state law, applies to Deepwater Horizon event-related claims. The Company, pursuant to the Settlement Agreement, is fully indemnified by BP against losses arising as a result of claims for damages, irrespective of whether such claims are based on federal (including OPA) or state law.

The Louisiana District Court plans to hold a trial in Transocean’s Limitation of Liability case in the MDL. The first phase of the trial is to determine certain liability issues and the liability allocation among the parties alleged to be involved in or liable for the Deepwater Horizon events. In March 2012, BP and the Plaintiffs’ Steering Committee (PSC) entered into a tentative settlement agreement to resolve the substantial majority of economic loss and medical claims stemming from the Deepwater Horizon events. In light of this settlement agreement, the Louisiana District Court postponed the start of the trial until a future date and requested that the parties submit separate briefs that explain the parties’ opinions as to the impact of the tentative settlement on the Louisiana District Court’s previously issued trial plan. BP and the PSC jointly filed the proposed settlement agreement with the Louisiana District Court in April 2012. In May 2012, the Louisiana District Court issued its revised case management order (CMO) ruling that the first phase of the trial will commence in January 2013, and will address issues arising out of the conduct of various parties involved with the Deepwater Horizon events. The CMO provides that the Stipulated Order excusing Anadarko from participation in the first phase of the trial remains in effect. The CMO also provides that the second phase of trial will follow the first phase after a two-to-three week recess and will address source-control and qualification issues.

Two separate class action complaints were filed in June and August 2010, in the U.S. District Court for the Southern District of New York (New York District Court) on behalf of purported purchasers of the Company’s stock between June 9, 2009, and June 12, 2010, against Anadarko and certain of its officers. The complaints allege causes of action arising pursuant to the Securities Exchange Act of 1934 (Exchange Act) for purported misstatements and omissions regarding, among other things, the Company’s liability related to the Deepwater Horizon events. In March 2012, the New York District Court granted the Lead Plaintiff’s motion to transfer venue to the U.S. District Court for the Southern District of Texas – Houston Division (Texas District Court). In May 2012, the Texas District Court granted the defendants’ motion to transfer the consolidated action within the district to Judge Keith P. Ellis.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

10.   Contingencies (Continued)

 

In November 2011, the Company’s Board of Directors (Board) received a letter from a purported shareholder demanding that the Board investigate, address, remedy, and commence derivative proceedings against certain officers and directors for their alleged breach of fiduciary duty related to the Deepwater Horizon events. The Board has considered this demand and in February 2012 determined that it would not be in the best interest of the Company to pursue the issues alleged in the demand letter. In March 2012, the Company’s Board received a similar demand letter from a purported shareholder supplementing an original demand that had been made by the shareholder in September 2010 related to the Deepwater Horizon events. The Board has considered this demand and in April 2012 determined that it would not be in the best interest of the Company to pursue the issues alleged in the demand letter.

Given the various stages of these proceedings, the Company currently cannot assess the probability of losses, or reasonably estimate a range of any potential losses, related to ongoing proceedings. The Company intends to vigorously defend itself, its officers, and its directors in each of these proceedings, and will avail itself of any and all indemnities provided by BP against civil damages.

Remaining Liability Outlook  It is reasonably possible that the Company may recognize additional Deepwater Horizon event-related liabilities for potential fines and penalties, shareholder claims, and certain other claims not covered by the indemnification provisions of the Settlement Agreement; however, the Company does not believe that any potential liability attributable to the foregoing items, individually or in the aggregate, will have a material impact on the Company’s consolidated financial position, results of operations, or cash flows. This assessment takes into account certain qualitative factors, including the subjective and fault-based nature of CWA penalties, the Company’s indemnification by BP against certain damage claims as discussed above, BP’s creditworthiness, the merits of the shareholder claims, and directors and officers insurance coverage related to outstanding shareholder claims.

The Company will continue to monitor the MDL and other legal proceedings discussed above as well as federal investigations related to the Deepwater Horizon events, including review of the preliminary investigatory findings recently announced by the U.S. Chemical Safety Board. The Company cannot predict the nature of evidence that may be discovered during the course of legal proceedings and investigations, the timing of discovery, or the timing of completion of any legal proceedings or investigations.

Although the Company is fully indemnified by BP against OPA damage claims, NRD claims and assessment costs, and certain other potential liabilities, the Company may be required to recognize a liability for these amounts in advance of or in connection with recognizing a receivable from BP for the related indemnity payment. In all circumstances, however, the Company expects that any additional indemnified liability that may be recognized by the Company will be subsequently recovered from BP itself or through the guarantees of BPCNA or BP p.l.c.

Tronox Litigation  In January 2009, Tronox Incorporated (Tronox), a former subsidiary of Kerr-McGee Corporation (Kerr-McGee), which is a current subsidiary of Anadarko, and certain of Tronox’s subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. Subsequently, in May 2009, Tronox and certain of its affiliates filed a lawsuit against Anadarko and Kerr-McGee asserting a number of claims, including claims for actual and constructive fraudulent conveyance (Adversary Proceeding). Tronox alleges, among other things, that it was insolvent or undercapitalized at the time it was spun off from Kerr-McGee and seeks, among other things, to recover damages, including interest, in excess of $18.9 billion from Kerr-McGee and Anadarko, as well as litigation fees and costs. In accordance with Tronox’s Plan of Reorganization, the Adversary Proceeding is being prosecuted by the Anadarko Litigation Trust. Pursuant to the Anadarko Litigation Trust Agreement, the Anadarko Litigation Trust was “deemed substituted” for Tronox in the Adversary Proceeding as the party in such litigation. For purposes of this Form 10-Q, references to “Tronox” after February 2011 refer to the Anadarko Litigation Trust. For additional disclosure related to the Tronox Litigation, see Note 16—Contingencies—Tronox Litigation in the Notes to the Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.

The U.S. government was granted authority to intervene in the Adversary Proceeding, and in May 2009 asserted separate claims against Anadarko and Kerr-McGee under the Federal Debt Collection Procedures Act (FDCPA Complaint). In April 2012, Anadarko and Kerr-McGee filed an answer to the FDCPA Complaint.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

10.   Contingencies (Continued)

 

In February 2012, the Company filed a motion for partial summary judgment seeking dismissal of several claims, including all actual and constructive fraudulent transfer claims protected by Section 546(e) of the U.S. Bankruptcy Code. The court has not yet ruled on that issue. Trial began in May 2012 and is expected to last through September 2012.

