10-K 1 d10k.htm FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2008 Form 10-K for the Fiscal Year Ended December 31, 2008
Table of Contents
Index to Financial Statements

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2008

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

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

  

Name of each exchange on which registered

Common Stock, par value $0.10 per share    New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  x    No  ¨.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x.

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨.

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 Act).    Yes  ¨    No  x.

The aggregate market value of the Company’s common stock held by non-affiliates of the registrant on June 30, 2008 was $34.9 billion based on the closing price as reported on the New York Stock Exchange.

The number of shares outstanding of the Company’s common stock as of January 30, 2009 is shown below:

 

Title of Class    Number of Shares Outstanding
Common Stock, par value $0.10 per share    459,881,004

 

Part of

Form 10-K

   Documents Incorporated By Reference

Part III

   Portions of the Proxy Statement for the Annual Meeting of Stockholders of Anadarko Petroleum Corporation to be held May 19, 2009 (to be filed with the Securities and Exchange Commission prior to April 9, 2009).


Table of Contents
Index to Financial Statements

TABLE OF CONTENTS

 

          Page

PART I

     

Items 1 and 2.

   Business and Properties    2
  

General

   2
  

Oil and Gas Properties and Activities

   3
  

Proved Reserves

   3
  

Sales Volumes and Prices

   4
  

Properties and Activities—United States

   6
  

Properties and Activities—Algeria

   12
  

Properties and Activities—Other International

   13
  

Drilling Programs

   14
  

Drilling Statistics

   14
  

Productive Wells

   15
  

Properties and Leases

   15
  

Midstream Properties and Activities

   15
  

Marketing Activities

   16
  

Segment and Geographic Information

   17
  

Employees

   17
  

Regulatory Matters, Environmental and Additional Factors Affecting Business

   17
  

Title to Properties

   17
  

Capital Spending

   17
  

Ratios of Earnings to Fixed Charges and Earnings to Combined Fixed Charges and Preferred Stock Dividends

   17

Item 1A.

   Risk Factors    18

Item 1B.

   Unresolved Staff Comments    26

Item 3.

   Legal Proceedings    26

Item 4.

   Submission of Matters to a Vote of Security Holders    27
  

Executive Officers of the Registrant

   27

PART II

     

Item 5.

  

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

   29

Item 6.

   Selected Financial Data    31

Item 7.

  

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

   32

Item 7A.

   Quantitative and Qualitative Disclosures About Market Risk    66

Item 8.

   Financial Statements and Supplementary Data    68

Item 9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

   139

Item 9A.

   Controls and Procedures    139

Item 9B.

   Other Information    139

PART III

     

Item 10.

   Directors, Executive Officers and Corporate Governance    139

Item 11.

   Executive Compensation    140

Item 12.

  

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

   140

Item 13.

   Certain Relationships and Related Transactions, and Director Independence    140

Item 14.

   Principal Accounting Fees and Services    140

PART IV

     

Item 15.

   Exhibits, Financial Statement Schedules    141

 

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Index to Financial Statements

PART I

Items 1 and 2.    Business and Properties

General

Anadarko Petroleum Corporation is among the largest independent oil and gas exploration and production companies in the world, with 2.28 billion barrels of oil equivalent (BOE) of proved reserves as of December 31, 2008. Anadarko’s primary business segments are vertically integrated within the oil and gas industry. These segments are managed separately because of the nature of their products and services, as well as unique technology, distribution and marketing requirements. The Company’s three operating segments are:

Oil and gas exploration and production This segment explores for and produces natural gas, crude oil, condensate and natural gas liquids (NGLs). The Company’s major areas of operation are located onshore in the United States, the deepwater of the Gulf of Mexico and Algeria. Anadarko also has production in China and is executing strategic exploration programs in several other countries, including Ghana and Brazil.

Midstream This segment engages in gathering, processing, treating and transporting Anadarko and third-party oil and gas production. The Company owns and operates natural gas gathering, treating and processing systems in the United States.

Marketing This segment sells most of Anadarko’s production, as well as commodities purchased from third parties. The Company actively markets natural gas, oil and NGLs in the United States, and actively markets oil from Algeria and China.

The Company also has hard minerals properties that contribute to operating income through non-operated joint ventures and royalty arrangements in several coal, trona (natural soda ash) and industrial mineral mines located on lands within and adjacent to its Land Grant holdings. The Land Grant is an 8 million acre strip running through portions of Colorado, Wyoming and Utah and is where the Company owns most of its fee mineral rights. Anadarko is committed to minimizing its impact on the environment from exploration and production activities of its worldwide operations through programs such as carbon dioxide (CO2) sequestration and the reduction of surface area used for production facilities.

On August 10, 2006, Anadarko completed the acquisition of Kerr-McGee Corporation (Kerr-McGee) in an all-cash transaction totaling $16.5 billion, plus the assumption of approximately $2.6 billion in debt. On August 23, 2006, Anadarko completed the acquisition of Western Gas Resources, Inc. (Western) in an all-cash transaction totaling $4.8 billion plus the assumption of $625 million in debt. As part of an asset realignment associated with the acquisitions, the Company sold its wholly-owned Canadian oil and gas subsidiary, Anadarko Canada Corporation, in November 2006 for approximately $4 billion. Anadarko also divested, in 2007 and 2006, certain properties onshore in the United States, in the Gulf of Mexico and Qatar for total proceeds of approximately $13 billion before income taxes. The proceeds from these transactions were used to reduce debt.

In 2008, Anadarko divested certain properties in Brazil, onshore in the United States and the Gulf of Mexico for total proceeds of $2.5 billion before income taxes. Proceeds from these divestitures were used primarily to reduce debt by $2.4 billion in 2008. For additional information, see Acquisitions and Divestitures and Outlook under Item 7 of this Form 10-K.

During 2007, Anadarko changed its method of accounting for its oil and gas exploration and development activities from full cost to the successful efforts method. All financial information presented for prior periods has been recast to reflect retrospective application of the successful efforts method.

Unless the context otherwise requires, the terms “Anadarko” or “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries. The Company’s corporate headquarters is located at 1201 Lake Robbins Drive, The Woodlands, Texas 77380, where the telephone number is (832) 636-1000. Additionally, unless noted otherwise, the following information relates to Anadarko’s continuing operations and excludes the discontinued Canadian operations. For additional information, see Note 1—Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Available Information The Company files Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, registration statements and other items with the Securities and Exchange

 

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Commission (SEC). Anadarko provides access free of charge to all of these SEC filings, as soon as reasonably practicable after filing or furnishing, on its internet site located at www.anadarko.com. The Company will also make available to any stockholder, without charge, copies of its Annual Report on Form 10-K as filed with the SEC. For copies of this, or any other filing, please contact: Anadarko Petroleum Corporation, Investor Relations Department, P.O. Box 1330, Houston, Texas 77251-1330 or call (832) 636-1216.

In addition, the public may read and copy any materials Anadarko files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers, like Anadarko, that file electronically with the SEC.

Oil and Gas Properties and Activities

Proved Reserves

As of December 31, 2008, Anadarko had proved reserves of 8.1 trillion cubic feet (Tcf) of natural gas and 0.9 billion barrels of crude oil, condensate and NGLs. Combined, these proved reserves are equivalent to 2.28 billion barrels of oil or 13.7 Tcf of natural gas. Excluding the effect of divestitures, the Company’s proved reserves increased during 2008 by approximately 188 million barrels of oil equivalent (MMBOE). During 2008, sales of proved reserves in place totaled 137 MMBOE. Reserve additions were primarily driven by successful drilling in the Rockies and developments and appraisals in the deepwater Gulf of Mexico and positive revisions associated with successful infill drilling onshore in the United States and the Peregrino heavy-oil field, offshore Brazil, which was sold in 2008. These positive revisions were partially offset by a decrease in prices for oil and NGLs. As of December 31, 2008, Anadarko had proved developed reserves of 6.1 Tcf of natural gas and 580 million barrels (MMBbls) of crude oil, condensate and NGLs. Proved developed reserves comprise 70% of total proved reserves.

Evaluation and Review Anadarko’s estimates of proved reserves and associated future net cash flows as of December 31, 2008 were made solely by the Company’s engineers and are the responsibility of management. The procedures and methods used in preparing the Company’s estimates of proved reserves and future net cash flows, as of December 31, 2008, were reviewed by an independent engineering firm, Miller and Lents, Ltd. (M&L). The purpose of the review was to determine that procedures and methods used by Anadarko to estimate its proved reserves were based on generally accepted engineering and evaluation principles and are in accordance with definitions contained in the rules of the SEC. In each review, Anadarko’s technical staff presented M&L with an overview of the data, methods and assumptions used in its reserve estimates. The data presented included pertinent seismic information, geologic maps, well logs, production tests, material balance calculations, reservoir simulation models, well performance data, operating procedures and relevant economic criteria. Subsequent to the reviews, M&L was provided with additional data and information that was requested in certain instances to satisfy M&L that the procedures and methods used were in accordance with standard industry practice. Management’s intent in retaining M&L to review its procedures and methods is to provide for objective third-party input on these procedures and methods and to gather industry information applicable to its reserve estimation and reporting process.

The Company’s estimates of proved reserves, proved developed reserves and proved undeveloped reserves (PUDs) at December 31, 2008, 2007 and 2006 and changes in proved reserves during the last three years are contained in the Supplemental Information on Oil and Gas Exploration and Production Activities—Unaudited (Supplemental Information) in the Consolidated Financial Statements under Item 8 of this Form 10-K. Additional information with respect to the Company’s methods and procedures employed in the reserve estimation process, are also found in the Supplemental Information. The Company files annual estimates of certain proved oil and gas reserves with the U.S. Department of Energy, which are within 5% of the amounts included in the above estimates.

In December 2008, the SEC released the final rule for “Modernization of Oil and Gas Reporting” (Modernization). The Modernization disclosure requirements will permit reporting of oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices and the use of new technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable

 

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conclusions about reserves volumes. Companies will also be allowed to disclose probable and possible reserves in SEC filed documents. In addition, companies will be required to report the independence and qualifications of its reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit. The Modernization disclosure requirements become effective for Anadarko’s Annual Report on Form 10-K for the year ended December 31, 2009. The SEC is coordinating with the Financial Accounting Standards Board to obtain the revisions necessary to provide consistency with the Modernization. In the event that consistency is not achieved in time for companies to comply with the Modernization, the SEC will consider delaying the compliance date.

Also contained in the Supplemental Information in the Consolidated Financial Statements are the Company’s estimates of future net cash flows and discounted future net cash flows from proved reserves. See Operating Results and Critical Accounting Policies and Estimates under Item 7 of this Form 10-K for additional information on the Company’s proved reserves.

Sales Volumes and Prices

The following table shows the Company’s annual sales volumes from continuing operations. Sales volumes for 2007 include approximately 15 MMBOE associated with properties that were divested during 2007. Volumes for natural gas are in billions of cubic feet (Bcf) at a pressure base of 14.73 pounds per square inch. For the computation of BOE, six thousand cubic feet (Mcf) of gas is the energy equivalent of one barrel of oil, condensate or NGLs.

Sales Volumes

 

     2008    2007    2006

United States

        

Natural gas (Bcf)

   750    698    558

Oil and condensate (MMBbls)

   40    48    39

Natural gas liquids (MMBbls)

   14    16    15

Total (MMBOE)

   179    180    147

Algeria

        

Oil and condensate (MMBbls)

   21    24    23

Total (MMBOE)

   21    24    23

Other International

        

Oil and condensate (MMBbls)

   6    7    8

Total (MMBOE)

   6    7    8

Total

        

Natural gas (Bcf)

   750    698    558

Oil and condensate (MMBbls)

   67    79    70

Natural gas liquids (MMBbls)

   14    16    15

Total (MMBOE)

   206    211    178

The following table shows the Company’s annual average sales prices and average production costs from continuing operations. The impact on average sales prices from derivative instruments, which the Company utilizes to manage price risk related to the Company’s sales volumes, is shown separately in the table. Natural gas sales and oil and condensate sales include net unrealized gains (losses) related to these derivatives of $372 million and $520 million for 2008, $(395) million and $(653) million for 2007 and $579 million and $258 million for 2006, respectively. Production costs are costs incurred to operate and maintain the Company’s wells and related equipment and include cost of labor, well service and repair, location maintenance, power and fuel, transportation, cost of product, property taxes, production and severance taxes and production related general and administrative costs. Additional information on volumes, prices, production costs and markets is contained in Financial Results and Marketing Strategies under Item 7 of this Form 10-K. Additional detail of production costs is contained in the Supplemental Information under Item 8 of this Form 10-K. Information on major customers is contained in Note 18—Major Customers of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

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Index to Financial Statements

Sales Prices and Production Costs

 

     2008     2007     2006  

United States

      

Sales price

      

Natural gas price per Mcf, excluding derivatives

   $ 7.65     $ 5.74     $ 6.14  

Realized gains (losses) on derivatives

     0.19       0.73       0.33  
                        
     7.84       6.47       6.47  

Unrealized gains (losses) on derivatives

     0.50       (0.57 )     1.03  
                        

Total

   $ 8.34     $ 5.90     $ 7.50  

Oil and condensate price per barrel, excluding derivatives

   $ 96.20     $ 66.64     $ 59.41  

Realized gains (losses) on derivatives

     (8.15 )     1.35       2.64  
                        
     88.05       67.99       62.05  

Unrealized gains (losses) on derivatives

     8.18       (10.75 )     6.54  
                        

Total

   $ 96.23     $ 57.24     $ 68.59  

Natural gas liquids price per barrel, excluding derivatives

   $ 56.11     $ 45.87     $ 39.71  

Realized gains (losses) on derivatives

     —         0.03       (0.13 )
                        
     56.11       45.90       39.58  

Unrealized gains (losses) on derivatives

     —         —         —    
                        

Total

   $ 56.11     $ 45.90     $ 39.58  

Total

   $ 60.82     $ 42.13     $ 50.77  

Production cost per BOE

   $ 13.81     $ 11.14     $ 10.76  

Algeria

      

Sales price

      

Oil and condensate price per barrel, excluding derivatives

   $ 98.99     $ 75.50     $ 65.55  

Realized gains (losses) on derivatives

     (5.86 )     —         —    
                        
     93.13       75.50       65.55  

Unrealized gains (losses) on derivatives

     9.14       (5.91 )     —    
                        

Total

   $ 102.27     $ 69.59     $ 65.55  

Production cost per BOE

   $ 35.20     $ 34.13     $ 7.48  

Other International

      

Sales price

      

Oil and condensate price per barrel

   $ 85.51     $ 59.91     $ 48.58  

Production cost per BOE

   $ 26.88     $ 14.78     $ 10.43  

Total

      

Sales price

      

Natural gas price per Mcf, excluding derivatives

   $ 7.65     $ 5.74     $ 6.14  

Realized gains (losses) on derivatives

     0.19       0.73       0.33  
                        
     7.84       6.47       6.47  

Unrealized gains (losses) on derivatives

     0.50       (0.57 )     1.03  
                        

Total

   $ 8.34     $ 5.90     $ 7.50  

Oil and condensate price per barrel, excluding derivatives

   $ 96.15     $ 68.68     $ 60.28  

Realized gains (losses) on derivatives

     (6.72 )     0.82       1.48  
                        
     89.43       69.50       61.76  

Unrealized gains (losses) on derivatives

     7.78       (8.31 )     3.67  
                        

Total

   $ 97.21     $ 61.19     $ 65.43  

Natural gas liquids price per barrel, excluding derivatives

   $ 56.11     $ 45.87     $ 39.71  

Realized gains (losses) on derivatives

     —         0.03       (0.13 )
                        
     56.11       45.90       39.58  

Unrealized gains (losses) on derivatives

     —         —         —    
                        

Total

   $ 56.11     $ 45.90     $ 39.58  

Total

   $ 65.75     $ 45.81     $ 52.63  

Production cost per BOE

   $ 16.35     $ 13.84     $ 10.31  

 

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Properties and Activities—United States

Overview Anadarko’s active areas in the United States include the Lower 48 states, Alaska and the deepwater Gulf of Mexico. Reserves in the United States comprised 90% of Anadarko’s total proved reserves at year-end 2008. During 2008, the Company’s drilling efforts in the United States resulted in 2,645 natural gas wells, 149 oil wells and 19 dry holes. The accompanying maps illustrate the locations of Anadarko’s domestic onshore and offshore oil and gas producing operations.

The following table presents selected 2008 United States operating data by area.

 

     Net Sales Volumes    Net
Proved
Reserves
at Year End
(MMBOE)
   Producing
Wells(1)
   Drilling Statistics
   Natural
Gas
(MMcf/d)
   Oil and
NGLs
(MBbls/d)
   Total
(MBOE/d)
         Wells
Drilled(2)
   Success
Rate
    Nature of
Interest(3)

Rockies:

                    

Tight Gas

                    

-Greater Natural Buttes

   250    4    46    287    2,337    353    100.0 %   W

-Wattenberg

   171    19    48    258    4,520    385    100.0 %   W/R

-Wamsutter and Moxa

   146    11    35    157    2,901    383    100.0 %   W/R

-Pinedale

   70    1    13    98    897    463    100.0 %   W

Enhanced Oil Recovery

   3    12    12    160    1,378    34    100.0 %   W

Coalbed Methane

   377    —      63    165    9,799    839    100.0 %   W

Other

   7    —      1    40    196    —      n/a     W/R
                                         
   1,024    47    218    1,165    22,028    2,457    100.0 %  
                                         

Southern Region:

                    

Bossier

   150    —      25    148    879    22    100.0 %   W

Carthage

   85    5    19    121    1,616    121    97.5 %   W/R

Haley

   91    —      16    40    159    26    92.3 %   W

Ozona

   38    1    7    57    2,332    52    100.0 %   W

Austin Chalk

   43    12    19    31    687    25    84.0 %   W/R

Other

   146    8    32    139    2,365    92    94.5 %   W/R
                                         
   553    26    118    536    8,038    338    95.8 %  
                                         

Total Onshore—Lower 48 States

      1,577    73    336    1,701    30,066    2,795    99.5 %  

Alaska

   —      19    19    51    257    11    82.0 %   W

Gulf of Mexico

   472    55    134    291    212    7    57.0 %   W/R
                                         

Total United States

   2,049    147    489    2,043    30,535    2,813    99.3 %  
                                         

 

(1)

Gross number of wells in which Anadarko has an interest.

(2)

Includes 2,788 gross development wells with a 99.6% success rate and 25 gross exploration wells with a 64.0% success rate.

(3)

W = Working, R = Royalty

 

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LOGO

 

7

 

Anadarko

Petroleum Corporation

ONSHORE PRODUCING PROPERTIES

ROCKIES

MONTANA

Powder River Basin

NORTH DAKOTA

IDAHO

WYOMING

Pinedale

Moxa

EOR

CBM

Wamsutter

CBM

SOUTH DAKOTA

UTAH

Greater Natural Buttes

CBM

COLORADO

DENVER

Wattenberg

SOUTHERN REGION

NEBRASKA

KANSAS

Hugoton

ARIZONA

NEW MEXICO

OKLAHOMA

ARKANSAS

TEXAS

Carthage

Haley

Ozona

South Texas

Bossier

Austin Chalk

THE WOODLANDS

MISSISSIPPI

LOUISIANA

GAS FIELD (CONTAINS OPERATED WELLS)

OIL FIELD (CONTAINS OPERATED WELLS)

LAND GRANT

CORPORATE OFFICES

ALASKA

Colville River Unit

Note: Alaska not to scale

ACREAGE LOWER 48 ALASKA

UNDEVELOPED LEASEHOLD (Net) 2,969,868 1,231,683

DEVELOPED LEASEHOLD (Net) 3,151,048 8,448

FEE MINERAL (Net) 8,322,277 7,978

JANUARY 2009

N SCALE 0 100MI. 200MI.


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Index to Financial Statements

Onshore—Lower 48 States At the end of 2008, about 75% of the Company’s proved reserves were located onshore in the Lower 48 states. The Company has allocated approximately 45% of the 2009 capital budget to the Lower 48 states. Of this amount, approximately 65% is allocated to the Rockies and approximately 35% is allocated to the Southern Region.

Rockies Anadarko’s properties in the Rockies are located in Colorado, Utah and Wyoming with a primary focus on natural gas plays. Anadarko is a large independent operator of tight gas and CBM natural gas assets as well as an operator of enhanced oil recovery (EOR) projects within the region.

Tight gas assets include the Greater Natural Buttes, Wattenberg, Wamsutter and Moxa fields. Pinedale is also a non-operated asset within Anadarko’s tight gas portfolio in the Rockies.

In the Greater Natural Buttes field, located in the Uinta basin of northeast Utah, the Company continues to be primarily focused on development of the Wasatch and Mesa Verde formations through infill drilling operations and drilling additional wells adjacent to existing producing wells. Anadarko operates approximately 1,500 wells in the Greater Natural Buttes field area and has an interest in approximately 900 non-operated wells. In 2009, Anadarko plans to maintain an active drilling program in this area.

The Wattenberg natural gas and condensate field is located in the Denver-Julesburg basin in northeast Colorado on a portion of the Land Grant. Development activities in 2008 included infill drilling, re-completions, and re-fracture stimulations of pre-existing wells. The Land Grant affords the Company royalty revenues on many of the operated and non-operated wells in this and other fields. Anadarko operates approximately 4,200 wells and has an interest in approximately 300 non-operated wells in the Wattenberg field. In 2009, the Company expects to have several active drilling and workover rigs in the area.

Anadarko was active in the Wamsutter and Moxa tight gas fields in 2008, which are located in the Greater Green River basin (GGRB) area of southern Wyoming. Both fields are also on the Wyoming portion of the Land Grant which provides Anadarko with royalty revenues. The Company further benefits from the success of numerous third-party operators on the Wyoming portion of the Land Grant acreage and actively pursues farm-out projects to capture incremental royalty revenues in the GGRB from exploration and development activity. Anadarko operates approximately 700 wells and has an interest in approximately 2,200 non-operated wells in the Wamsutter and Moxa fields.

The Company’s non-operated Pinedale asset is located in the GGRB in southwest Wyoming. The gas produced at Pinedale is transported through Company-owned gathering systems that deliver gas to an Anadarko processing facility located on the Land Grant. Anadarko has an interest in approximately 900 producing wells in the Pinedale field.

During 2008, the Company continued to pursue the phased development of the Rockies EOR assets at the Salt Creek, Monell and Sussex areas in Wyoming. Each area has demonstrated year-over-year increases in production due to CO2 injection operations. The Company expects that phased development will continue in 2009 for these assets.

The Company’s CBM operations are primarily located in the Powder River basin in northeast Wyoming, but include activity on the Wyoming portion of the Land Grant at the Atlantic Rim in southern Wyoming, and in the Helper and Clawson fields in Utah. Anadarko operates approximately 4,600 shallow low-cost CBM wells and has an interest in approximately 5,200 outside-operated CBM wells in the Rockies.

Southern Region Anadarko’s properties in the Southern Region are located primarily in Texas with a focus on natural gas plays. During 2008, production and development activities at the Company’s properties in the east Texas area were concentrated in the Bossier and Carthage areas with the Company drilling 22 wells in the Bossier area and 121 wells in the Carthage area. In 2009, Anadarko plans to reduce activity in the Bossier and Carthage areas. Anadarko’s east Texas Austin Chalk activity continues to focus on horizontal drilling in Tyler and Jasper counties. Anadarko drilled 25 wells in 2008 in this area. In 2009, the Company plans to remain active with the continued extension of field boundaries and drilling infill development wells to optimize well spacing in this area.

 

8


Table of Contents
Index to Financial Statements

Operations in west Texas are concentrated on increasing production and reserves in the tight gas play of the Haley field. During 2007, the Company entered into a joint venture on a portion of the Haley field to reduce risk and increase acreage in the basin. The joint venture drilled 26 wells in 2008. Anadarko also drilled 52 wells in the Ozona field, which is located in the west Texas area, in 2008.

Other areas in the Southern Region include properties in South Texas and in the Hugoton field. In South Texas, the Company had an active drilling program in Starr and Hidalgo counties during 2008. The Hugoton field in southern Kansas continues to be a long-life, slow-decline asset for Anadarko with over 1,200 producing gas wells.

Exploration Anadarko’s exploration program in the Southern Region is concentrated in Texas, Pennsylvania and Mississippi. Anadarko was successful in 13 of 18 exploratory wells in six different plays in these areas during 2008, with focus on shale gas, tight sands and fractured carbonate plays. Anadarko has completed a number of these wells in the Maverick basin and the Haynesville shale play in Texas, and the Marcellus shale play in Pennsylvania. The Company plans to explore and delineate these areas in 2009.

Alaska Anadarko’s activity in Alaska is concentrated primarily on the North Slope. Approximately 2% of the Company’s proved reserves at year-end 2008 were in Alaska. During 2008, development activity at the Colville River Unit (22% WI) was focused on new development at the Qannik field and continued drilling at the Alpine, Fiord and Nanuq fields. First production from Qannik was achieved in July 2008. During 2009, the Company anticipates that development planning will lead to the sanction of the Alpine West field. In 2009, the Company expects to continue to participate in exploration drilling in Alaska.

Gulf of Mexico At year-end 2008, about 13% of the Company’s proved reserves were located offshore in the deepwater Gulf of Mexico where Anadarko owns an average 64% working interest in 596 blocks and has access to an additional 22 blocks through participation agreements. The Company holds interests in 26 producing fields and is in the process of developing two additional fields in the area. Anadarko has allocated approximately 20% of the capital budget to the deepwater Gulf of Mexico for 2009.

Independence Hub The Independence Hub, located in approximately 8,000 feet of water, began production in July 2007. Anadarko operates the facility, which is owned by third parties. The facility, capable of processing nearly 1 Bcf of gas per day, serves several ultra-deepwater natural gas fields, including eight field discoveries operated by Anadarko. Anadarko’s working interests in these fields range from 20% to 100%. Production is from 16 wells, of which Anadarko has an interest in 15. During 2008, Anadarko successfully drilled one development well (100% WI) in the area. In 2009, the Company plans to drill two to four additional development wells in the area.

Marco Polo/K2 complex Anadarko operates, and a third party owns, the platform and production facilities for the Marco Polo deepwater development project. Six K2 subsea wells (42% WI) are tied-back to the Marco Polo platform, where four Marco Polo field wells (100% WI) are also producing. In 2008, the Company drilled a down-dip K2 field delineation well and three sidetrack wells. During 2009, the Company plans to drill one K2 well to test the southern portion of the field, and to complete two K2 wells later in the year. Two wells were completed in the Marco Polo field in 2008. The fields have had limited production since September 2008 because of damage caused by Hurricane Ike to the third-party-owned gas export pipelines that connect the platform to the shelf infrastructure. Production is expected to resume in the first half of 2009.

Constitution/Ticonderoga fields The Constitution field (100% WI) began production in 2006 utilizing a truss spar located in approximately 5,000 feet of water. The Ticonderoga field (50% WI) also began production in 2006 as a subsea tieback to the Constitution spar. During 2008, additional drilling and completion at Ticonderoga increased the field to three producing wells. Both fields have been shut-in since September 2008 because of damage caused by Hurricane Ike to the third-party-owned gas export pipelines that connect the spar to the shelf infrastructure. Production is expected to resume in the first half of 2009. The Company is planning to use the Constitution spar as a hub for the accelerated development of the Caesar/Tonga complex.

 

9


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Index to Financial Statements

Caesar/Tonga complex (33.75% WI) The Company approved development of the Caesar/Tonga complex in December 2008 as a four-well subsea tieback to the Constitution spar, and production is expected to start in the first half of 2011. One development well was successfully drilled in 2008 and additional development drilling is expected in 2009.

Nansen field (50% WI) The Nansen field began production in 2002, and was developed with the world’s first truss spar in 3,700 feet of water. During 2008, Anadarko completed and tied-back four discoveries in the Northwest Nansen field area to the Nansen spar. Production from these four wells commenced during early 2008. Also during 2008, Anadarko drilled and completed two subsea wells. Production from both wells is expected to commence in mid-2009. In 2009, the Company plans to sidetrack and recomplete one subsea well and expects to initiate a three-well sidetrack or recompletion program with a platform rig.

Boomvang field (East Breaks Blocks 642, 643, and 688 (30% WI), Block 598 (100% WI), and Block 599 (33% WI)) The Boomvang field began production in 2002 and was developed with a truss spar in 3,450 feet of water. During 2008, the Company drilled a sidetrack well. Production from this well commenced in early 2008. In 2009, the Company plans to drill one development well in the proximity of the Drysdale discovery. Production from this well is expected to commence during mid-2009.

Gunnison field (50% WI) The Gunnison field has been producing since 2003 and incorporates a truss spar in 3,100 feet of water. During 2006, the Dawson Deep discovery began production as a subsea tieback to the Gunnison spar. In 2008, the Company drilled one well and recompleted two other wells. Gunnison was shut-in after Hurricane Ike because of damage to an onshore third-party-owned processing facility. Partial production was quickly restored and full production resumed in January 2009. The Company plans to recomplete one well in 2009 and is currently planning a platform-based rig program for late 2009 or 2010.

Red Hawk field (50% WI) The Red Hawk field, located in approximately 5,300 feet of water, began production in 2004 utilizing the world’s first cell spar designed for developing smaller reservoirs in deepwater basins. During 2007, the Company completed installation of compression equipment at the spar, which extended the life of the field. During 2008, the Company recompleted one well. However, at the end of 2008, both wells at Red Hawk had depleted reserves and were shut-in. The Company plans to continue evaluating potential opportunities in and around the Red Hawk field in 2009.

Power Play field (45% WI) The Power Play field is an Anadarko operated single-well subsea tieback to the Baldpate platform. The well was completed and tied-back during the second quarter of 2008.

Other The Neptune field (50% WI) is an Anadarko-operated property utilizing the world’s first floating production spar. During 2008, the Company drilled an appraisal well in the proximity of the Mission Deep discovery (50% WI). Anadarko is currently evaluating its options for the Mission Deep discovery. In 2008, a fourth well was drilled in the Blind Faith field (non-operated, 25% WI), where a deep-draft semi-submersible platform was installed and first production was achieved. Other Anadarko non-operated properties include Baldpate (50% WI), Conger (25% WI), Pompano (25% WI) and Tahiti (3% plus over-riding royalty interest).

Exploration Anadarko’s exploration program in the Gulf of Mexico is currently focused on the extensive middle-to-lower Miocene play within the central Gulf of Mexico and the developing lower Tertiary play in the western Gulf of Mexico. During 2008, Anadarko participated in two wells which were still drilling at the end of the year and both resulted in discoveries (Heidelberg and Shenandoah) in early 2009. Anadarko also drilled two unsuccessful wells in the Gulf of Mexico in 2008. The Company expects to participate in approximately three to four exploration wells and several delineation wells in the area in 2009.