The Company’s recent attempts to resolve the Adversary Proceeding through mediation and settlement discussions have reached an impasse and at this time the Company believes the likelihood of settlement is remote. The Company now considers litigation the probable form of final resolution of the Adversary Proceeding. Previously, the Company believed it probable that the parties would reach a settlement on reasonable terms and thus the Company considered a loss, via settlement, related to the Adversary Proceeding probable. Based on this assumption, a $275 million loss contingency was accrued in the first quarter of 2012, which increased the Company’s total estimated contingent loss accrual related to the Adversary Proceeding to $525 million as of March 31, 2012. Due to the change in the Company’s opinion as to the probable form of resolution of this matter, the Company reversed the settlement-based $525 million contingent loss accrual related to this matter in the second quarter of 2012.

The Company remains confident in the merits of its position, and continues to vigorously defend the claims asserted in the Adversary Proceeding. The Company does not believe a loss resulting from litigating the Adversary Proceeding is probable. Accounting guidance requires that contingent losses be probable in nature for loss recognition to be appropriate. Accordingly, the Company’s Consolidated Balance Sheet as of June 30, 2012, does not include a loss-contingency liability related to the litigation of the Adversary Proceeding.

Although the Company does not consider a loss related to the litigation of the Adversary Proceeding probable, it is reasonably possible that the Company could incur a loss as a result of litigating this matter. Despite the plaintiffs’ damage claims in excess of $18.9 billion, the Company currently believes a reasonable range of potential loss is zero to $1.4 billion. The low end of the Company’s estimated range of potential loss is based on the Company’s current belief that it will more likely than not prevail in defending against the claims asserted in the Adversary Proceeding. The high end of the Company’s estimated range of potential loss represents the amount of consideration received by Kerr-McGee at the time of the Tronox spin-off, approximately $985 million, plus interest thereon.

The Company’s estimated range of potential loss is based on the Company’s opinion regarding the current status of and likelihood of final resolution through litigation and could change as a result of developments in the Adversary Proceeding, or if the likelihood of settlement ceases to be remote. The Company’s ultimate financial obligation resulting from resolution of the Adversary Proceeding could vary, perhaps materially, from the Company’s above-stated estimated range of potential loss.

Separately, in July 2009, a consolidated class action complaint was filed in the New York District Court on behalf of purported purchasers of Tronox’s equity and debt securities between November 21, 2005, and January 12, 2009, against Anadarko, Kerr-McGee, several former Kerr-McGee officers and directors, several former Tronox officers and directors, and Ernst & Young LLP (Securities Case). The complaint alleges causes of action arising under Sections 10(b) and 20(a) of the Exchange Act for purported misstatements and omissions regarding, among other things, Tronox’s environmental-remediation and tort-claim liabilities. The plaintiffs allege, among other things, that these purported misstatements and omissions are contained in certain of Tronox’s public filings, including filings made in connection with Tronox’s initial public offering. The plaintiffs seek an unspecified amount of compensatory damages, including interest thereon, as well as litigation fees and costs. Certain parties, including Anadarko, Kerr-McGee, and the former Kerr-McGee officers and directors, reached a tentative settlement in this matter in April 2012, subject to approval by the court. The tentative settlement amount will be directly funded by the insurers for Tronox, Anadarko, and Kerr-McGee. As a result, offsetting gains and losses have been recorded to reflect the impact of the tentative settlement of the Securities Case.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

10.   Contingencies (Continued)

 

Other Litigation  In December 2008, Anadarko sold its interest in the Peregrino heavy-oil field offshore Brazil. The Company is currently litigating a dispute with the Brazilian tax authorities regarding the tax rate applicable to the transaction. Currently, $169 million, the amount of tax in dispute, resides in a judicially controlled Brazilian bank account, pending final resolution of the matter and is included in other assets on the Company’s Consolidated Balance Sheet as of June 30, 2012.

In July 2009, the lower judicial court ruled in favor of the Brazilian tax authorities. The Company appealed this decision to the Brazilian Regional courts, which upheld the lower court’s ruling in favor of the Brazilian tax authorities in December 2011. In April 2012, the Company filed simultaneous appeals to the Brazilian Superior court and the Brazilian Supreme court. The Brazilian Supreme court is not required to hear the case.

The Company believes that it will, more likely than not, prevail in Brazilian courts. Therefore, no tax liability has been recorded for Peregrino divestiture-related litigation as of June 30, 2012. The Company continues to vigorously defend itself in Brazilian courts.

Deepwater Drilling Moratorium and Other Related Matters  In June 2010, as a result of the moratorium on drilling in the Gulf of Mexico between mid-May 2010 and mid-October 2010 (Moratorium), the Company gave written notice of termination to a drilling contractor of a rig placed in force majeure in May 2010, and filed a lawsuit in the Texas District Court against the drilling contractor seeking a judicial declaration that the Company’s interpretation of the drilling contract was correct and that the contract terminated on June 19, 2010. The drilling contractor filed an Original Answer in July 2010 denying the Moratorium constituted a force majeure event and asserting that Anadarko had breached the drilling contract. In the second quarter of 2012, the Company and the drilling contractor mutually agreed to dismiss all claims related to this dispute. The resolution of this dispute did not have a material impact on Anadarko’s consolidated financial position, results of operations, or cash flows.

Algeria Exceptional Profits Tax Settlement  In 2006, the Algerian parliament approved legislation establishing an exceptional profits tax on foreign companies’ Algerian oil production and issued regulations implementing this legislation. The Company notified Sonatrach of the Company’s disagreement with Sonatrach’s collection of the exceptional profits tax and initiated arbitration against Sonatrach in February 2009. The arbitration hearing was held in June 2011.