 

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Index to Financial Statements

LOGO

 

11

 

Anadarko

Petroleum Corporation

GULF OF MEXICO PRODUCING PROPERTIES

TEXAS

Houston

LOUISIANA

Lake Charles

New Orleans

MISSISSIPPI

Biloxi

ALABAMA

Mobile

FLORIDA

Pensacola

Nansen

Boomvang

Gunnison

Power Play

Conger

Baldpate

Red Hawk

Constitution Ticonderoga

Tahiti

K2

Marco Polo

Blind Faith

Independence Hub

Pompano

Neptune

N 0 60 MILES

OPERATED FIELDS/FACILITIES

NON-OPERATED FIELDS/FACILITIES

ACREAGE

UNDEVELOPED (Net) 1,976,145

DEVELOPED (Net) 170,897

PRODUCING BLOCKS 65

EXPLORATORY BLOCKS 531

JANUARY 2009


Table of Contents
Index to Financial Statements

Properties and Activities—Algeria

Overview Anadarko is engaged in exploration, development and production activities in Algeria’s Sahara Desert. At the end of 2008, about 9% of the Company’s proved reserves were located in Algeria where a total of nine fields discovered by the Company were on production. In 2008, net sales volumes from the Company’s properties in Algeria represented 10% of the Company’s total sales volumes. During 2008, Anadarko participated in 11 development wells with an 82% success rate. During 2009, the Company expects to drill about 10 development wells, exclusive of water and gas injection wells, in Algeria.

Production and Development On Block 404, production from the HBNS field and its associated satellite fields averaged 139 MBbls/d of oil (gross) in 2008. Production from the HBN field, which extends from Block 404 into Block 403, averaged 64 MBbls/d of oil (gross) in 2008. Anadarko is also actively involved in the unitized Ourhoud field, which is located in portions of Block 404, Block 406a and Block 405. Production from this field averaged 230 MBbls/d of oil (gross) in 2008. Anadarko has an interest in several fields further south on Block 208 where development is expected to occur during the first half of 2009 and initial production is expected to occur in late 2011.

Contracts and Partners Anadarko’s interest in the Production Sharing Agreement (PSA) for Blocks 404 and 208 is 50% before participation at the exploitation stage by Sonatrach, the national oil and gas company of Algeria. The Company has two partners, each with a 25% interest, also prior to participation by Sonatrach. Under the terms of the PSA, oil reserves that are discovered, developed and produced are shared by Sonatrach, Anadarko and its two partners. Sonatrach is responsible for 51% of the development and production costs. Anadarko and its partners have completed the exploration program on Blocks 404 and 208 and now participates only in development activity on these blocks. Anadarko and its joint-venture partners funded Sonatrach’s share of exploration costs and are entitled to recover these exploration costs from production during the development phase.

Anadarko’s operations in Algeria have been governed by the PSA since October 1989. In March 2006, Anadarko received from Sonatrach a letter purporting to give notice under the PSA that enactment of a law in 2005 (2005 Law) relating to hydrocarbons triggered Sonatrach’s right under the PSA to renegotiate the PSA in order to re-establish the equilibrium of Anadarko’s and Sonatrach’s interests. Anadarko and Sonatrach reached an impasse over whether Sonatrach had a right to renegotiate the PSA based on the 2005 Law and entered into a formal non-binding conciliation process under the terms of the PSA in an attempt to resolve this dispute. The conciliation on the 2005 Law dispute was concluded in 2007 without a definitive resolution. There have been no further developments on the 2005 Law dispute. At this time, Anadarko is unable to reasonably estimate the economic impact under the PSA if Sonatrach were to succeed in modifying the PSA.

Anadarko and its partners still maintain an exploration license, under a separate production sharing agreement, for Block 403 c/e (67% interest).

Exceptional Profits Tax In July 2006, the Algerian parliament approved legislation establishing an exceptional profits tax on foreign companies’ Algerian oil production. In December 2006, implementing regulations regarding this legislation were issued. These regulations provide for an exceptional profits tax imposed on gross production at rates of taxation ranging from 5% to 50% based on average daily production volumes for each calendar month in which the price of Brent crude averages over $30 per barrel, retroactively effective to August 2006 production. Uncertainty existed at the time as to whether the exceptional profits tax would apply to the full value of production or only to the value of production in excess of $30 per barrel.

In January 2007, Sonatrach advised Anadarko that it would begin collecting the exceptional profits tax from Anadarko’s share of production commencing with March 2007 liftings, including for the prior months since the new tax went into effect. In April 2007, ALNAFT, the new agency in the Algerian Ministry of Energy and Mines responsible for overseeing the Algerian hydrocarbons industry, issued the Application Procedure further defining the procedure and conditions under which the exceptional profits tax is applied and the methodology for its calculation. The Application Procedure and other information supplied by Sonatrach revealed that the exceptional profits tax was being applied to the full value of production rather than to the amount in excess of $30 per barrel. This was evidenced by changes in the Company’s crude oil lifting schedule, which was conveyed to Anadarko by Sonatrach. As a result, Anadarko changed the measurement basis for the exceptional profits tax

 

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Index to Financial Statements

liability in the first quarter of 2007 to reflect the application of the tax to the full value of production. For additional information, see Note 15—Other Taxes of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

At December 31, 2008, Anadarko had 83 MMBbls of PUDs in Algeria, the economics of which are sensitive to the exceptional profits tax. Anadarko is continuing to evaluate the impact of the exceptional profits tax on the economic viability of its future projects in Algeria, as well as its legal remedies with regard to the exceptional profits tax.

In response to the Algerian government’s imposition of the exceptional profits tax, the Company has notified Sonatrach of its disagreement with the collection of the exceptional profits tax. The Company believes that the PSA provides fiscal stability through several of its provisions that require Sonatrach to pay all taxes and royalties. To facilitate discussions between the parties in an effort to resolve the dispute, on October 31, 2007, the Company initiated a conciliation proceeding on the exceptional profits tax as provided in the PSA. Any recommendation issued by a conciliation board (Conciliation Board) arising out of the conciliation proceeding is non-binding on the parties. The Conciliation Board issued its non-binding recommendation on November 26, 2008, which the Company received on December 1, 2008. On February 15, 2009, the Company initiated arbitration against Sonatrach with regard to the exceptional profits tax. In conformance with the terms of the PSA, a notice of arbitration was submitted to Sonatrach.

Properties and Activities—Other International

Overview The Company’s other international oil and gas production and/or development operations are located primarily in China. The Company has exploration acreage in China, Brazil, Ghana, Indonesia and other selected areas. About 1% of the Company’s proved reserves were located in these other international locations at year-end 2008. During 2008, net sales volumes from the Company’s other international properties accounted for 3% of the Company’s total sales volumes. Anadarko drilled 17 wells in 2008 in other international areas. In 2009, the Company expects to drill about 20 development and 15 exploration wells at various other international locations.

China Anadarko’s development and production project in China straddles Blocks 04/36 and 05/36 in Bohai Bay in approximately 75 feet of water. Anadarko drilled 11 wells in 2008 in this area. Development drilling and recompletion activity has been ongoing through 2008 and is anticipated to continue in 2009. Further investment is planned in 2009 on minor facility upgrades. At the end of 2008, net production from China was approximately 14 MBbls/d of oil. The Company has entered into a joint-venture agreement with the China National Offshore Oil Company to explore the South China Sea Contract Area 43/11. The joint venture has commenced exploration of Contract Area 43/11. During 2009, the Company plans to drill one deepwater exploration well in the South China Sea.

Brazil Anadarko holds exploration interests in several blocks located offshore in the Campos and Espírito Santo basins. Anadarko drilled two wells in 2008 in these areas, Wahoo and Serpa. The Serpa well was drilled in the BM-ES-24 block. Although encountering pay in the shallower pre-salt section, the well was determined to be non-commercial as a stand-alone development at this time. The Company announced the offshore pre-salt Wahoo discovery in the BM-C-30 block (30% WI) in 2008. Also in 2008, the Company divested its 50-percent interest in the Peregrino heavy-oil field in the Campos basin. In 2009, Anadarko expects to participate in three to four deepwater exploration and appraisal wells.

Ghana The Jubilee field was discovered offshore Ghana in 2007 and lies partly in the West Cape Three Points block (non-operated, 31% interest) and partly in the Deep Tano block (non-operated, 18% interest). In 2008, the Company drilled three additional wells on the blocks. In 2009, the Company and its partners expect to sanction the project and expect the operator to award contracts for a floating production, storage and offloading vessel and related equipment. The Company also plans to drill up to 11 development wells and to participate in three to five exploration wells in the two blocks. Production is expected to begin in late 2010.

Indonesia Anadarko has a participating interest in approximately 4.1 million exploration acres in Indonesia through a combination of several operated and non-operated Production Sharing Contracts. The Company did not participate in any wells in 2008, but plans to participate in two or three exploration wells in 2009.

 

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Index to Financial Statements

Other Anadarko also has active exploration projects in Mozambique, Liberia, Sierra Leone and several other countries in West Africa, as well as activities in other potential exploration and new venture areas overseas.

Drilling Programs

The Company’s 2008 drilling program focused on proven and emerging oil and natural gas basins in the United States (Lower 48 states, Alaska and Gulf of Mexico), Algeria and other countries where it holds acreage. Exploration activity consisted of 28 gross completed wells, including 21 wells in the Lower 48 states, 2 wells in Alaska, 2 wells offshore in the Gulf of Mexico, 2 wells in Algeria and 1 well in other international locations. Development activity consisted of 2,810 gross completed wells, which included 2,774 wells in the Lower 48 states, 9 wells in Alaska, 5 wells offshore in the Gulf of Mexico, 11 wells in Algeria and 11 wells in other international locations.

Drilling Statistics

The following table shows the number of oil and gas wells completed in each of the last three years:

 

     Net Exploratory    Net Development     
     Productive    Dry Holes    Total    Productive    Dry Holes    Total    Total

2008

                    

United States

   12.1    4.6    16.7    1,566.1    8.0    1,574.1    1,590.8

Algeria

   —      1.3    1.3    1.3    0.4    1.7    3.0

Other International

   —      0.3    0.3    3.6    —      3.6    3.9
                                  

Total

   12.1    6.2    18.3    1,571.0    8.4    1,579.4    1,597.7
                                  

2007

                    

United States

   18.1    4.2    22.3    902.1    2.4    904.5    926.8

Algeria

   0.3    0.5    0.8    0.5    —      0.5    1.3

Other International

   —      3.3    3.3    4.1    —      4.1    7.4
                                  

Total

   18.4    8.0    26.4    906.7    2.4    909.1    935.5
                                  

2006

                    

United States

   37.4    2.3    39.7    831.9    2.2    834.1    873.8

Algeria

   0.8    0.8    1.6    1.8    —      1.8    3.4

Other International

   —      2.6    2.6    3.5    —      3.5    6.1
                                  

Total

   38.2    5.7    43.9    837.2    2.2    839.4    883.3
                                  

The following table shows the number of wells in the process of drilling or in active completion stages and the number of wells suspended or waiting on completion as of December 31, 2008:

 

     Wells in the process
of drilling or
in active completion
   Wells suspended or
waiting on completion
     Exploration    Development    Exploration    Development

United States

           

Gross

   11    678    24    9

Net

   6.5    345.1    13.5    6.6

Algeria

           

Gross

   —      1    —      14

Net

   —      0.3    —      2.5

Other International

           

Gross

   4    1    7    —  

Net

   1.3    0.3    2.8    —  

Total

           

Gross

   15    680    31    23

Net

   7.8    345.7    16.3    9.1

 

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Index to Financial Statements

Productive Wells

As of December 31, 2008, the Company had an ownership interest in productive wells as follows:

 

     Oil Wells*    Gas Wells*

United States

     

Gross

   3,952    26,583

Net

   3,022.6    15,929.2

Algeria

     

Gross

   162    —  

Net

   29.5    —  

Other International

     

Gross

   105    —  

Net

   38.0    —  

Total

     

Gross

   4,219    26,583

Net

   3,090.1    15,929.2

 

*  Includes wells containing multiple completions as follows:

     

Gross

   371    1,681

Net

   343.9    1,373.8

Properties and Leases

The following schedule shows the number of developed lease, undeveloped lease and fee mineral acres in which Anadarko held interests at December 31, 2008:

 

     Developed
Lease
   Undeveloped
Lease
   Fee Minerals    Total
thousands of acres    Gross    Net    Gross    Net    Gross    Net    Gross    Net

United States

                       

Onshore—Lower 48

   5,612    3,151    5,099    2,970    9,849    8,322    20,560    14,443

Offshore

   379    171    3,045    1,979    —      —      3,424    2,150

Alaska

   59    9    3,667    1,264    16    8    3,742    1,281
                                       

Total

   6,050    3,331    11,811    6,213    9,865    8,330    27,726    17,874
                                       

Algeria*

   287    70    215    66    —      —      502    136

Other International

   62    22    26,163    11,969    —      —      26,225    11,991

 

* Developed acreage in Algeria relates only to areas with an Exploitation License. A portion of the undeveloped acreage in Algeria will be relinquished in the future consistent with contractual obligations or upon finalization of Exploitation License boundaries.

Midstream Properties and Activities

Anadarko invests in midstream (gathering, treating and processing) facilities to complement its oil and gas operations in regions where the Company has natural gas production. The Company is better able to manage both the value received for, and cost of, gathering, treating and processing natural gas through its ownership and operation of these facilities. In addition, Anadarko’s midstream business provides gathering, treating and processing services for third-party customers, including major and independent producers. Anadarko generates revenues in its gathering, treating and processing activities through various fee structures that include fixed-rate,

 

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Index to Financial Statements

percent of proceeds, or keep-whole agreements. The Company also processes a portion of its gas at various third-party plants. During 2009, less than 10% of the Company’s capital budget is allocated to midstream facilities.

In 2006, Anadarko significantly increased the size and scope of its midstream business through the acquisitions of Western and Kerr-McGee. During 2007, the Company divested control of its interests in two natural gas gathering systems and associated processing plants, in areas where Anadarko has limited or no oil and gas production, for $1.85 billion. At the end of 2008, Anadarko has 29 systems in seven states (Wyoming, Colorado, Utah, New Mexico, Kansas, Oklahoma and Texas) located in major onshore producing basins.

During the second quarter of 2008, Western Gas Partners, LP (WES) completed its initial public offering of 20.8 million common units for net proceeds of $321 million ($343 million less $22 million for underwriting discounts and structuring fees). WES is a Delaware limited partnership formed by Anadarko to own, operate, acquire and develop midstream assets. Anadarko contributed assets to WES in exchange for an aggregate 59.6% limited partner interest (consisting of common and subordinated limited partner units) in WES, a 2% general partner interest and incentive distribution rights (IDRs). IDRs entitle the holder to specified increasing percentages of cash distributions as WES’s per-unit cash distributions increase. In addition, Anadarko maintains control over the assets owned by WES through sole indirect ownership of the general partner interests.

On December 19, 2008, WES acquired additional midstream assets from Anadarko for aggregate consideration of $210 million, consisting of a $175 million note payable to Anadarko and the issuance of 2.6 million common units of WES to Anadarko. In addition, WES issued additional general partner units to its general partner, a wholly-owned subsidiary of Anadarko, to allow it to maintain its 2% general partner interest in WES after contribution by Anadarko of its 2% undivided interest in the midstream assets. Anadarko currently holds an aggregate 61.3% limited partner interest in WES.

The following table provides key statistics for Company-owned gathering and processing facilities.

 

Gathering and Processing Facilities

   Miles of
Gathering

Pipelines
   Total
Horsepower
   2008
Average
Throughput
(MMcf/d)

Hugoton Gathering

   2,070    102,260    130

Wattenberg

   1,720    71,300    250

Powder River CBM

   1,570    414,350    690

Greater Natural Buttes

   890    125,180    330

Granger Complex

   750    46,130    250

Red Desert Complex

   740    64,010    140

Dew Gathering

   320    43,170    200

Pinnacle

   270    1,270    260

Other

   4,390    208,890    1,210
              

Total

   12,720    1,076,560    3,460
              

Marketing Activities

The Company’s marketing department actively manages the sales of Anadarko’s natural gas, crude oil and NGLs. In marketing its production, the Company attempts to minimize market-related shut-ins, maximize realized prices, and manage credit risk exposure. The Company also purchases natural gas, crude oil, condensate and NGLs volumes for resale primarily from partners and producers near Anadarko’s production. These purchases allow Anadarko to aggregate larger volumes and attract larger, creditworthy customers, which enables the Company to maximize prices received for the Company’s production and minimize balancing issues with customers and pipelines during operational disruptions.

The Company sells natural gas under a variety of contracts. The Company has the marketing capability to move large volumes of gas into and out of the daily gas market to capitalize on price volatility. The Company may also engage in trading activities for the purpose of generating profits from exposure to changes in market prices of natural gas, crude oil, condensate and NGLs. The Company’s marketing strategy includes the use of leased natural gas storage facilities, firm transportation contracts and various derivative instruments. However,

 

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Index to Financial Statements

the Company does not engage in market-making practices nor does it trade in any non-energy-related commodities. The Company’s marketing function does not participate in any energy marketing-related partnerships.

The Company also engages in sales of greenhouse gas emission reduction credits (ERCs) derived from CO2 injection operations in Wyoming. The Company expects additional sales of ERCs in the future.

Segment and Geographic Information

For additional information on operations by segment and geographic location, see Note 19—Segment and Geographic Information of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Employees

As of December 31, 2008, the Company had approximately 4,300 employees. Anadarko considers its relations with its employees to be satisfactory. The Company has had no significant work stoppages or strikes associated with its employees.

Regulatory Matters, Environmental and Additional Factors Affecting Business

See Risk Factors under Item 1A and Environmental under Item 7 of this Form 10-K.

Title to Properties

As is customary in the oil and gas industry, only a preliminary title review is conducted at the time properties believed to be suitable for drilling operations are acquired by the Company. Prior to the commencement of drilling operations, a thorough title examination of the drill site tract is conducted and curative work is performed with respect to significant defects, if any, before proceeding with operations. Anadarko believes the title to its leasehold properties is good and defensible in accordance with standards generally acceptable in the oil and gas industry subject to such exceptions that, in the opinion of legal counsel for the Company, are not so material as to detract substantially from the use of such properties.

The leasehold properties owned by the Company are subject to royalty, overriding royalty and other outstanding interests customary in the industry. The properties may be subject to burdens such as liens incident to operating agreements and current taxes, development obligations under oil and gas leases and other encumbrances, easements and restrictions. Anadarko does not believe any of these burdens will materially interfere with its use of these properties.

Capital Spending

See Liquidity and Capital Resources under Item 7 of this Form 10-K.

Ratios of Earnings to Fixed Charges and Earnings to Combined Fixed Charges and Preferred Stock Dividends

 

     2008    2007    2006

Ratio of earnings to fixed charges

   4.79    4.66    5.24

Ratio of earnings to combined fixed charges and preferred stock dividends

   4.79    4.64    5.21

These ratios were computed by dividing earnings by either fixed charges or combined fixed charges and preferred stock dividends. For this purpose, earnings include income from continuing operations before income taxes and fixed charges and excludes undistributed earnings of equity investees. Fixed charges include interest and amortization of debt expenses and the estimated interest component of rentals. Preferred stock dividends are adjusted to reflect the amount of pretax earnings required for payment.

 

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Item 1A. Risk Factors

Forward-Looking Statements The Company has made in this report, and may from time to time otherwise make in other public filings, press releases and discussions with Company management, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning the Company’s operations, economic performance and financial condition. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, marketing and midstream activities and those statements preceded by, followed by or that otherwise include the words “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 have been correct. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, the Company’s assumptions about energy markets, production levels, reserve levels, operating results, competitive conditions, technology, the availability of capital resources, capital expenditures and other contractual obligations, the supply and demand for and the price of natural gas, oil, 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 changes in environmental regulation, environmental risks and liability under federal, state and foreign environmental laws and regulations, potential environmental or other obligations arising from Kerr-McGee’s former chemical business, the securities, capital or credit markets, our ability to repay debt, the outcome of any proceedings related to the Algerian exceptional profits tax, and other factors discussed below and elsewhere in this Form 10-K and in the Company’s other public filings, press releases and discussions with Company management. Anadarko undertakes no obligation to publicly update or revise any forward-looking statements.

Oil, natural gas and NGLs prices are volatile. A substantial or extended decline in prices could adversely affect our financial condition and results of operations.

Prices for oil, natural gas and NGLs can fluctuate widely. Our revenues, operating results and future rate of growth are highly dependent on the prices we receive for our oil, natural gas and NGLs. Historically, the markets for oil, natural gas and NGLs have been volatile and may continue to be volatile in the future. The factors influencing the prices of oil, natural gas and NGLs are beyond our control. These factors include, among others:

 

   

domestic and worldwide supply of, and demand for, oil, natural gas and NGLs;

 

   

volatile trading patterns in the commodity futures markets;

 

   

the cost of exploring for, developing, producing, transporting, and marketing oil, natural gas and NGLs;

 

   

weather conditions;

 

   

the ability of the members of the Organization of Petroleum Exporting Countries (OPEC) and other producing nations to agree to and maintain production levels;

 

   

the worldwide military and political environment, uncertainty or instability resulting from the escalation or additional outbreak of armed hostilities or further acts of terrorism in the United States, or elsewhere;

 

   

the effect of worldwide energy conservation efforts;

 

   

the price and availability of alternative and competing fuels;

 

   

the price and level of foreign imports of oil, natural gas and NGLs;

 

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domestic and foreign governmental regulations and taxes;

 

   

the proximity to, and capacity of, natural gas pipelines and other transportation facilities; and

 

   

general economic conditions worldwide.

The long-term effect of these and other factors on the prices of oil, natural gas and NGLs are uncertain. Prolonged or substantial declines in these commodity prices may have the following effects on our business:

 

   

adversely affecting our financial condition, liquidity, ability to finance planned capital expenditures and results of operations;

 

   

reducing the amount of oil, natural gas and NGLs that we can produce economically;

 

   

causing us to delay or postpone some of our capital projects;

 

   

reducing our revenues, operating income and cash flows;

 

   

reducing the amounts of our estimated proved oil and natural gas reserves;

 

   

reducing the carrying value of our oil and natural gas properties;

 

   

reducing the standardized measure of discounted future net cash flows relating to oil and natural gas reserves; and

 

   

limiting our access to sources of capital, such as equity and long-term debt.

Our debt and other financial commitments may limit our financial and operating flexibility.

As of December 31, 2008, our total debt was about $12.3 billion, which included a $1.7 billion note payable from a midstream subsidiary to a related party. We also have various commitments for operating leases, drilling contracts and transportation and purchase obligations for services and products. Our financial commitments could have important consequences to you. For example, they could:

 

   

increase our vulnerability to general adverse economic and industry conditions;

 

   

limit our ability to fund future working capital and capital expenditures, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flow from operations to payments on our debt or to comply with any restrictive terms of our debt;

 

   

limit our flexibility in planning for, or reacting to, changes in the industry in which we operate; and

 

   

place us at a competitive disadvantage compared to our competitors that have less debt and fewer financial commitments.

A downgrade in our credit rating could negatively impact our cost of and ability to access capital.

As of December 31, 2008, Standard and Poor’s (S&P) and Moody’s Investors Service (Moody’s) rated our debt at “BBB-” with a positive outlook and “Baa3” with a stable outlook, respectively. Although we are not aware of any current plans of S&P or Moody’s to lower their respective ratings on our debt, we cannot be assured that such credit ratings will not be downgraded. A downgrade in our credit ratings could negatively impact our cost of capital or our ability to effectively execute aspects of our strategy. If we were to be downgraded, it could be difficult for us to raise debt in the public debt markets and the cost of that new debt could be much higher than our outstanding debt issued previously. The only outstanding debt that contains rating downgrade triggers that would accelerate the maturity dates of outstanding debt is a $1.7 billion midstream note held by one of Anadarko’s subsidiaries, the maturity of which could accelerate if Anadarko’s senior unsecured credit rating were to be rated below BB- by S&P or Ba3 by Moody’s. The $1.7 billion midstream note is unconditionally guaranteed by Anadarko and, jointly and severally, by certain midstream subsidiaries.

 

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We may incur substantial environmental and other costs arising from Kerr-McGee’s former chemical business.

Prior to its acquisition by the Company, Kerr-McGee through an initial public offering, spun off its chemical manufacturing business to a newly created and separate company, Tronox Incorporated (Tronox). Under the terms of a Master Separation Agreement (MSA), Kerr-McGee agreed to reimburse Tronox for certain qualifying environmental remediation costs, subject to certain limitations and conditions and up to a maximum aggregate reimbursement of $100 million. However, Kerr-McGee could be subject to liability for certain costs of cleaning up hazardous substance contamination attributable to the facilities and operations conveyed to Tronox if Tronox becomes insolvent or otherwise unable to pay for certain remediation costs. As a result of the acquisition of Kerr-McGee, we will be responsible to provide reimbursements to Tronox pursuant to the MSA, and we may be subject to potential liability, as the successor-in-interest to Kerr-McGee, if Tronox is unable to perform certain remediation obligations.

On January 12, 2009, Tronox and certain of its subsidiaries filed voluntary petitions to restructure under Chapter 11 of the United States Bankruptcy Code. As a result of this filing, third parties may seek to impose liability upon Kerr-McGee that is otherwise attributable to Tronox due to Kerr-McGee’s status as the former parent of Kerr-McGee Chemical Worldwide LLC, a predecessor-in-interest to Tronox. In addition, based on the information contained in the Tronox bankruptcy filings, it is also possible that third parties may pursue other claims against Kerr-McGee associated with the separation of Kerr-McGee’s former chemical business and the initial public offering of Tronox. Currently, we are unable to estimate the amount of these potential liabilities.

Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

Recently, concerns over inflation, energy costs, geopolitical issues, the availability and cost of credit, the United States mortgage market and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy.

These factors, combined with volatile oil, natural gas and NGLs prices, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad continues to deteriorate, demand for petroleum products could continue to diminish, which could impact the price at which we can sell our oil, natural gas and NGLs, affect our vendors, suppliers and customers ability to continue operations, and ultimately adversely impact our results of operations, liquidity and financial condition.

Our results of operations could be adversely affected by asset impairments.

If oil, natural gas and NGLs prices continue to decrease, we may be required to write-down the value of our oil and gas properties if the estimated future cash flows from these properties fall below their net book value. Future non-cash asset impairments could negatively affect our results of operations.

As a result of mergers and acquisitions, at December 31, 2008 we had approximately $5.3 billion of goodwill on our balance sheet. Goodwill is not amortized, but instead must be tested at least annually for impairment, and more frequently when circumstances indicate likely impairment, by applying a fair-value-based test. Goodwill is deemed impaired to the extent that its carrying amount exceeds its implied fair value. Various factors could lead to goodwill impairments that could have a substantial negative effect on our profitability, such as if the Company is unable to replace the value of its depleting asset base or if other adverse events, such as lower sustained oil and gas prices, reduce the fair value of the associated reporting unit.

 

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We are subject to complex laws and regulations relating to environmental protection that can adversely affect the cost, manner and feasibility of doing business.

Our operations and properties are subject to numerous federal, state, tribal, local and foreign laws and regulations relating to environmental protection from the time projects commence until abandonment. These laws and regulations govern, among other things:

 

   

the amounts and types of substances and materials that may be released;

 

   

the issuance of permits in connection with exploration, drilling and production activities;

 

   

the protection of endangered species;

 

   

the release of emissions;

 

   

the discharge and disposition of generated waste materials;

 

   

offshore oil and gas operations;

 

   

the reclamation and abandonment of wells and facility sites; and

 

   

the remediation of contaminated sites.

In addition, these laws and regulations may impose substantial liabilities for our failure to comply with them or for any contamination resulting from our operations. Future environmental laws and regulations, such as proposed legislation regulating climate change, may negatively impact our industry. The cost of meeting these requirements may have an adverse effect on our financial condition, results of operations and cash flows. For a description of certain environmental proceedings in which we are involved, see Legal Proceedings under Item 3 of this Form 10-K.

We are vulnerable to risks associated with operating in the Gulf of Mexico that could negatively impact our operations and financial results.

Our operations and financial results could be significantly impacted by conditions in the Gulf of Mexico because we explore and produce extensively in that area. As a result of this activity, we are vulnerable to the risks associated with operating in the Gulf of Mexico, including those relating to:

 

   

hurricanes and other adverse weather conditions;

 

   

oil field service costs and availability;

 

   

compliance with environmental and other laws and regulations;

 

   

remediation and other costs resulting from oil spills or releases of hazardous materials; and

 

   

failure of equipment or facilities.

In addition, we are currently conducting some of our exploration in the deep waters (greater than 1,000 feet) of the Gulf of Mexico, where operations are more difficult and costly than in shallower waters. The deep waters in the Gulf of Mexico lack the physical and oilfield service infrastructure present in its shallower waters. As a result, deepwater operations may require a significant amount of time between a discovery and the time that we can market our production, thereby increasing the risk involved with these operations.

Further, production of reserves from reservoirs in the Gulf of Mexico generally declines more rapidly than from reservoirs in many other producing regions of the world. This results in recovery of a relatively higher percentage of reserves from properties in the Gulf of Mexico during the initial few years of production and, as a result, our reserve replacement needs from new prospects may be greater there than for our operations elsewhere. Also, our revenues and return on capital will depend significantly on prices prevailing during these relatively short production periods.

 

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We operate in other countries and are subject to political, economic and other uncertainties.

Our operations in areas outside the United States are based primarily in Algeria, China, Brazil, Ghana and Indonesia. As a result, we face political and economic risks and other uncertainties with respect to our international operations. These risks may include, among other things:

 

   

loss of revenue, property and equipment as a result of hazards such as expropriation, war, acts of terrorism, insurrection and other political risks;

 

   

increases in taxes and governmental royalties;

 

   

unilateral renegotiation of contracts by governmental entities;

 

   

difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations;

 

   

changes in laws and policies governing operations of foreign-based companies; and

 

   

currency restrictions and exchange rate fluctuations.

Our international operations may also be adversely affected by laws and policies of the United States affecting foreign trade and taxation.

Realization of any of these factors could materially and adversely affect our financial position, results of operations and cash flows.

Our commodity price risk management and trading activities may prevent us from benefiting fully from price increases and may expose us to other risks.

To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may be prevented from realizing the full benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, our commodity price management and trading activities may expose us to the risk of financial loss in certain circumstances, including instances in which:

 

   

our production is less than the hedged volumes;

 

   

there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;

 

   

the counterparties to our hedging or other price risk management contracts fail to perform under those arrangements; or

 

   

a sudden unexpected event materially impacts oil and natural gas prices.

In addition, we engage in limited speculative trading in hydrocarbon commodities, which subjects us to additional risk.

The credit risk of financial institutions could adversely affect us.

We have exposure to different counterparties, and we have entered into transactions with counterparties in the financial services industry, including, commercial banks, investment banks, insurance companies, other investment funds and other institutions. These transactions expose us to credit risk in the event of default of our counterparty. Continued deterioration in the credit markets may continue to impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to these financial institutions in the form of derivative transactions in connection with our hedges. We also maintain insurance policies with insurance companies to protect us against certain risks inherent in our business. In addition, if any lender under our credit facility is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under our credit facility.

 

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Our proved reserves are estimates. Any material inaccuracies in our reserve estimates or assumptions underlying our reserve estimates could cause the quantities and net present value of our reserves to be overstated or understated.