In March 2012, Anadarko reached an agreement with Sonatrach to resolve the exceptional profits tax dispute. The agreement was approved by the Algerian government and provides for delivery to the Company of crude oil valued at approximately $1.7 billion and the elimination of $62 million of the Company’s previously recorded and unpaid transportation charges. The crude oil is to be delivered to the Company over a 12-month period which began in June 2012. At June 30, 2012, a receivable of $1.6 billion on the Company’s Consolidated Balance Sheet was included in the oil and gas exploration and production reporting segment. The Company recognized a $1.8 billion credit in the Costs and Expenses section of the Consolidated Statement of Income for the six months ended June 30, 2012, to reflect the effect of this agreement on previously recorded expenses. Additionally, the parties agreed to an amendment to the existing Production Sharing Agreement (PSA) that provides the Company increased sales volumes in future periods. The amendment also confirms the duration for each exploitation license granted under the PSA will be 25 years from the date the license was awarded.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

11.   Income Taxes

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

 

                                           
     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
millions except percentages      2012          2011          2012          2011    

Income tax expense (benefit)

   $ 164       $ 440      $ 516       $ 706  

Effective tax rate

     174%         44%         20%         47%   

The increase from the 35% U.S. federal statutory rate for the three months ended June 30, 2012, was primarily attributable to the foreign tax rate differential and valuation allowances, recurring accrual of the Algerian exceptional profits tax, and U.S. tax impact from losses and restructuring of foreign operations. The decrease from the 35% U.S. federal statutory rate for the six months ended June 30, 2012, was primarily attributable to the resolution of the Algeria exceptional profits tax dispute. This amount was partially offset by the foreign tax rate differential and valuation allowances, recurring accrual of the Algerian exceptional profits tax, and U.S. tax impact from losses and restructuring of foreign operations.

The increase from the 35% U.S. federal statutory rate for the three and six months ended June 30, 2011, was primarily attributable to the recurring accrual of the Algerian exceptional profits tax, foreign tax rate differential and valuation allowances, U.S. tax on foreign income inclusions and distributions, state income taxes, and items resulting from business acquisitions. These items were partially offset by the U.S. income tax benefits associated with foreign losses and restructuring of foreign operations.

12.   Supplemental Cash Flow Information

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

 

           Six Months Ended      
June 30,
 
millions    2012     2011  

Cash paid (received)

    

Interest

   $     354     $     415  

Income taxes

   $ (40   $ 82  

Non-cash investing activities

    

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

   $ 31     $ 4  

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

   $      $ 21  

13.   Segment Information

Anadarko’s business segments are separately managed due to distinct operational differences and unique technology, distribution, and marketing requirements. The Company’s three reporting segments are oil and gas exploration and production, midstream, and marketing. The oil and gas exploration and production segment explores for and produces natural gas, crude oil, condensate, and NGLs. The midstream segment engages in gathering, processing, treating, and transporting Anadarko and third-party oil, natural-gas, and NGLs production. The midstream reporting segment consists of two operating segments, WES and other midstream activities, which are aggregated into one reporting segment due to similar financial and operating characteristics. The marketing segment sells most of Anadarko’s production, as well as third-party purchased volumes.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

13.   Segment Information (Continued)

 

To assess the performance of Anadarko’s operating segments, the chief operating decision maker analyzes income (loss) before income taxes; interest expense; exploration expense; depreciation, depletion, and amortization (DD&A); impairments; Deepwater Horizon settlement and related costs; Algeria exceptional profits tax settlement; Tronox-related contingent loss; unrealized (gains) losses on derivatives, net; and realized (gains) losses on other derivatives, net, less net income attributable to noncontrolling interests (Adjusted EBITDAX). The Company’s definition of Adjusted EBITDAX excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Adjusted EBITDAX also excludes exploration expense, as it is not an indicator of operating efficiency for a given reporting period. However, exploration expense is monitored by management as part of costs incurred in exploration and development activities. Similarly, DD&A and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. Anadarko’s definition of Adjusted EBITDAX excludes Deepwater Horizon settlement and related costs, Algeria exceptional profits tax settlement, and Tronox-related contingent loss, as these costs are outside the normal operations of the Company. See Note 10—Contingencies. Finally, unrealized (gains) losses on derivatives, net and realized (gains) losses on other derivatives, net are excluded from Adjusted EBITDAX because these (gains) losses are not considered a measure of asset operating performance. Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions to stockholders.

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

 

           Three Months Ended      
June 30,
          Six Months Ended      
June 30,
 
millions    2012     2011             2012                     2011          

Income (loss) before income taxes

   $ 94      $ 1,002     $ 2,629      $ 1,505  

Exploration expense

     1,121       236       1,365       415  

DD&A

     1,027       985       1,957       1,970  

Impairments

     112       102       162       104  

Deepwater Horizon settlement and related costs (1)

     3       9       11       35  

Algeria exceptional profits tax settlement (2)

                       (1,804       

Tronox-related contingent loss (2)

     (525            (250       

Interest expense

     190       216       376       436  

Unrealized (gains) losses on derivatives, net

     225       (178     83       75  

Realized (gains) losses on other derivatives, net (2)

     2       2       2       2  

Less: Net income attributable to noncontrolling interests

     19       18       46       39  
  

 

 

   

 

 

   

 

 

   

 

 

 

Consolidated Adjusted EBITDAX

   $     2,230     $     2,356     $ 4,485     $     4,503  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) 

In the third quarter of 2011, the Company revised the definition of Adjusted EBITDAX to exclude Deepwater Horizon settlement and related costs. Prior periods have been adjusted to reflect this change.

(2) 

In the first quarter of 2012, the Company revised the definition of Adjusted EBITDAX to exclude Algeria exceptional profits tax settlement, Tronox-related contingent loss, and realized (gains) losses on other derivatives, net. Prior periods have been adjusted to reflect this change.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

13.   Segment Information (Continued)

 

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

 

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

Three Months Ended June 30, 2012

          

Sales revenues

   $ 1,888     $ 81     $ 1,231     $      $ 3,200  

Intersegment revenues

     1,035       220       (1,124     (131       

Gains (losses) on divestitures and other, net

     (12     (1            35       22  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues and other

     2,911       300       107       (96     3,222  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating costs and expenses (1)

     873       174       158       33       1,238  

Realized (gains) losses on commodity derivatives, net

                          (263     (263

Other (income) expense, net (2)

                          6       6  

Net income attributable to noncontrolling interests

            19                     19  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses and other

     873       193       158       (224     1,000  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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

                   8              8  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDAX

   $ 2,038     $     107     $ (43   $ 128     $ 2,230  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Three Months Ended June 30, 2011

          

Sales revenues

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

Intersegment revenues

     1,330       223           (1,448         (105       

Gains (losses) on divestitures and other, net

     (114     20              36       (58
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues and other

     3,287       341       117       (69     3,676  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating costs and expenses (1)

     921       199       135       88       1,343  

Realized (gains) losses on commodity derivatives, net

                          (27     (27

Other (income) expense, net (2)

                          (18     (18

Net income attributable to noncontrolling interests

            18                     18  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses and other

     921       217       135       43       1,316  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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

                   (4            (4
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDAX

   $ 2,366     $ 124     $ (22   $ (112   $ 2,356  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)

Operating costs and expenses excludes exploration expense, DD&A, impairments, Deepwater Horizon settlement and related costs, and Algeria exceptional profits tax settlement since these expenses are excluded from Adjusted EBITDAX.

(2)

Other (income) expense, net excludes Tronox-related contingent loss since this expense is excluded from Adjusted EBITDAX.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

13.   Segment Information (Continued)

 

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

Six Months Ended June 30, 2012

          

Sales revenues

   $     3,787     $     168     $ 2,657     $      $ 6,612  

Intersegment revenues

     2,209       469           (2,419         (259       

Gains (losses) on divestitures and other, net

     (29     (2            88       57  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues and other

     5,967       635       238       (171     6,669  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating costs and expenses (1)

     1,799       363       312       81       2,555  

Realized (gains) losses on commodity derivatives, net

                          (400     (400

Other (income) expense, net (2)

                          (4     (4

Net income attributable to noncontrolling interests

            46                     46  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses and other

     1,799       409       312       (323     2,197  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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

                   13              13  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDAX

   $ 4,168     $ 226     $ (61   $ 152     $ 4,485  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Six Months Ended June 30, 2011

          

Sales revenues

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

Intersegment revenues

     2,455       433       (2,680     (208       

Gains (losses) on divestitures and other, net

     (114     20              65       (29
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues and other

     6,208       615       249       (143     6,929  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating costs and expenses (1)

     1,762       365       271       110       2,508  

Realized (gains) losses on commodity derivatives, net

                          (84     (84

Other (income) expense, net (2)

                          (42     (42

Net income attributable to noncontrolling interests

            39                     39  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses and other

     1,762       404       271       (16     2,421  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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

                   (5            (5
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDAX

   $ 4,446     $ 211     $ (27   $ (127   $ 4,503  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)

Operating costs and expenses excludes exploration expense, DD&A, impairments, Deepwater Horizon settlement and related costs, and Algeria exceptional profits tax settlement since these expenses are excluded from Adjusted EBITDAX.

(2)

Other (income) expense, net excludes Tronox-related contingent loss since this expense is excluded from Adjusted EBITDAX.

 

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ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

14.   Pension Plans and Other Postretirement Benefits

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

During the six months ended June 30, 2012, the Company made contributions of $32 million to its funded pension plans, $2 million to its unfunded pension plans, and $9 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 2012, the Company expects to contribute approximately $88 million to its funded pension plans, approximately $32 million to its unfunded pension plans, and approximately $10 million to its unfunded other postretirement benefit plans.

The following sets forth the components of net periodic benefit cost for the Company’s pension and other postretirement benefit plans.

 

             Pension Benefits                      Other Benefits           
millions            2012                     2011                     2012                      2011          

Three Months Ended June 30

         

Service cost

   $ 19     $ 19     $ 3      $ 2  

Interest cost

     22       22       4        4  

Expected return on plan assets

     (22     (22               

Amortization of net actuarial loss (gain)

     23       21                 

Amortization of net prior service cost (credit)

                   1          
  

 

 

   

 

 

   

 

 

    

 

 

 

Net periodic benefit cost

   $ 42     $ 40     $ 8      $ 6  
  

 

 

   

 

 

   

 

 

    

 

 

 

Six Months Ended June 30

         

Service cost

   $ 38     $ 39     $ 5      $ 4  

Interest cost

     43       43       8        8  

Expected return on plan assets

         (45         (43               

Amortization of net actuarial loss (gain)

     46       42                 

Amortization of net prior service cost (credit)

            1       1          
  

 

 

   

 

 

   

 

 

    

 

 

 

Net periodic benefit cost

   $ 82     $ 82     $     14      $     12  
  

 

 

   

 

 

   

 

 

    

 

 

 

 

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Table of Contents

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

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

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

 

   

the Company’s assumptions about the energy market;

 

   

production levels;

 

   

reserve levels;

 

   

operating results;

 

   

competitive conditions;

 

   

technology;

 

   

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

 

   

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

 

   

volatility in the commodity-futures market;

 

   

the weather;

 

   

inflation;

 

   

the availability of goods and services;

 

   

drilling risks;

 

   

future processing volumes and pipeline throughput;

 

   

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

 

   

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

 

   

the ability of BP Exploration & Production Inc. (BP) to meet its indemnification obligations to the Company for, among other things, damage claims arising under the Oil Pollution Act of 1990 (OPA), claims for natural resource damages (NRD) and associated damage-assessment costs, and any claims arising under the Operating Agreement (OA) for the Macondo well, as well as the ability of BP Corporation North America Inc. (BPCNA) and BP p.l.c. to satisfy their guarantees of such indemnification obligations;

 

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Table of Contents
   

the impact of remaining claims related to the Deepwater Horizon events, including, but not limited to, fines, penalties, and punitive damages against which the Company is not indemnified by BP;

 

   

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

 

   

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

 

   

civil or political unrest in a region or country;

 

   

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

 

   

volatility in the securities, capital, or credit markets and related risks such as general credit, liquidity and interest-rate risk;

 

   

the Company’s ability to successfully monetize select assets, repay its debt, and the impact of changes in the Company’s credit ratings;

 

   

disruptions in international crude oil cargo shipping activities;

 

   

electronic, cyber, and physical security breaches;

 

   

the supply and demand, technological, political, and commercial conditions associated with long-term development and production projects in domestic and international locations; 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 2011 Annual Report on Form 10-K, 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 Part I, Item 1, the information set forth in Risk Factors under Part II, Item 1A as well as the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in Part II, Item 8 of the 2011 Annual Report on Form 10-K, and the information set forth in the Risk Factors under Part I, Item 1A of the 2011 Annual Report on Form 10-K. Unless the context otherwise requires, the terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries.