There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control that could cause the quantities and net present value of our reserves to be overstated. The reserve information included or incorporated by reference in this report represents estimates prepared by our internal engineers. The procedures and methods for estimating the reserves by our internal engineers were reviewed by independent petroleum consultants. Estimation of reserves is not an exact science. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, any of which may cause these estimates to vary considerably from actual results, such as:

 

   

historical production from an area compared with production from similar producing areas;

 

   

assumed effects of regulation by governmental agencies;

 

   

assumptions concerning future oil and natural gas prices, future operating costs and capital expenditures; and

 

   

estimates of future severance and excise taxes, workover and remedial costs.

Estimates of reserves based on risk of recovery and estimates of expected future net cash flows prepared or audited by different engineers, or by the same engineers at different times, may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and the variance may be material. The net present values referred to in this report should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower.

Failure to replace reserves may negatively affect our business.

Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves generally decline when reserves are produced, unless we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. We may be unable to find, develop or acquire additional reserves on an economic basis. Furthermore, if oil and natural gas prices increase, our costs for additional reserves could also increase.

We may not be insured against all of the operating risks to which our business is exposed.

Our business is subject to all of the operating risks normally associated with the exploration for and production, gathering, processing and transportation of oil and gas, including hurricanes, blowouts, cratering and fire, any of which could result in damage to, or destruction of, oil and natural gas wells or formations or production facilities and other property and injury to persons. As protection against financial loss resulting from these operating hazards, we maintain insurance coverage, including certain physical damage, employer’s liability, comprehensive general liability and worker’s compensation insurance. However, we are not fully insured against all risks in all aspects of our business, such as political risk, business interruption risk and risk of major terrorist attacks. The occurrence of a significant event against which we are not fully insured could have a material adverse effect on our financial position.

 

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Material differences between the estimated and actual timing of critical events may affect the completion of and commencement of production from development projects.

We are involved in several large development projects. Key factors that may affect the timing and outcome of such projects include:

 

   

project approvals by joint-venture partners;

 

   

timely issuance of permits and licenses by governmental agencies;

 

   

weather conditions;

 

   

manufacturing and delivery schedules of critical equipment; and

 

   

commercial arrangements for pipelines and related equipment to transport and market hydrocarbons.

Delays and differences between estimated and actual timing of critical events may affect the forward looking statements related to large development projects.

Our domestic operations are subject to governmental risks that may impact our operations.

Our domestic operations have been, and at times in the future may be, affected by political developments and by federal, state, tribal and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations.

The oil and gas exploration and production industry is very competitive, and some of our exploration and production competitors have greater financial and other resources than we do.

The oil and gas business is highly competitive in the search for and acquisition of reserves and in the gathering and marketing of oil and gas production. Our competitors include national oil companies, major oil and gas companies, independent oil and gas companies, individual producers, gas marketers and major pipeline companies, as well as participants in other industries supplying energy and fuel to industrial, commercial and individual consumers. Some of our competitors may have greater and more diverse resources upon which to draw than we do. If we are not successful in our competition for oil and gas reserves or in our marketing of production, our financial condition and results of operations may be adversely affected.

The high cost or unavailability of drilling rigs, equipment, supplies, personnel and other oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of rigs, equipment, supplies and personnel are substantially greater and their availability may be limited. Additionally, these services may not be available on commercially reasonable terms. As a result of the recent historically high levels of exploration and production in response to strong demand for crude oil and natural gas, the demand for oilfield services has risen and the costs of these services have also been increasing to historically high levels.

Our drilling activities may not be productive.

Drilling for oil and natural gas involves numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

 

   

unexpected drilling conditions;

 

   

pressure or irregularities in formations;

 

   

equipment failures or accidents;

 

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fires, explosions, blow-outs and surface cratering;

 

   

marine risks such as capsizing, collisions and hurricanes;

 

   

title problems;

 

   

other adverse weather conditions; and

 

   

shortages or delays in the delivery of equipment.

Certain of our future drilling activities may not be successful and, if unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. Because of the percentage of our capital budget devoted to higher-risk exploratory projects, it is likely that we will continue to experience significant exploration and dry hole expenses.

Repercussions from terrorist activities or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts or other armed conflict involving the United States or its interests abroad may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If events of this nature occur and persist, the attendant political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on prevailing oil and natural gas prices and causing a reduction in our revenues. Oil and natural gas production facilities, transportation systems and storage facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our operations is destroyed or damaged by such an attack. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

We have limited control over the activities on properties we do not operate.

Other companies operate some of the properties in which we have an interest. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital and lead to unexpected future costs.

Our ability to sell our natural gas and crude oil production could be materially harmed if we fail to obtain adequate services such as transportation.

The marketability of our production depends in part upon the availability, proximity and capacity of pipeline facilities and tanker transportation. If any of the pipelines or tankers become unavailable, we would be required to find a suitable alternative to transport the gas and oil, which could increase our costs and/or reduce the revenues we might obtain from the sale of the gas and oil.

Provisions in our corporate documents and Delaware law could delay or prevent a change of control of Anadarko, even if that change would be beneficial to our stockholders.

Our restated certificate of incorporation and by-laws contain provisions that may make a change of control of Anadarko difficult, even if it may be beneficial to our stockholders, including provisions governing the classification, nomination and removal of directors, prohibiting stockholder action by written consent and regulating the ability of our stockholders to bring matters for action before annual stockholder meetings, and the authorization given to our Board of Directors to issue and set the terms of preferred stock.

In addition, Section 203 of the Delaware General Corporation Law imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock.

 

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We may reduce or cease to pay dividends on our common stock.

We can provide no assurance that we will continue to pay dividends at the current rate or at all. The amount of cash dividends, if any, to be paid in the future will depend upon their declaration by our Board of Directors and upon our financial condition, results of operations, cash flow, the levels of our capital and exploration expenditures, our future business prospects and other related matters that our Board of Directors deems relevant.

The loss of key members of our management team, or difficulty attracting and retaining experienced technical personnel, could reduce our competitiveness and prospects for future success.

The successful implementation of our strategies and handling of other issues integral to our future success will depend, in part, on our experienced management team. The loss of key members of our management team, including James T. Hackett, our Chairman, President and Chief Executive Officer, could have an adverse effect on our business. We entered into an employment agreement with Mr. Hackett to secure his employment with us. We do not carry key man insurance. Our exploratory drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced explorationists, engineers and other professionals. Competition for such professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.

 

Item 1B. Unresolved Staff Comments

The Company has no outstanding or unresolved SEC staff comments.

 

Item 3. Legal Proceedings

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

Environmental Matters The United States Environmental Protection Agency Region 8 (EPA) and the United States Department of Justice (DOJ) have alleged that a number of spills at the Company’s Salt Creek and Elk Basin Fields violated provisions of the federal Clean Water Act and the facilities had inadequate Spill Prevention Control and Countermeasure (SPCC) plans and Facility Response Plans (FRP). The Company sold substantially all of Elk Basin to a third party in 2007, but the Company agreed to retain responsibility for the historical spills, SPCC and FRP issues at Elk Basin. The Company reached a tentative settlement with the EPA and DOJ to resolve these allegations by agreeing to pay a fine of approximately $1 million, plus agreeing to perform certain preventative actions, subject to negotiating a mutually agreeable settlement agreement. In the opinion of management, the liability with respect to these actions will not have a material effect on the consolidated financial position, results of operations or cash flow of the Company.

Other Matters The Company is subject to other legal proceedings, claims and liabilities which arise in the ordinary course of its business. In the opinion of Anadarko, the liability with respect to these actions will not have a material effect on the consolidated financial position, results of operations or cash flow of the Company.

 

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Item 4. Submission of Matters to a Vote of Security Holders

There were no matters submitted to a vote of security holders during the fourth quarter of 2008.

Executive Officers of the Registrant

 

Name

   Age at End
of 2009
  

Position

James T. Hackett

   55    Chairman of the Board, President and Chief Executive Officer

Karl F. Kurz

   48    Chief Operating Officer

Robert P. Daniels

   50    Senior Vice President, Worldwide Exploration

Robert G. Gwin

   46    Senior Vice President

Charles A. Meloy

   49    Senior Vice President, Worldwide Operations

Robert K. Reeves

   52   

Senior Vice President, General Counsel and Chief Administrative Officer

R. A. Walker

   52    Senior Vice President, Finance and Chief Financial Officer

M. Cathy Douglas

   53    Vice President, Chief Accounting Officer and Controller

Mr. Hackett was named President and Chief Executive Officer in December 2003 and assumed the additional role of Chairman of the Board in January 2006. Prior to joining Anadarko, he served as President and Chief Operating Officer of Devon Energy Corporation following its merger with Ocean Energy, Inc. in April 2003. Mr. Hackett served as President and Chief Executive Officer of Ocean Energy, Inc. from March 1999 to April 2003 and as Chairman of the Board from January 2000 to April 2003. He currently serves as a director of Fluor Corporation and Halliburton Company and serves as Chairman of the Board of the Federal Reserve Bank of Dallas.

Mr. Kurz was named Chief Operating Officer in December 2006. Prior to this position, he served as Senior Vice President of North American Operations, Midstream and Marketing. He was named Senior Vice President of Marketing and General Manager, U.S. Onshore in May 2005, and from 2003 until that time he served as Vice President, Marketing. He joined Anadarko as Manager of Energy Marketing in 2000. Mr. Kurz has also served as a director of Western Gas Holdings, LLC, a subsidiary of Anadarko and the general partner of Western Gas Partners, LP since August 2007.

Mr. Daniels was named Senior Vice President, Worldwide Exploration in December 2006, Senior Vice President, Exploration and Production in 2004 and named Vice President, Canada in 2001. Prior to this position, he served in various managerial roles in the Exploration Department for Anadarko Algeria Company, LLC. He has worked for the Company since 1985.

Mr. Gwin was named Senior Vice President in March 2008. He also serves as President, Chief Executive Officer and a director of Western Gas Holdings, LLC. He joined Anadarko in January 2006 as Vice President, Finance and Treasurer. Prior to this position, he served as Chairman, President and CEO of Prosoft Learning Corporation from November 2002 to November 2004 and prior to that served as its Chief Financial Officer from 2000 to November 2002. Previously, Mr. Gwin spent 10 years at Prudential Capital Group in merchant banking roles of increasing responsibility, including serving as Managing Director with responsibility for the firm’s energy investments worldwide.

Mr. Meloy was named Senior Vice President, Worldwide Operations in December 2006 and had served as Senior Vice President, Gulf of Mexico and International Operations since the acquisition of Kerr-McGee in August 2006. Prior to joining Anadarko, he served Kerr-McGee as Vice President of Exploration and Production from 2005 to 2006, Vice President of Gulf of Mexico Exploration, Production and Development from 2004 to 2005, Vice President and Managing Director of Kerr-McGee North Sea (U.K.) Limited from 2002 to 2004 and Vice President of Gulf of Mexico Deep Water from 2000 to 2002.

Mr. Reeves was named Senior Vice President, General Counsel and Chief Administrative Officer in February 2007. He had previously served as Senior Vice President, Corporate Affairs & Law and Chief Governance Officer since 2004. Prior to joining Anadarko, he served as Executive Vice President, Administration and General Counsel of North Sea New Ventures from 2003 to 2004, and as Executive Vice

 

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President, General Counsel and Secretary of Ocean Energy, Inc. and its predecessor companies from 1997 to 2003. He has also served as a director of Key Energy Services, Inc., a publicly traded oil field services company, since October 2007, and as a director of Western Gas Holdings, LLC since August 2007.

Mr. Walker was named Senior Vice President, Finance and Chief Financial Officer in September 2005. Prior to joining Anadarko, he served as Managing Director for the Global Energy Group of UBS Investment Bank from 2003 to 2005 and was President and Chief Financial Officer of 3TEC Energy Corporation from 2000 to 2003. From 1987 to 2000, he worked for Prudential Capital Group in a variety of merchant banking positions. He has also served as a director of Temple-Inland, Inc. since November 2008, and as the Chairman of Western Gas Holdings, LLC since August 2007. Mr. Walker also serves on the Board of Trustees of the United Way of Greater Houston and the Houston Museum of Natural Science.

Ms. Douglas was named Vice President, Chief Accounting Officer and Controller in November 2008 and had served as Controller since September 2007. She served as Assistant Controller from July 2006 to September 2007. Ms. Douglas also served as Director, Accounting, Policy and Coordination from October 2006 to September 2007 and Financial Reporting and Policy Manager from January 2003 to October 2006. She joined Anadarko in 1979.

Officers of Anadarko are elected at an organizational meeting of the Board of Directors following the annual meeting of stockholders, which is expected to occur on May 19, 2009, and hold office until their successors are duly elected and shall have qualified. There are no family relationships between any directors or executive officers of Anadarko.

 

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Table of Contents
Index to Financial Statements

PART II

 

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

As of January 30, 2009, there were approximately 17,010 record holders of Anadarko common stock. The common stock of Anadarko is traded on the New York Stock Exchange. The following shows information regarding the closing market price of and dividends declared and paid on the Company’s common stock by quarter for 2008 and 2007.

 

     First
Quarter
   Second
Quarter
   Third
Quarter
   Fourth
Quarter

2008

           

Market Price

           

High

   $ 66.75    $ 79.86    $ 74.47    $ 48.21

Low

   $ 54.02    $ 62.56    $ 44.86    $ 27.17

Dividends

   $ 0.09    $ 0.09    $ 0.09    $ 0.09

2007

           

Market Price

           

High

   $ 43.92    $ 55.33    $ 54.77    $ 67.05

Low

   $ 38.63    $ 43.68    $ 47.14    $ 53.89

Dividends

   $ 0.09    $ 0.09    $ 0.09    $ 0.09

The amount of future common stock dividends will depend on earnings, financial condition, capital requirements and other factors, and will be determined by the Board of Directors on a quarterly basis. For additional information, see Dividends under Item 7 and Note 11—Stockholders’ Equity and Note 12—Stock-Based Compensation under Item 8 of this Form 10-K.

Common Stock Repurchase Table The following table sets forth information with respect to repurchases by the Company of its shares of common stock during the fourth quarter of 2008.

 

Period

   Total
number of
shares
purchased(1)
   Average
price paid
per share
   Total number of
shares purchased
as part of publicly
announced plans
or programs
   Approximate dollar
value of shares that
may yet be
purchased under the
plans or programs(2)

October 1-31

   523    $ 42.35    —     

November 1-30

   68,782    $ 37.79    —     

December 1-31

   261,306    $ 37.26    —     
               

Fourth Quarter 2008

   330,611    $ 37.38    —      $ 4,400,000,000
                   

 

(1)

During the fourth quarter of 2008, no shares were purchased under the Company’s share repurchase program. During the fourth quarter of 2008, 330,611 shares purchased were related to stock received by the Company for the payment of withholding taxes due on shares issued under employee stock plans.

 

(2)

In August 2008, the Company announced a share repurchase program to purchase up to $5 billion in shares of common stock. The program replaces the prior repurchase program and is authorized to extend through August 2011; however, the repurchase program does not obligate Anadarko to acquire any specific number of shares and may be discontinued at any time.

 

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Index to Financial Statements

Performance Graph

The following performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.

The following graph compares the cumulative 5-year total return to shareholders on Anadarko’s common stock relative to the cumulative total returns of the S&P 500 index and a customized peer group of eleven companies. The companies included in the customized peer group are: Apache Corporation, ConocoPhillips, Devon Energy Corporation, EnCana Corporation, EOG Resources, Inc., Hess Corporation, Marathon Oil Corporation, Noble Energy, Inc., Occidental Petroleum Corporation, Pioneer Natural Resources Company and Talisman Energy Inc.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN AMONG

ANADARKO PETROLEUM CORPORATION, THE S&P 500 INDEX,

AND A PEER GROUP

LOGO

An investment of $100 (with reinvestment of all dividends) is assumed to have been made in the Company’s common stock, in the index and in the peer group on December 31, 2003 and its relative performance is tracked through December 31, 2008.

 

Fiscal Year Ended December 31    2003    2004    2005    2006    2007    2008

Anadarko Petroleum Corporation

   $ 100.00    $ 128.27    $ 189.10    $ 175.03    $ 266.12    $ 157.24

S&P 500

     100.00      110.88      116.33      134.70      142.10      89.53

Peer Group

     100.00      136.70      207.24      238.80      335.24      214.86

 

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Index to Financial Statements
Item 6. Selected Financial Data

 

     Summary Financial Information*
millions, except per share amounts    2008     2007    2006     2005    2004

Sales Revenues

   $ 14,640     $ 11,132    $ 10,116     $ 6,197    $ 5,085

Gains (Losses) on Divestitures and Other, net

     1,083       4,760      114       111      755
                                    

Total Revenues and Other

     15,723       15,892      10,230       6,308      5,840

Operating Income

     6,162       7,347      4,381       3,398      2,577

Income from Continuing Operations

     3,198       3,770      2,474       1,975      1,325

Income from Discontinued Operations, net of taxes

     63       11      2,275       356      37

Net Income Available to Common Stockholders

     3,260       3,778      4,746       2,326      1,357

Per Common Share:

            

Income from Continuing Operations—Basic

   $ 6.87     $ 8.09    $ 5.37     $ 4.19    $ 2.64

Income from Continuing Operations—Diluted

   $ 6.84     $ 8.05    $ 5.33     $ 4.15    $ 2.62

Income from Discontinued Operations—Basic

   $ 0.13     $ 0.02    $ 4.94     $ 0.76    $ 0.07

Income from Discontinued Operations—Diluted

   $ 0.13     $ 0.02    $ 4.91     $ 0.75    $ 0.07

Net Income Available to Common Stockholders—Basic

   $ 7.01     $ 8.12    $ 10.31     $ 4.95    $ 2.72

Net Income Available to Common Stockholders—Diluted

   $ 6.97     $ 8.08    $ 10.24     $ 4.90    $ 2.69

Dividends

   $ 0.36     $ 0.36    $ 0.36     $ 0.36    $ 0.28

Average Number of Common Shares Outstanding—Basic

     465       465      460       470      499

Average Number of Common Shares Outstanding—Diluted

     468       468      464       475      503

Cash Provided by Operating Activities—Continuing Operations

   $ 6,447     $ 2,766    $ 4,671     $ 3,221    $ 2,412

Cash Provided by (Used in) Operating Activities—Discontinued Operations

     (5 )     134      (178 )     591      400

Net Cash Provided by Operating Activities

     6,442       2,900      4,493       3,812      2,812

Capital Expenditures

   $ 4,881     $ 3,990    $ 4,212     $ 2,644    $ 2,185

Current Debt

   $ 1,472     $ 1,396    $ 11,471     $ 80    $ 169

Long-term Debt

     9,128       11,151      11,520       3,547      3,621

Midstream subsidiary note payable to a related party

     1,739       2,200      —         —        —  

Total Debt

   $ 12,339     $ 14,747    $ 22,991     $ 3,627    $ 3,790

Stockholders’ Equity

     18,795       16,364      12,403       8,649      7,027

Total Assets

   $ 48,923     $ 48,451    $ 54,964     $ 18,902    $ 16,714

Annual Sales Volumes:

            

Continuing Operations

            

Gas (Bcf)

     750       698      558       414      499

Oil and Condensate (MMBbls)

     67       79      70       57      63

Natural Gas Liquids (MMBbls)

     14       16      15       13      16

Total (MMBOE)**

     206       211      178       139      162

Discontinued Operations (MMBOE)

     —         —        17       20      29

Total (MMBOE)**

     206       211      195       159      191

Average Daily Sales Volumes:

            

Continuing Operations

            

Gas(MMcf/d)

     2,049       1,912      1,529       1,136      1,363

Oil and Condensate (MBbls/d)

     182       215      193       155      172

Natural Gas Liquids (MBbls/d)

     39       43      42       36      43

Total (MBOE/d)

     563       577      489       380      442

Discontinued Operations (MBOE/d)

     —         —        46       55      79

Total (MBOE/d)

     563       577      535       435      521

Reserves:

            

Continuing Operations

            

Oil Reserves (MMBbls)

     926       1,014      1,264       1,090      1,073

Gas Reserves (Tcf)

     8.1       8.5      10.5       6.6      6.2

Total Reserves (MMBOE)

     2,277       2,431      3,011       2,187      2,113

Discontinued Operations (MMBOE)

     —         —        —         262      254

Total Reserves (MMBOE)

     2,277       2,431      3,011       2,449      2,367

Number of Employees

     4,300       4,000      5,200       3,300      3,300
* Consolidated for Anadarko Petroleum Corporation and its subsidiaries. Certain amounts for prior years have been reclassified to conform to the current presentation. Factors that materially effect the comparability of this information are disclosed in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Item 7 of this Form 10-K.
** Natural gas converted to equivalent barrels at the rate of 6,000 cubic feet of gas per barrel.

 

Table of Measures

  

Bcf—Billion cubic feet

   MMBbls—Million barrels

BOE—Barrels of oil equivalent

   MMBOE—Million barrels of oil equivalent

MBbls/d—Thousand barrels per day

   MMcf/d—Million cubic feet per day

MBOE/d—Thousand BOE per day

   Tcf—Trillion cubic feet

 

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Index to Financial Statements
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this report in Item 8, and the Risk Factors information, which are set forth in Item 1A.

Overview

Anadarko Petroleum Corporation is among the world’s largest independent oil and natural gas exploration and production companies. Anadarko’s primary line of business is the exploration, development, production, gathering, processing and marketing of natural gas, crude oil, condensate and NGLs. The Company’s major areas of operations are located in the United States and Algeria, with additional activity in Brazil, China, Ghana, Indonesia, Mozambique and several other countries.

Anadarko achieved its key operational objectives in 2008, during a year marked by a downturn in the financial markets and a volatile commodity-price environment that included New York Mercantile Exchange (NYMEX) oil prices rising to highs above $140 per barrel, and falling to lows under $40 per barrel. The Company is managing its 2009 capital program consistent with a sustained lower-commodity-price environment. Anadarko ended 2008 with approximately $2.4 billion of cash on hand and retains the availability of its undrawn $1.3 billion revolving credit agreement (RCA), along with access to credit markets. Management expects this liquidity position and cash flow from operations to position the Company to meet its 2009 operational objectives and capital commitments.

Mission and Strategy

Anadarko’s mission is to deliver a competitive and sustainable rate of return to shareholders by exploring for, acquiring and developing oil and natural gas resources vital to the world’s health and welfare. Anadarko employs the following strategy to achieve this mission:

 

   

Identify and commercialize resources

 

   

Explore in high-potential, proven basins

 

   

Employ global business development approach

 

   

Ensure financial discipline and flexibility

The first portion of this strategy involves Anadarko developing its portfolio of primarily unconventional resources that give the Company a stable base of capital-efficient, predictable and repeatable development opportunities to consistently grow the Company at competitive rates.

Exploring in high-potential, proven and emerging basins worldwide provides the Company with differential growth. Anadarko’s exploration success creates value by expanding its future resource potential, while providing the flexibility to manage risk by monetizing discoveries.

Anadarko’s global business development approach transfers core skills across the globe to discover and develop world-class resources that are accretive to the Company’s performance. These resources help form an optimized-global portfolio where both surface and subsurface risks are actively managed.

A strong balance sheet is essential for the development of the Company’s assets, and Anadarko is committed to disciplined investments in its businesses to manage through commodity price cycles. Maintaining financial discipline enables the Company to capitalize on the flexibility of its global portfolio, while allowing the Company to pursue new strategic and tactical-growth opportunities.

 

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Operating Highlights

The Company overcame significant weather events and third-party-related infrastructure issues in 2008 to achieve production growth, reserve additions, and production replacement. Significant operational highlights by area include:

United States Onshore

   

Achieved record production in the Rocky Mountain region

 

   

Secured additional takeaway and processing capacity in the Rockies region

 

   

Expanded acreage position and began testing prospects in the Haynesville and Marcellus shale plays, located in East Texas and central Pennsylvania, respectively, as well as the Maverick basin in South Texas

Gulf of Mexico

   

Announced a successful appraisal well at Tonga West and approved the Caesar/Tonga complex

 

   

All Anadarko-operated facilities successfully weathered two major hurricanes with only minor, localized surface damage; however some production remained curtailed due to third-party pipeline and infrastructure issues

 

   

Restored production to pre-shut-in levels at Independence Hub within 72 hours of Hurricane Ike

 

   

Restored production on June 16, 2008 to nearly a billion cubic feet per day of natural gas at Independence Hub after a ten-week shut-in due to a third-party export pipeline leak

International

   

Announced major discoveries and successful appraisal wells offshore Ghana in and near the Jubilee field

 

   

Announced the Company’s first pre-salt discovery in the Campos basin offshore Brazil at the Wahoo prospect

 

   

Achieved 1-billion-barrel production milestone in Algeria

 

   

Acquired six blocks in the West Africa Cretaceous trend located in Sierra Leone and Liberia

Financial Highlights

The Company’s 2008 financial highlights include:

 

   

Generated $6.4 billion of cash flow from continuing operating activities compared to $2.8 billion in 2007 due to higher commodity prices

 

   

Announced a $5 billion share repurchase program and completed $600 million of repurchases in the third quarter of 2008

 

   

Completed an initial public offering through the issuance of 20.8 million common units of its formerly wholly-owned midstream subsidiary, WES, for net proceeds of $321 million

 

   

Closed the divestitures of the Company’s interest in the Peregrino field offshore Brazil and the Kaskida discovery in the deepwater Gulf of Mexico for before-tax proceeds of approximately $1.8 billion

 

   

Reduced year-end debt-to-capital ratio to 39.6%. Reduced debt by $2.4 billion in 2008, including repayment of the Company’s 2006 acquisition financing and approximately $580 million of floating rate notes due in 2009

 

   

Closed 2008 with $2.4 billion of cash on hand

 

   

Operated in a volatile commodity-price environment that included NYMEX oil prices rising to highs above $140 per barrel, and falling to lows under $40 per barrel

 

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Index to Financial Statements

The following discussion pertains to Anadarko’s financial condition, results of operations and changes in financial condition. Unless noted otherwise, the following information relates to continuing operations and excludes the discontinued Canadian operations. The primary factors that affect the Company’s results of operations include, among other things, commodity prices for natural gas, crude oil and NGLs, production volumes, the Company’s ability to find additional oil and natural gas reserves, as well as the cost of finding reserves and changes in the levels of costs and expenses required for continuing operations. Unless the context otherwise requires, the terms “Anadarko” or “Company” refer to Anadarko Petroleum Corporation and its consolidated subsidiaries. Following is an index by major category of discussion including a brief description of contents:

 

Table of Contents   
     Page

Financial Results — comparative discussion of financial results of operations

   35

Operating Results — discussion of business activities

   43

Liquidity and Capital Resources — discussion of sources and uses of cash, outlook on operations and

 material financial arrangements, obligations and commitments

   50

Critical Accounting Estimates — discussion of significant judgments and estimates

   60

Recent Accounting Developments — discussion of accounting guidance effective in future periods

   65

Results of Continuing Operations

Selected Data

 

millions except per share amounts and percentages    2008     2007     2006(2)  

Financial Results

      

Sales revenues

   $ 14,640     $ 11,132     $ 10,116  

Gains on divestitures and other, net

     1,083       4,760       114  
                        

Total revenues and other

     15,723       15,892       10,230  

Costs and expenses

     9,561       8,545       5,849  

Other (income) expense

     816       1,018       644  

Income tax expense

     2,148       2,559       1,263  

Income from continuing operations

   $ 3,198     $ 3,770     $ 2,474  

Earnings per common share—diluted

   $ 6.84     $ 8.05     $ 5.33  

Average number of common shares outstanding—diluted

     468       468       464  

Operating Results

      

Adjusted EBITDAX(1)

   $ 10,874     $ 11,217     $ 7,203  

Total proved reserves (MMBOE)

     2,277       2,431       3,011  

Annual sales volumes (MMBOE)

     206       211       178  

Capital Resources and Liquidity

      

Cash provided by operating activities

   $ 6,447     $ 2,766     $ 4,671  

Capital expenditures

     4,881       3,990       4,212  

Total debt

     12,339       14,747       22,991  

Stockholders’ equity

   $ 18,795     $ 16,364     $ 12,403  

Debt to total capitalization ratio

     39.6 %     47.4 %     65.0 %

 

(1)

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

 

(2)

Anadarko’s financial and operating results for 2006 include the operating results of Kerr-McGee and Western since the dates of their acquisitions on August 10, 2006, and August 23, 2006, respectively.

 

34


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Index to Financial Statements

Financial Results

Income from Continuing Operations Anadarko’s income from continuing operations for 2008 totaled $3.2 billion, or $6.84 per share (diluted), compared to income from continuing operations for 2007 of $3.8 billion, or $8.05 per share (diluted). Anadarko had income from continuing operations in 2006 of $2.5 billion, or $5.33 per share (diluted). The decrease in income from continuing operations for 2008 compared to 2007 was primarily due to a decrease in gains on divestitures and higher costs and expenses, partially offset by higher natural gas, oil and NGLs sales, including the impact of derivatives, lower interest expense and lower income tax expense. The increase in 2007 income from continuing operations compared to 2006 was primarily due to gains on divestitures and higher sales volumes, partially offset by the impact of lower natural gas and oil and condensate prices, higher costs and expenses, including other taxes related to an Algerian exceptional profits tax, and higher interest expense. In 2008, the higher sales revenues and costs and expenses were due primarily to the impact of higher commodity prices, higher exploration expense related to impairments of unproved properties and higher other taxes related to the higher commodity prices. In 2007, the higher sales volumes and costs and expenses were due primarily to the impact of operations acquired with the third quarter 2006 acquisitions.

Sales Revenues

 

               D vs.          D vs.  
millions except percentages    2008    2007    2008     2006    2007  

Gas sales

   $ 6,254    $ 4,119    52 %   $ 4,186    (2 )%

Oil and condensate sales

     6,502      4,807    35       4,618    4  

Natural gas liquids sales

     802      719    12       594    21  

Gathering, processing and marketing sales

     1,082      1,487    (27 )     718    107  
                         

Total

   $ 14,640    $ 11,132    32     $ 10,116    10  
                         

Anadarko’s sales revenues for 2008 increased when compared to 2007 due to higher oil and condensate, natural gas and NGLs commodity prices and unrealized gains on derivatives, partially offset by lower sales volumes associated with properties that were divested in 2007. The increase in 2007 compared to 2006 was primarily due to higher sales volumes, partially offset by significantly lower natural gas and oil and condensate prices.

The Company’s sales revenues for 2008, 2007 and 2006 include $930 million, $(1,100) million and $895 million, respectively, related to net unrealized gains (losses) on derivatives used to manage price risk on natural gas, crude oil, condensate and NGLs sales. The significant fluctuations in unrealized gains (losses) are due primarily to an increase in Anadarko’s derivative portfolio as a result of the 2006 acquisition of Kerr-McGee, as well as the discontinuance of hedge accounting effective January 1, 2007. The majority of the unrealized gains recorded in 2006 related to derivatives assumed with the Kerr-McGee acquisition. Any realization of these gains or losses is expected to be substantially offset by the value realized from that portion of the Company’s production covered by the derivative instruments.