OVERVIEW

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

 

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Table of Contents

Significant operating and financial activities during the second quarter of 2012 include the following:

Overall

 

   

Anadarko achieved second-quarter sales volumes of 742 thousand barrels of oil equivalent per day (MBOE/d), representing an 8% increase over the second quarter of 2011.

 

   

The Company achieved second-quarter liquids sales volumes of 318 thousand barrels per day (MBbls/d), representing a 7% increase over the second quarter of 2011.

United States Onshore

 

   

The Company’s Rocky Mountains Region (Rockies) achieved second-quarter sales volumes of 317 MBOE/d, representing a 6% increase over the second quarter of 2011, primarily due to increased sales volumes from the Wattenberg field and the Greater Natural Buttes area.

 

   

The Southern and Appalachia Region achieved second-quarter sales volumes of 192 MBOE/d, representing a 37% increase over the second quarter of 2011, primarily due to increased sales volumes from the Eagleford and Marcellus shales.

Gulf of Mexico

 

   

The Company’s Gulf of Mexico second-quarter sales volumes were 133 MBOE/d, representing a 5% decrease from the second quarter of 2011, primarily due to natural production declines, partially offset by the impact of a full quarter of production from Caesar/Tonga.

 

   

The Company successfully drilled the Heidelberg sidetrack appraisal well (44.25% working interest) in Green Canyon Block 903, which defined the down-dip limits of the Heidelberg field.

 

   

The Company participated in the successful drilling of a third Vito appraisal well (18.67% working interest) in the Mississippi Canyon area, encountering approximately 620 net feet of oil pay.

International

 

   

The Company’s International second-quarter sales volumes were 85 MBOE/d, representing a 7% decrease from the second quarter of 2011, primarily due to the timing of cargo liftings in Ghana.

 

   

Offshore Mozambique, the Company successfully drilled the Barquentine-4 appraisal well, as well as the Golfinho and Atum discovery wells (all at 36.5% working interest).

 

   

Offshore Mozambique, the Company successfully tested the Barquentine-1 well (36.5% working interest), achieving an equipment-constrained flow rate of 100 million cubic feet per day (MMcf/d).

 

   

Offshore Côte d’Ivoire, the Company successfully drilled the Paon exploration well (40% working interest), encountering more than 100 net feet of light-oil pay.

Financial

 

   

The Company generated approximately $2.0 billion of cash flows from operations and ended the quarter with $2.8 billion of cash on hand.

 

   

Anadarko’s net loss attributable to common stockholders for the second quarter of 2012 totaled $89 million, which included $844 million for impairments of certain unproved properties.

 

   

The Company repaid $800 million of borrowings under the senior secured revolving credit facility, which matures in September 2015 ($5.0 billion Facility).

 

   

The Company received the first crude-oil delivery related to the resolution of the Algeria exceptional profits tax dispute.

 

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Table of Contents

The following discussion pertains to Anadarko’s results of operations, financial condition, and changes in financial condition. Any increases or decreases “for the three months ended June 30, 2012,” refer to the comparison of the three months ended June 30, 2012, to the three months ended June 30, 2011, and any increases or decreases “for the six months ended June 30, 2012,” refer to the comparison of the six months ended June 30, 2012, to the six months ended June 30, 2011. The primary factors that affect the Company’s results of operations include commodity prices for natural gas, crude oil, and NGLs; sales volumes; the Company’s ability to discover additional oil and natural-gas reserves; the cost of finding such reserves; and operating costs.

RESULTS OF OPERATIONS

 

Selected Data

 

                                           
     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
millions except per-share amounts      2012         2011         2012         2011    

Financial Results

        

Revenues and other

   $ 3,222     $ 3,676     $ 6,669     $ 6,929  

Costs and expenses

     3,501       2,675       4,246       5,032  

Other (income) expense

     (373     (1     (206     392  

Income tax expense (benefit)

     164        440       516        706  

Net income (loss) attributable to common stockholders

   $ (89   $ 544     $ 2,067      $ 760  

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

   $ (0.18   $ 1.08     $ 4.10      $ 1.51  

Average number of common shares outstanding—diluted

     500       500       501       499  

Operating Results

        

Adjusted EBITDAX (1)

   $ 2,230     $ 2,356     $ 4,485     $ 4,503  

Sales volumes (MMBOE)

     68       62       132       124  

 

MMBOE—millions of barrels of oil equivalent

 

(1) 

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

FINANCIAL RESULTS

Net Income (Loss) Attributable to Common Stockholders    For the second quarter of 2012, Anadarko’s net loss attributable to common stockholders totaled $89 million, or $0.18 per share (diluted), compared to net income attributable to common stockholders of $544 million, or $1.08 per share (diluted), for the second quarter of 2011. Anadarko’s net loss for the three months ended June 30, 2012, included $844 million for impairments of certain unproved properties. For the six months ended June 30, 2012, Anadarko’s net income attributable to common stockholders totaled $2.1 billion, or $4.10 per share (diluted), compared to net income attributable to common stockholders of $760 million, or $1.51 per share (diluted), for the same period of 2011. As discussed more fully below, Anadarko’s net income for the six months ended June 30, 2012, included $1.8 billion related to the favorable resolution of the exceptional profits tax dispute with Sonatrach and $844 million for impairments of certain unproved properties.

 

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Table of Contents

Sales Revenues and Volumes

 

     Three Months Ended
June  30,
     Six Months Ended
June  30,
 
millions except percentages    2012      Inc/(Dec)
vs. 2011
     2011      2012      Inc/(Dec)
vs. 2011
     2011  

Sales Revenues

                 

Natural-gas sales

   $ 496        (43)%        $ 870      $ 1,069        (38)%         $ 1,724   

Oil and condensate sales

     2,222        (1)              2,236        4,466        10               4,043  

Natural-gas liquids sales

     282        (24)              370        624        (11)              703  
  

 

 

       

 

 

    

 

 

       

 

 

 

Total

   $     3,000        (14)            $     3,476      $     6,159        (5)            $     6,470  
  

 

 

       

 

 

    

 

 

       

 

 

 

Anadarko’s total sales revenues for the three months ended June 30, 2012, decreased primarily due to lower average commodity prices, partially offset by higher sales volumes for all products. Anadarko’s total sales revenues for the six months ended June 30, 2012, decreased primarily due to lower average natural-gas and NGLs prices, partially offset by higher sales volumes for all products and higher average prices for crude oil.

 

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

2011 sales revenues

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

Changes associated with sales volumes

     81       156       22       259  

Changes associated with prices

         (455         (170         (110         (735
  

 

 

   

 

 

   

 

 

   

 

 

 

2012 sales revenues

   $ 496     $ 2,222     $ 282     $ 3,000  
  

 

 

   

 

 

   

 

 

   

 

 

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

2011 sales revenues

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

Changes associated with sales volumes

     91       258       44       393  

Changes associated with prices

         (746     165           (123     (704
  

 

 

   

 

 

   

 

 

   

 

 

 

2012 sales revenues

   $ 1,069     $     4,466     $     624     $ 6,159  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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Table of Contents
     Three Months Ended
June  30,
     Six Months Ended
June  30,
 
Sales Volumes        2012          Inc/(Dec)
vs. 2011
         2011              2012          Inc/(Dec)
vs. 2011
         2011      

Barrels of Oil Equivalent

                 

(MMBOE except percentages)

                 

United States

     60        11%             54        116        6%             109  

International

     8        (7)               8        16        —                15  
  

 

 

       

 

 

    

 

 

       

 

 

 

Total

     68        8               62        132        6               124  
  

 

 

       

 

 

    

 

 

       

 

 

 

Barrels of Oil Equivalent per Day

                 

(MBOE/d except percentages)

                 

United States

     657        11%             594        639        6%             602  

International

     85        (7)               91        84        (2)               86  
  

 

 

       

 

 

    

 

 

       

 

 

 

Total

     742        8               685        723        6               688  
  

 

 

       

 

 

    

 

 

       

 

 

 

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 Note 6—Derivative Instruments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q and Other (Income) Expense—(Gains) Losses on Commodity Derivatives, net. Production of natural gas, crude oil, and NGLs usually is 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,
 
         2012         

Inc/(Dec)
vs. 2011

       2011              2012         

Inc/(Dec)
vs. 2011

       2011      

United States

                 

Sales volumes—Bcf

     230      9%          212        450      5%          429  

                            MMcf/d

         2,544      9                 2,326        2,480      5             2,369  

Price per Mcf

   $ 2.15      (48)          $ 4.11      $ 2.37      (41)          $ 4.02  

Natural-gas sales revenues (millions)

   $ 496      (43)          $ 870      $     1,069      (38)          $     1,724  

 

Bcf—billion cubic feet

MMcf/d—million cubic feet per day

The Company’s natural-gas sales volumes increased 218 MMcf/d and 111 MMcf/d for the three and six months ended June 30, 2012, respectively. These increases were due to higher sales volumes in the Southern and Appalachia Region of 229 MMcf/d and 173 MMcf/d, respectively, primarily as a result of drilling in the Marcellus and Eagleford shales, and higher sales volumes in the Rockies of 81 MMcf/d and 65 MMcf/d, respectively, associated with continued drilling in the Greater Natural Buttes area and the Wattenberg field. These increases were largely offset by reduced sales volumes for the three and six months ended June 30, 2012, in the Gulf of Mexico of 92 MMcf/d and 127 MMcf/d, respectively, primarily due to natural production declines.

The average natural-gas price Anadarko received decreased for the three and six months ended June 30, 2012, due to increased domestic production resulting in above-average U.S. natural-gas storage levels.

 

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Table of Contents

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

 

     Three Months Ended
June  30,
     Six Months Ended
June  30,
 
     2012      Inc/(Dec)
vs. 2011
     2011      2012      Inc/(Dec)
vs. 2011
     2011  

United States

                 

Sales volumes—MMBbls

     15        16%          12        27        12%          24  

                            MBbls/d

     156        16            134        148        12            133  

Price per barrel

   $ 98.20        (6)          $ 104.68      $ 101.76        4          $ 98.23  

International

                 

Sales volumes—MMBbls

     8        (7)%         8        16        —%         15  

                            MBbls/d

     85        (7)            91        84        (2)            86  

Price per barrel

   $ 106.77        (7)          $ 115.33      $ 113.30        5          $ 107.91  

Total

                 

Sales volumes—MMBbls

     23        7%          20        43        6%          39  

                            MBbls/d

     241        7            225        232        6            219  

Price per barrel

   $     101.22        (7)          $     108.99      $     105.94        4          $     102.04  

Oil and condensate sales revenues (millions)

   $ 2,222        (1)          $ 2,236      $ 4,466        10          $ 4,043  

 

MMBbls—million barrels

MBbls/d—thousand barrels per day

Anadarko’s crude-oil and condensate sales volumes increased 16 MBbls/d and 13 MBbls/d for the three and six months ended June 30, 2012, respectively. Increased drilling in the Wattenberg field led to sales-volume improvements in the Rockies of 6 MBbls/d for both the three and six months ended June 30, 2012. In addition, for the three and six months ended June 30, 2012, sales volumes in the Gulf of Mexico increased 8 MBbls/d and 2 MBbls/d, respectively, attributable to the start of oil production at Caesar/Tonga in March 2012. Increased activity in the Eagleford shale and Bone Spring/Avalon formations also contributed to increased sales volumes in the Southern and Appalachia Region of 9 MBbls/d and 7 MBbls/d, for the three and six months ended June 30, 2012, respectively. The increase for the three months ended June 30, 2012, was partially offset by lower sales volumes in Ghana of 9 MBbls/d due to the timing of cargo liftings.

Anadarko’s average crude-oil price received decreased for the three months ended June 30, 2012, primarily due to increasing macroeconomic concerns in Europe and China. Anadarko’s average crude-oil price received increased for the six months ended June 30, 2012, due to concerns about potential supply disruptions from political unrest in the Middle East, which more than offset macroeconomic concerns.

 

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

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
     2012      Inc/(Dec)
vs. 2011
     2011      2012      Inc/(Dec)
vs. 2011
     2011  

United States

                 

Sales volumes—MMBbls

     7        6%           6        14        6%           13  

                            MBbls/d

     77        6             72        78        6             74  

Price per barrel

   $     40.41        (28)           $     56.21      $     43.82        (16)           $     52.47  

Natural-gas liquids sales revenues (millions)

   $ 282        (24)           $ 370      $ 624        (11)           $ 703  

NGLs sales represent revenues from the sale of product derived from the processing of Anadarko’s natural-gas production. For the three and six months ended June 30, 2012, the Company’s NGLs sales volumes increased by 5 MBbls/d and 4 MBbls/d, respectively, as a result of drilling in liquids-rich areas, primarily at Wattenberg and Greater Natural Buttes in the Rockies and the Eagleford shale in the Southern and Appalachia Region.