 

35


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Index to Financial Statements

Analysis of Oil and Gas Operations Sales Revenues

The following table provides a summary of the effects of changes in volumes, prices and derivatives gains and losses on Anadarko’s sales revenues for the year ended December 31, 2008 compared to 2007 and 2006.

 

millions    Natural
Gas
    Oil and
Condensate
    NGLs  

2006 sales revenues

   $ 4,186     $ 4,618     $ 594  

Changes associated with sales volumes

     858       481       26  

Changes in prices, excluding derivatives

     (282 )     659       108  

Changes in realized derivative gains and losses

     331       (40 )     (9 )

Changes in unrealized derivative gains and losses

     (974 )     (911 )     —    
                        

2007 sales revenues

   $ 4,119     $ 4,807     $ 719  

Changes associated with sales volumes

     300       (802 )     (63 )

Changes in prices, excluding derivatives

     1,436       1,838       146  

Changes in realized derivative gains and losses

     (368 )     (514 )     —    

Changes in unrealized derivative gains and losses

     767       1,173       —    
                        

2008 sales revenues

   $ 6,254     $ 6,502     $ 802  
                        

The Company utilizes derivative instruments to manage the risk of a decrease in the market prices for its anticipated sales of natural gas, crude oil, condensate and NGLs. This activity is referred to as price risk management. The impact of price risk management (including realized and unrealized gains and losses) increased revenues $586 million in 2008, decreased revenues $472 million in 2007 and increased revenues $1,131 million in 2006. See Energy Price Risk under Part II, Item 7A and Note 8—Derivative Instruments under Part II, Item 8 of this Form 10-K.

Analysis of Oil and Gas Operations Sales Volumes

 

               D vs.          D vs.  
     2008    2007    2008     2006    2007  

Barrels of Oil Equivalent (MMBOE except percentages)

             

United States

   179    180    (1 )%   147    22 %

Algeria

   21    24    (13 )   23    4  

Other International

   6    7    (14 )   8    (13 )
                   

Total

   206    211    (2 )   178    19  
                   

Barrels of Oil Equivalent per Day (MBOE/d except percentages)

             

United States

   489    492    (1 )   404    22  

Algeria

   58    65    (11 )   64    2  

Other International

   16    20    (20 )   21    (5 )
                   

Total

   563    577    (2 )   489    18  
                   

Anadarko’s daily sales volumes increased in 2008 compared to 2007, excluding 2007 divested property volumes of 45 MBOE/d, primarily due to an increase in the United States of 38 MBOE/d related to higher sales volumes in the Rockies due to improved drilling efficiencies allowing for more overall drilling and the Gulf of Mexico. The sales volume increase in the Gulf of Mexico was realized despite prolonged repairs of third-party downstream infrastructure at the end of 2008 as a result of the 2008 hurricane activity. Volumes in Algeria decreased 7 MBOE/d primarily as a result of lower production due to maintenance, a statutory shutdown and current production constraints implemented by OPEC in the fourth quarter of 2008. During 2007, Anadarko’s daily sales volumes increased compared to 2006 primarily due to higher sales volumes of 138 MBOE/d

 

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Index to Financial Statements

associated with the full-period impact of the 2006 acquisitions and higher sales volumes in the Gulf of Mexico of 18 MBOE/d associated with production start up at Independence Hub in the second half of 2007, partially offset by a decrease in sales volumes of 64 MBOE/d associated with the impact of 2007 divestitures in the onshore United States, the Gulf of Mexico and Qatar.

Sales volumes represent actual production volumes adjusted for changes in commodity inventories. Anadarko employs marketing strategies to help manage volumes and mitigate the effect of price volatility, which is likely to continue in the future.

Natural Gas Sales Volumes, Average Prices and Revenues

 

     2008    2007     D vs.
2008
    2006    D vs.
2007
 
                (Percentages)          (Percentages)  

United States

            

Sales volumes—Bcf

     750      698     7 %     558    25 %

       MMcf/d

     2,049      1,912     7       1,529    25  

Price per Mcf, excluding derivatives

   $ 7.65    $ 5.74     33     $ 6.14    (7 )

Realized gains (losses) on derivatives

     0.19      0.73     (74 )     0.33    121  
                          
     7.84      6.47     21       6.47    —    

Unrealized gains (losses) on derivatives

     0.50      (0.57 )   188       1.03    (155 )
                          

Total

   $ 8.34    $ 5.90     41     $ 7.50    (21 )

Gas sales revenues (millions)

   $ 6,254    $ 4,119     52     $ 4,186    (2 )

The Company’s daily natural gas sales volumes increased in 2008 compared to 2007, excluding 2007 divested property volumes of 156 MMcf/d, primarily due to higher sales volumes in the Gulf of Mexico of 175 MMcf/d as a result of the start up of the Independence Hub and increased production in the Rockies of 162 MMcf/d due to improved drilling efficiencies allowing for more overall drilling, partially offset by decreased production in the Southern Region of 44 MMcf/d. Anadarko’s daily natural gas sales volumes in 2007 increased when compared to 2006. The increases were primarily due to higher sales volumes associated with the 2006 acquisitions of 491 MMcf/d and higher sales volumes of 106 MMcf/d in the Gulf of Mexico related to the start up of the Independence Hub, partially offset by decreases in sales volumes of 224 MMcf/d associated with 2007 divestitures in the onshore United States and Gulf of Mexico. Production of natural gas is generally not directly affected by seasonal swings in demand.

Excluding the impact of gains and losses on derivatives, Anadarko’s average natural gas price for 2008 increased when compared to 2007. The relative difference in 2008 and 2007 prices is primarily attributable to strong prices in the first half of 2008. The strong price in 2008 stemmed from lower year-over-year natural gas storage volumes coupled with lower liquefied natural gas volumes available to the United States consumer, both of which were caused principally by increased demand and pricing in both Europe and Asia. Excluding the impact of both realized and unrealized gains and losses on derivatives, Anadarko’s average natural gas price for 2007 decreased when compared to 2006. The lower natural gas price is attributable to a higher than average North America natural gas storage level in 2007, the full year effect in 2007 of the return of Gulf of Mexico gas production capacity in 2006 that was damaged during the 2005 hurricane season and a significant increase in liquefied natural gas supply into the United States. As of December 31, 2008, the Company has implemented price risk management on about 24% of its anticipated natural gas wellhead sales volumes for 2009.

 

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Crude Oil and Condensate Sales Volumes, Average Prices and Revenues

 

                 D vs.          D vs.  
     2008     2007     2008     2006    2007  
                 (Percentages)          (Percentages)  

United States

           

Sales volumes—MMBbls

     40       48     (17 )%     39    23 %

       MBbls/d

     108       130     (17 )     108    20  

Price per barrel, excluding derivatives

   $ 96.20     $ 66.64     44     $ 59.41    12  

Realized gains (losses) on derivatives

     (8.15 )     1.35     (704 )     2.64    (49 )
                           
     88.05       67.99     30       62.05    10  

Unrealized gains (losses) on derivatives

     8.18       (10.75 )   176       6.54    (264 )
                           

Total

   $ 96.23     $ 57.24     68     $ 68.59    (17 )

Algeria

           

Sales volumes—MMBbls

     21       24     (13 )     23    4  

       MBbls/d

     58       65     (11 )     64    2  

Price per barrel, excluding derivatives

   $ 98.99     $ 75.50     31     $ 65.55    15  

Realized gains (losses) on derivatives

     (5.86 )     —       NM       —      NM  
                           
     93.13       75.50     23       65.55    15  

Unrealized gains (losses) on derivatives

     9.14       (5.91 )   255       —      NM  
                           

Total

   $ 102.27     $ 69.59     47     $ 65.55    6  

Other International

           

Sales volumes—MMBbls

     6       7     (14 )     8    (13 )

       MBbls/d

     16       20     (20 )     21    (5 )

Total average price per barrel

   $ 85.51     $ 59.91     43     $ 48.58    23  

Total

           

Sales volumes—MMBbls

     67       79     (15 )     70    13  

       MBbls/d

     182       215     (15 )     193    11  

Total price per barrel, excluding derivatives

   $ 96.15     $ 68.68     40     $ 60.28    14  

Realized gains (losses) on derivatives

     (6.72 )     0.82     (920 )     1.48    (45 )
                           
     89.43       69.50     29       61.76    13  

Unrealized gains (losses) on derivatives

     7.78       (8.31 )   194       3.67    (326 )
                           

Total

   $ 97.21     $ 61.19     59     $ 65.43    (7 )

Total oil and condensate sales revenues (millions)

   $ 6,502     $ 4,807     35     $ 4,618    4  

 

NM—not meaningful

           

Anadarko’s daily crude oil and condensate sales volumes were lower in 2008 compared to 2007, excluding 2007 divested property volumes of 15 MBbls/d, primarily due to lower crude oil sales volumes of 13 MBbls/d in the Gulf of Mexico due to 2008 hurricane activity, lower crude oil sales volumes of 7 MBbls/d in Algeria, primarily as a result of lower production due to maintenance, a statutory shutdown and current production constraints implemented by OPEC in the fourth quarter of 2008, and lower crude oil sales volumes of 3 MBbls/d in Alaska, partially offset by higher crude oil sales volumes of 5 MBbls/d in the Rockies. Anadarko’s daily crude oil and condensate sales volumes for 2007 were up when compared to the same period of 2006. The increases in 2007 compared to 2006 were primarily due to an increase in sales volumes of 48 MBbls/d associated with the 2006 acquisitions, partially offset by a decrease in sales volumes of 20 MBbls/d associated with 2007 divestitures in the onshore United States, the Gulf of Mexico and Qatar and a decrease in Venezuelan sales volumes due to contract changes in late 2006. Production of oil usually is not affected by seasonal swings in demand.

Excluding the impact of gains and losses on derivatives, Anadarko’s average crude oil price for 2008 increased when compared to 2007. Crude oil prices were strong in the first half of 2008, primarily due to limited excess production capacity, heightened geopolitical tension and increased demand in Asia; particularly China and

 

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India. Excluding the impact of both realized and unrealized gains and losses on derivatives, Anadarko’s average crude oil price for 2007 increased when compared to 2006. The higher crude oil prices were attributed primarily to additional global demand, limited excess production capacity and heightened geopolitical tension. As of December 31, 2008, the Company has utilized price risk management on about 28% of its anticipated oil and condensate sales volumes for 2009.

Natural Gas Liquids Sales Volumes, Average Prices and Revenues

 

     2008    2007    D vs.
2008
    2006     D vs.
2007
 
               (Percentages)           (Percentages)  

United States

            

Sales volumes—MMBbls

     14      16    (13 )%     15     7 %

       MBbls/d

     39      43    (9 )     42     2  

Price per barrel, excluding derivatives

   $ 56.11    $ 45.87    22     $ 39.71     16  

Realized gains (losses) on derivatives

     —        0.03    NM       (0.13 )   NM  
                          
     56.11      45.90    22       39.58     16  

Unrealized gains (losses) on derivatives

     —        —      NM       —       NM  
                          

Total

   $ 56.11    $ 45.90    22     $ 39.58     16  

Natural gas liquids sales revenues (millions)

   $ 802    $ 719    12     $ 594     21  

NGLs sales represent revenues derived from the processing of Anadarko’s natural gas production. The Company’s daily NGLs sales volumes were down in 2008 compared to 2007 primarily due to a 4 MBbls/d decrease associated with the 2007 divestitures. Anadarko’s daily NGLs sales volumes were up in 2007 compared to 2006 primarily due to higher sales volumes of 8 MBbls/d associated with the 2006 acquisitions, partially offset by a decrease in sales volumes of 6 MBbls/d related to the 2007 divestitures.

Excluding the impact of gains and losses on derivatives, the average NGLs price increased in 2008 compared to 2007 primarily due to increased global petrochemical demand for the first three quarters of 2008. During 2007, average NGLs prices increased when compared to 2006 primarily due to increased petrochemical demand in 2007. NGLs production is dependent on natural gas and NGLs prices as well as the economics of processing the natural gas to extract NGLs. Production of NGLs usually is not affected by seasonal swings in demand.

Gathering, Processing and Marketing Revenues

 

millions except percentages    2008     2007    D vs.
2008
    2006    D vs.
2007
 

Gathering and processing sales

   $ 1,085     $ 1,259    (14 )%   $ 538    134 %

Marketing sales

     (3 )     228    (101 )     180    27  
                          

Total

   $ 1,082     $ 1,487    (27 )   $ 718    107  
                          

Gathering and processing revenues represent revenues derived from gathering and processing natural gas from sources other than the Company’s production. Marketing sales primarily represent the margin earned on sales of gas, oil and NGLs purchased from third parties. During 2008, gathering and processing sales decreased $174 million compared to 2007 primarily due to lower volumes as a result of the 2007 divestitures, partially offset by higher product prices and gathering rates. Marketing sales decreased $231 million during 2008 primarily due to lower margins on firm transportation contracts, write-down of storage inventory due to lower commodity prices in the fourth quarter of 2008 and less third-party marketing activity. During 2007, gathering and processing sales increased $721 million compared to 2006 due to gathering and processing operations acquired with the 2006 acquisitions, partially offset by a decrease associated with divestitures in 2007.

 

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Gains (Losses) on Divestitures and Other, net

Gains on divestitures in 2008 were $1.2 billion, primarily related to the divestiture of certain oil and gas properties in Brazil, onshore in the United States and the Gulf of Mexico, in several unrelated transactions. Gains on divestitures in 2007 related primarily to the Company’s asset realignment program. During 2007, net gains of $4.1 billion related to divestitures of oil and gas properties and net gains of $0.6 billion related to the divestiture of certain gathering and processing interests that were not affiliated with the Company’s operating areas. Gains on divestitures in 2006 were $26 million. For additional information, see Acquisitions and Divestitures below.

In 2008, gains (losses) on divestitures and other, net includes a net $82 million ($52 million after tax) reduction related to corrections resulting from analysis of property records after the adoption of the successful efforts method of accounting. This net amount includes a reduction of $163 million related to 2007. Management concluded that this misstatement was not material relative to 2007 interim and annual results, or to the 2008 periods, and corrected the error in the first quarter of 2008.

Costs and Expenses

 

millions except percentages    2008    2007    D vs.
2008
    2006    D vs.
2007
 

Oil and gas operating

   $ 1,104    $ 1,101    —   %   $ 822    34 %

Oil and gas transportation and other

     553      453    22       341    33  

Exploration

     1,369      905    51       737    23  

Gathering, processing and marketing

     800      1,025    (22 )     553    85  

General and administrative

     866      936    (7 )     768    22  

Depreciation, depletion and amortization

     3,194      2,840    12       1,752    62  

Other taxes

     1,452      1,234    18       549    125  

Impairments

     223      51    337       327    (84 )
                         

Total

   $ 9,561    $ 8,545    12     $ 5,849    46  
                         

During 2008, Anadarko’s costs and expenses increased when compared to 2007 due to the following factors:

  Oil and gas operating expenses were impacted by a decrease of $111 million associated with the 2007 divestitures, a decrease in demand charges of $46 million in the Gulf of Mexico and lower insurance expenses of $20 million related to Gulf of Mexico properties, offset primarily by higher operating costs of $79 million in the Rockies, higher direct operating and third-party expense of $63 million in the Gulf of Mexico and gas processing fees of $31 million in the Gulf of Mexico, primarily associated with the startup of Independence Hub in July 2007.
  Oil and gas transportation and other expenses increased primarily due to higher transportation charges in the Rockies and Southern Region, higher surface owner payments in the Rockies and due to expenses associated with the Independence Hub startup in July 2007.
  Exploration expense increased $464 million primarily due to a $337 million impairment of unproved properties in the Gulf of Mexico, a $55 million impairment of unproved properties in Trinidad, a $40 million impairment of unproved properties in Brazil, and a $34 million increase in geological and geophysical costs, primarily in Mozambique.
  Gathering, processing and marketing (GPM) expenses decreased $225 million. Costs associated with gathering and processing operations decreased $183 million primarily due to 2007 divestitures and a reduction of accrued expenses related to a prior period of $29 million, partially offset by an increase in cost of product due to higher prices and direct operating costs. Marketing transportation costs decreased $39 million.
  General and administrative (G&A) expense decreased primarily due to a $42 million decrease in employee severance and termination benefits, lower compensation expense of $39 million and a decrease of $16 million in contract labor expense, partially offset by higher benefit plans expense of $33 million.