The average NGLs price decreased for the three and six months ended June 30, 2012, primarily due to lower market prices for ethane and propane. The demand for ethane decreased due to several petrochemical plants, the primary feedstock for which is ethane, being offline a portion of the first and second quarter for maintenance and conversion upgrades. Also, mild winter temperatures across much of the United States reduced demand for propane and contributed to above-average levels of propane stockpiles.

Gathering, Processing, and Marketing Margin

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
millions except percentages    2012      Inc/(Dec)
vs. 2011
     2011      2012      Inc/(Dec)
vs. 2011
     2011  

Gathering, processing, and marketing sales

   $        200        (22)%         $        258      $        453        (7)%         $        488  

Gathering, processing, and marketing expenses

     178        (13)              205        367        (2)              376  
  

 

 

       

 

 

    

 

 

       

 

 

 

Margin

   $ 22        (58)            $ 53      $ 86        (23)            $ 112  
  

 

 

       

 

 

    

 

 

       

 

 

 

For the three and six months ended June 30, 2012, the gathering, processing, and marketing margin decreased primarily due to lower commodity prices, which led to reduced natural-gas processing margins. Also, for the six months ended June 30, 2012, marketing margins decreased due to lower margins on sales from inventory caused by lower prices and volumes, as well as a write-down of natural-gas inventory to market value. These decreases for the three and six months ended June 30, 2012, were partially offset by an increase in gathering and processing revenues associated with increased throughput volumes across several of Anadarko’s fee-based systems, and additional margin provided by midstream assets acquired in February 2011 and May 2011.

Gains (Losses) on Divestitures and Other, net

Losses on divestitures during the three and six months ended June 30, 2012, were $12 million and $29 million, respectively, primarily related to oil and gas exploration and production reporting segment domestic properties. Gains (losses) on divestitures for the three and six months ended June 30, 2011, included a loss of $76 million related to the effective termination of natural-gas processing contracts between the Company and the previous owner of the Wattenberg Plant, which occurred in connection with the Company’s purchase of the plant. The loss represents the aggregate amount by which the Company’s contracts with the previous owner of the Wattenberg Plant were unfavorable as compared to current market transactions for the same or similar services at the date of the Company’s acquisition of the plant. This loss was partially offset by the recognition of a $21 million gain from the acquisition-date fair-value remeasurement of the Company’s pre-acquisition equity interest in the Wattenberg Plant.

 

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Costs and Expenses

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
     2012      Inc/(Dec)
vs. 2011
     2011      2012      Inc/(Dec)
vs. 2011
     2011  

Oil and gas operating (millions)

   $ 249         6%          $ 236      $ 491        5%          $ 468  

Oil and gas operating—per BOE

         3.68        (3)                  3.79            3.73        (1)                  3.76  

Oil and gas transportation and other (millions)

     223        8              207        463        11              416  

Oil and gas transportation and other—per BOE

     3.30        (1)              3.32        3.51        5              3.35  

For the three and six months ended June 30, 2012, oil and gas operating expenses increased by $13 million and $23 million, respectively. For the three and six months ended June 30, 2012, operating expenses increased $21 million and $33 million, respectively, due to increased activity in Ghana and the Bone Spring/Avalon formations. Also, for the three and six months ended June 30, 2012, water-handling costs increased $5 million and $8 million, respectively, primarily due to increased activity in the Rockies, and surface maintenance costs increased $7 million for the six months ended June 30, 2012, primarily due to increased activity in the Gulf of Mexico. Partially offsetting these increases were lower costs for workovers of $16 million and $24 million for the three and six months ended June 30, 2012, respectively, primarily in the Rockies and the Gulf of Mexico. For the three and six months ended June 30, 2012, oil and gas operating expenses per barrel of oil equivalent (BOE) decreased by $0.11 and $0.03, respectively, primarily due to increased operating efficiencies and increased sales volumes.

For the three and six months ended June 30, 2012, oil and gas transportation and other expenses increased by $16 million and $47 million, respectively, primarily due to higher gas gathering and transportation costs attributable to higher volumes and increased costs attributable to growth in the Company’s U.S. onshore asset base. This increase was partially offset by a reversal of $25 million of previously accrued rig termination fees for a deepwater drilling rig in the Gulf of Mexico. This expense reversal resulted from a dispute settlement with the drilling contractor. See Note 10—Contingencies—Deepwater Drilling Moratorium and Other Related Matters in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information. Oil and gas transportation and other expenses per BOE decreased by $0.02 for the three months ended June 30, 2012, primarily due to increased sales volumes and the reversal of rig termination fees. Oil and gas transportation and other expenses per BOE increased by $0.16 for the six months ended June 30, 2012, primarily due to the higher costs discussed above.

 

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Table of Contents

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
millions except percentages    2012      Inc/(Dec)
vs. 2011
     2011      2012      Inc/(Dec)
vs. 2011
     2011  

Exploration Expense

                 

Dry hole expense

   $ 115        174%        $ 42      $ 204        NM            $ 58  

Impairments of unproved properties

     923        NM             95        983        NM              169  

Geological and geophysical expenses

     14        (73)            52        49        (51)%         100  

Exploration overhead and other

     69        47            47        129        47             88  
  

 

 

       

 

 

    

 

 

       

 

 

 

Total exploration expense

   $     1,121        NM           $        236      $     1,365        NM            $        415  
  

 

 

       

 

 

    

 

 

       

 

 

 

 

NM—percentage change does not provide

meaningful information

Exploration expense increased by $885 million and $950 million for the three and six months ended June 30, 2012, respectively. During the second quarter of 2012, the Company recognized $844 million for impairments of certain unproved properties in the Rockies and the Gulf of Mexico. Approximately $720 million was associated with the impairment of unproved Powder River coalbed methane properties in the Rockies primarily due to lower natural-gas prices. The Company also recognized $124 million associated with an unproved Gulf of Mexico natural-gas property due to a reduction of estimated recoverable reserves as a result of the forecasted natural-gas price environment. This Gulf of Mexico property is located on a lease that is close to expiration and the Company does not plan to pursue the exploitation of this property under the forecasted natural-gas price environment. The remaining increases of $41 million and $106 million for the three and six months ended June 30, 2012, respectively, were primarily due to higher dry hole expense of $73 million and $146 million, respectively, primarily in Sierra Leone, Côte d’Ivoire, and the Gulf of Mexico, which were partially offset by lower geological and geophysical expense of $38 million and $51 million, respectively, primarily due to fewer seismic purchases in the Gulf of Mexico, Mozambique, Kenya, and Liberia.

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
millions except percentages    2012      Inc/(Dec)
vs. 2011
     2011      2012      Inc/(Dec)
vs. 2011
     2011  

General and administrative

   $ 262        (7)%        $     282      $ 531        8%         $ 491  

Depreciation, depletion, and amortization

         1,027        4              985            1,957        (1)                 1,970  

Other taxes

     326        (21)             413        703        (7)             757  

Impairments

     112        10              102        162        56             104  

For the three months ended June 30, 2012, general and administrative (G&A) expense decreased by $20 million primarily due to consulting fees of $16 million incurred during the second quarter of 2011 related to the Maverick basin joint venture. For the six months ended June 30, 2012, G&A expense increased $40 million primarily due to legal-related expenses. The increase was partially offset by lower consulting fees of $16 million as discussed above and decreased insurance costs of $11 million due to lower premiums for directors and officers insurance in 2012.

For the three months ended June 30, 2012, depreciation, depletion, and amortization (DD&A) expense increased by $42 million due to higher sales volumes, the start of production at Caesar/Tonga in March 2012, and the accelerated depletion of a natural-gas field in the Gulf of Mexico, partially offset by lower per-barrel DD&A rates resulting from asset impairments recorded in the fourth quarter of 2011 and reserve additions at the Eagleford shale. For the six months ended June 30, 2012, DD&A expense decreased by $13 million due to lower per-barrel DD&A rates related to the 2011 asset impairments and reserve additions at the Eagleford shale, partially offset by higher sales volumes.

 

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Table of Contents

For the three and six months ended June 30, 2012, other taxes decreased by $87 million and $54 million, respectively, primarily related to lower Algeria exceptional profits taxes of $60 million and $45 million, respectively, due to a lower Algeria effective tax rate resulting from the resolution of the exceptional profits tax dispute with Sonatrach. Other taxes were also lower for the three and six months ended June 30, 2012, due to decreased U.S. production and severance taxes of $24 million and $10 million, respectively, primarily due to lower natural-gas prices.

Impairment expense for the three and six months ended June 30, 2012, was $112 million and $162 million, respectively. In the second quarter of 2012, due to lower natural-gas prices, the Company recognized impairments of $79 million related to certain onshore domestic oil and gas exploration and production reporting segment properties and $4 million related to midstream reporting segment properties. The Company also recognized impairments of $50 million and $17 million during the first and second quarter of 2012, respectively, related to downward reserves revisions for a Gulf of Mexico property that is near the end of its economic life. Also in the second quarter of 2012, the Company recognized impairment expense of $11 million related to the Company’s investment in Venezuelan assets due to declines in estimated recoverable reserves and lower crude-oil prices. Impairment expense for the three and six months ended June 30, 2011, was $102 million and $104 million, respectively, including $100 million recognized in the second quarter of 2011 related to onshore domestic oil and gas exploration and production reporting segment properties due to a change in projected cash flows resulting from the Company’s intent to divest of the properties.

 

     Three Months Ended
June  30,
     Six Months Ended
June 30,
 
millions except percentages    2012     Inc/(Dec)
vs. 2011
     2011      2012     Inc/(Dec)
vs. 2011
     2011  

Algeria exceptional profits tax settlement

   $           —        NM            $           —         $  (1,804     NM            $           —   

Deepwater Horizon settlement and related costs

     3       (67)%          9        11       (69)%          35  

In March 2012, Anadarko reached an agreement with Sonatrach to resolve the exceptional profits tax dispute. The agreement was approved by the Algerian government and provides for delivery to the Company of crude oil valued at approximately $1.7 billion and the elimination of $62 million of the Company’s previously recorded and unpaid transportation charges. The crude oil is to be delivered to the Company over a 12-month period that began in June 2012. The Company recognized a $1.8 billion credit in the Costs and Expenses section of the Consolidated Statement of Income in the first quarter of 2012 to reflect the effect of this agreement on previously recorded expenses. The Company expects to receive approximately $1.0 billion from the sale of the crude oil during 2012 and the balance in the first half of 2013. Additionally, the parties agreed to an amendment to the existing Production Sharing Agreement (PSA) that provides the Company increased sales volumes and a lower effective exceptional profits tax rate in future periods. The amendment also confirms the duration for each exploitation license granted under the PSA will be 25 years from the date the license was awarded.

For the three and six months ended June 30, 2012, Deepwater Horizon settlement and related costs decreased by $6 million and $24 million, respectively, due to lower legal expenses and related costs associated with the Deepwater Horizon events. See Note 10—Contingencies—Deepwater Horizon Events in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for additional information.

 

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Table of Contents

Other (Income) Expense

 

            Three Months Ended         
        June 30,        
              Six Months Ended           
          June 30,          
 
millions except percentages   2012     Inc/(Dec)
vs. 2011
    2011     2012     Inc/(Dec)
vs. 2011
    2011  

Interest Expense

           

Current debt, long-term debt, and other

  $     236       (6)%        $     250     $     486       (2)%        $     498  

Capitalized interest

    (46     (35)             (34     (110     (77)             (62
 

 

 

     

 

 

   

 

 

     

 

 

 

Total interest expense

  $ 190       (12)           $ 216     $ 376       (14)           $ 436  
 

 

 

     

 

 

   

 

 

     

 

 

 

For the three and six months ended June 30, 2012, interest expense decreased by $26 million and $60 million, respectively, primarily due to an increase in capitalized interest of $13 million and $49 million, respectively, related to higher construction-in-progress balances for long-term capital projects. Additionally, interest expense for the three and six months ended June 30, 2012, decreased $9 million and $17&n