 

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  Depreciation, depletion and amortization (DD&A) expense increased in 2008. DD&A expense associated with oil and gas properties increased approximately $416 million due to higher costs associated with acquiring, finding and developing oil and gas reserves. This increase was partially offset by a decrease of approximately $43 million due to lower sales volumes and a decrease in depreciation of other properties and equipment of $28 million primarily due to divestitures.
  Other taxes increased primarily due to increased production and severance taxes of $194 million related primarily to higher commodity prices, increases associated with the effects of a windfall profits tax in China of $55 million and increased ad valorem taxes of $43 million. This increase was partially offset by a decrease in the Algerian exceptional profits tax expense primarily attributable to a change in the estimate of the 2006 exceptional profits tax recognized in the first quarter of 2007.
  Impairments of $113 million, $98 million and $12 million in 2008 were related to Oil and Gas Exploration and Production segment properties in the United States, Midstream segment assets and Marketing segment assets, respectively. The Oil and Gas Exploration and Production segment and Midstream segment impairments were primarily a result of lower commodity prices at year-end 2008. The Marketing segment impairments related to the impairment of transportation contracts.

During 2007, Anadarko’s costs and expenses increased when compared to 2006 due to the following factors:

 

  Oil and gas operating expense increased primarily due to approximately $227 million in operating expenses on properties acquired with the 2006 acquisitions, an increase of $71 million in expenses in the deepwater Gulf of Mexico related primarily to subsurface repairs and operating costs of Independence Hub which began production in 2007, a $28 million increase in costs associated primarily with the ramp up of activity in the Rockies and an increase of approximately $20 million related to severance cost associated with the Company’s post-acquisition asset realignment program. These increases were partially offset by decreases of approximately $66 million associated with properties divested during 2007.
  Oil and gas transportation and other expenses increased in 2007. Transportation expenses increased primarily due to higher volumes transported as a result of the 2006 acquisitions, partially offset by a decrease associated with properties divested in 2007.
  Exploration expense increased $168 million due primarily to a $140 million increase in impairments of unproved properties, primarily associated with a significant increase in unproved leasehold interests as a result of the 2006 acquisitions, and a $28 million increase in dry hole expense related to international activities.
  GPM expenses increased $472 million. Costs associated with gathering and processing operations increased $389 million primarily due to facilities acquired in 2006. Marketing transportation and cost of product increased $83 million primarily due to higher volumes transported as a result of the 2006 acquisitions and the assumption of firm transportation contracts in 2006.
  G&A expense increased primarily due to increases in compensation and benefit expenses of $158 million associated primarily to rising base compensation and benefit costs for employees, higher performance-based bonus expense and an increase in the average number of employees associated with the 2006 acquisitions.
  DD&A expense increased in 2007. DD&A expense associated with oil and gas properties increased approximately $719 million as a result of operations acquired in 2006, approximately $367 million due to higher costs associated with acquiring, finding and developing oil and gas reserves and approximately $43 million due to higher organic sales volumes primarily associated with first production at Independence Hub in the Gulf of Mexico. Depreciation of other properties and equipment increased approximately $105 million primarily due to gathering, processing and general properties obtained with the 2006 acquisitions. These increases were partially offset by a decrease of approximately $149 million related to oil and gas properties divested in 2007.

 

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  Other taxes increased in 2007. Other taxes include an increase of $602 million associated with the Algerian exceptional profits tax. The remaining increase of $83 million is primarily due to the effect of higher sales volumes on production taxes, the effect of a new Alaskan severance tax, the effect of a windfall profits tax in China and higher franchise taxes.
  Impairments of $35 million and $16 million in 2007 were related to the Oil and Gas Exploration and Production segment and the Marketing segment in the United States, respectively. Impairments in 2006 include a $166 million loss associated with the termination of the Venezuela operating service agreement in exchange for an 18% equity interest in a new operating company related to the Oil and Gas Exploration and Production segment and a $139 million impairment related to the decision to suspend construction of the Company’s Bear Head LNG project in Nova Scotia for the Marketing segment.

Other (Income) Expense

 

millions except percentages    2008     2007     D vs.
2008
    2006     D vs.
2007
 

Interest Expense

          

Gross interest expense—

          

Current debt, long-term debt and other

   $ 756     $ 1,212     (38 )%   $ 730     66 %

Midstream subsidiary note payable to a related party

     109       2     5,350       —       NM  

Capitalized interest

     (123 )     (122 )   1       (80 )   53  
                            

Net interest expense

     742       1,092     (32 )     650     68  
                            

Other (Income) Expense, net

          

Interest income

     (44 )     (84 )   (48 )     (47 )   79  

Other

     95       10     850       41     (76 )
                            

Total other (income) expense, net

     51       (74 )   (169 )     (6 )   1,133  
                            

Minority Interests

     23       —       NM       —       NM  
                            

Total

   $ 816     $ 1,018     (20 )   $ 644     58  
                            

Interest Expense Anadarko’s gross interest expense for 2008 decreased compared to 2007. The decrease was primarily due to lower average debt levels in 2008 and decreases in average floating interest rates in 2008. Anadarko’s gross interest expense increased during 2007 compared to 2006. The increase was primarily due to higher average borrowings associated with the 2006 acquisitions and higher interest rates compared to 2006. For additional information see Acquisitions and Divestitures and Debt below and Interest Rate Risk under Item 7A of this Form 10-K.

The amount of capitalized interest in 2008 is comparable to capitalized interest in 2007. In 2007, capitalized interest increased compared to 2006. This increase was primarily due to increased costs for major projects.

Other (Income) Expense For 2008, the Company had total other expense of $51 million compared to total other income of $74 million for 2007. The decrease of $125 million was primarily related to lower interest income of $40 million due to lower average cash levels and lower interest rates in 2008, a $40 million loss related to environmental reserve adjustments and $54 million of impairment losses related to equity investments.

For 2007, the Company had total other income of $74 million compared to $6 million for 2006. The increase of $68 million was primarily due to higher interest income of $37 million, a $22 million loss on an impaired equity investment in 2006 and a $10 million loss related to environmental reserve adjustments in 2006.

 

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Minority Interests For 2008, the Company had minority interests expense of $23 million primarily related to the public ownership of a 36.7% limited partnership interest in WES which completed its initial public offering in the second quarter of 2008. See Master Limited Partnership Initial Public Offering below.

Income Tax Expense

 

millions except percentages    2008     2007     2006  

Income tax expense

   $ 2,148     $ 2,559     $ 1,263  

Effective tax rate

     40 %     40 %     34 %

For 2008, income tax expense related to continuing operations decreased 16% compared to 2007 primarily due to a decrease in income before income taxes. For 2007, income tax expense related to continuing operations increased 103% compared to 2006 primarily due to an increase in income before income taxes and variances from the statutory rate.

The variance from the 35% statutory rate in 2008 is primarily attributable to the accrual of the Algerian exceptional profits tax, which is non-deductible for Algerian income tax purposes, U.S. tax on foreign inclusions and distributions, state income taxes and other items. This increase in the 35% statutory rate is offset by a foreign tax rate applicable to the Company's divestiture of its 50% interest in the Peregrino field offshore Brazil, which is a rate lower than the 35% U.S. statutory rate, and other items. The variance from the 35% statutory rate in 2007 was primarily caused by the Algerian exceptional profits tax, which is non-deductible for Algerian income tax purposes, other foreign taxes in excess of federal statutory rates, state income taxes and other items. For 2006, the variance from the 35% statutory rate was primarily caused by foreign taxes in excess of federal statutory rates, state income taxes, excess U.S. foreign tax credits and other items.

Texas House Bill 3, signed into law in May 2006, eliminates the taxable capital and earned surplus components of the existing franchise tax and replaces these components with a taxable margin tax calculated on a combined basis. The new tax is effective for reports due on or after January 1, 2008 (based on business activity during 2007). Anadarko is required to include the impact of the law change on its deferred state income taxes in income for the period which includes the date of enactment. The adjustment, a reduction in Anadarko’s deferred state income taxes in the amount of approximately $14 million and $69 million, net of federal benefit, was included in the 2007 and 2006 tax provision, respectively.

Operating Results

Segment Analysis—Adjusted EBITDAX To assess the operating results of Anadarko’s segments, management uses income from continuing operations before income taxes, interest expense, exploration expense, DD&A expense and impairments (Adjusted EBITDAX). Anadarko’s definition of Adjusted EBITDAX, which is not a GAAP measure, excludes exploration expense, as exploration expense is not an indicator of operating efficiency for a given reporting period, but is monitored by management as part of costs incurred in exploration and development activities. Similarly, DD&A expense and impairments are excluded from Adjusted EBITDAX as a measure of segment operating performance, because capital expenditures are evaluated at the time capital costs are incurred. The Company’s definition of Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Anadarko’s financing methods or capital structure. Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make distributions to shareholders.

Adjusted EBITDAX, as defined by Anadarko, may not be comparable to similarly titled measures used by other companies. Therefore, Anadarko’s consolidated Adjusted EBITDAX should be considered in conjunction with income from continuing operations and other performance measures prepared in accordance with GAAP, such as operating income or cash flow from operating activities. Adjusted EBITDAX has important limitations as an analytical tool because it excludes certain items that affect income from continuing operations and net cash

 

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provided by operating activities. Adjusted EBITDAX should not be considered in isolation or as a substitute for an analysis of Anadarko’s results as reported under GAAP. Below is a reconciliation of consolidated Adjusted EBITDAX to income from continuing operations before income taxes.

Adjusted EBITDAX

 

millions except percentages    2008     2007     D vs.
2008
    2006     D vs.
2007
 

Income from continuing operations before income taxes

   $ 5,346     $ 6,329     (16 )%   $ 3,737     69 %

Exploration expense

     1,369       905     51       737     23  

Depreciation, depletion and amortization expense

     3,194       2,840     12       1,752     62  

Impairments

     223       51     337       327     (84 )

Interest expense

     742       1,092     (32 )     650     68  
                            

Consolidated Adjusted EBITDAX

   $ 10,874     $ 11,217     (3 )   $ 7,203     56  
                            

Adjusted EBITDAX by segment—

          

Oil and gas exploration and production

   $ 10,917     $ 10,637     3     $ 7,350     45  

Midstream

     428       894     (52 )     183     389  

Marketing

     39       234     (83 )     78     200  

Other and intersegment eliminations

     (510 )     (548 )   7       (408 )   (34 )

Oil and Gas Exploration and Production The increase in Adjusted EBITDAX for 2008 compared to 2007 was primarily due to the impact of higher commodity prices and higher sales volumes primarily in the Rockies and the Gulf of Mexico, partially offset by a decrease in gains on divestitures and other, net of $3.1 billion and lower sales volumes as a result of the 2007 divestitures. The increase in Adjusted EBITDAX for 2007 compared to 2006 was primarily due to an increase in gains on divestitures of $4.1 billion and higher sales volumes, partially offset by the impact of lower natural gas and oil and condensate prices and higher costs and expenses, including the Algerian exceptional profits tax. The Company’s sales revenues include the impact of price risk management activities (including realized and unrealized gains and losses) which increased oil and gas revenues $586 million during 2008, compared to a decrease of $472 million in 2007 and an increase of $1,131 million in 2006. Of these amounts for 2008, 2007, and 2006 $892 million, $(1,048) million, and $837 million, respectively, were related to the recognition of net unrealized gains (losses) on derivatives used to manage price risk on natural gas, crude oil, condensate and NGLs sales.

Midstream The decrease in Adjusted EBITDAX for 2008 compared to 2007 resulted primarily from a decrease in gains on divestitures and other, net of $531 million and lower volumes as a result of the 2007 divestitures, partially offset by higher product prices and gathering rates. The increase in Adjusted EBITDAX for 2007 compared to 2006 resulted primarily from an increase in gains on divestitures of $532 million related to midstream assets and an increased scope of midstream operations resulting from the 2006 acquisitions, partially offset by a decrease in earnings associated with the 2007 divestitures. During July 2007, the Company divested its interests in two natural gas gathering systems and associated processing plants that did not operate in areas where Anadarko has significant oil and gas production. These divested facilities accounted for $75 million, or 21%, of Anadarko’s midstream segment’s Adjusted EBITDAX excluding gains on divestitures during 2007.

Marketing Marketing earnings primarily represent the margin earned on sales of gas, oil and NGLs purchased from third parties. The decrease in Adjusted EBITDAX for 2008 compared to 2007 was primarily due to lower margins on firm transportation contracts and the write-down of storage inventory due to lower commodity prices in the fourth quarter of 2008. The increase in Adjusted EBITDAX for 2007 compared to 2006, resulted primarily from the effects of higher volumes transported as a result of the 2006 acquisitions.

Other and Intersegment Eliminations Other and intersegment eliminations consists primarily of corporate costs that are not allocated to the operating segments and income from hard minerals investments and royalties. The increase in Adjusted EBITDAX for 2008 compared to 2007 was primarily due to a decrease in employee

 

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severance and termination benefits, a decrease in compensation expense, and a decrease in contract labor expense, partially offset by higher benefit plans expense and impairment losses related to equity investments. The decrease in Adjusted EBITDAX for 2007 compared to 2006 was primarily due to increases in compensation expense from the increased average number of employees associated with the 2006 acquisitions.

Acquisitions and Divestitures

Acquisitions In August 2006, Anadarko acquired Kerr-McGee and Western in separate all-cash transactions. Anadarko initially financed $22.5 billion for the acquisitions through a 364-day committed acquisition facility with plans to repay it with proceeds from asset divestitures, free cash flow from operations and the issuance of equity, debt and bank financing during the term of the facility. Through February 29, 2008, the Company had repaid the initial amount financed under the acquisition facility of $22.5 billion using divestiture proceeds, long-term refinancing and cash flow from operations.

Kerr-McGee Transaction On August 10, 2006, Anadarko completed the acquisition of Kerr-McGee for $16.5 billion, or $70.50 per share, plus the assumption of $2.6 billion of debt.

Kerr-McGee’s legacy core properties are located in the deepwater Gulf of Mexico and onshore in Colorado and Utah. They include deepwater Gulf of Mexico blocks which are supported by Kerr-McGee’s “hub-and-spoke” infrastructure. In Colorado, Kerr-McGee held acreage in the Wattenberg natural gas play, located largely on Anadarko’s Land Grant holdings, where Anadarko owns the royalty interest. In Utah, Kerr-McGee held acreage in the Uinta basin’s prolific Greater Natural Buttes gas play. In addition to its U.S. portfolio, Kerr-McGee produces oil and is continuing to develop and explore offshore China, has made discoveries offshore Brazil, and is exploring West Africa and the islands of Trinidad and Tobago.

Western Transaction On August 23, 2006, Anadarko completed the acquisition of Western for $4.8 billion, or $61.00 per share, plus the assumption of $625 million of debt.

Western’s CBM properties within the Powder River basin are directly adjacent to Anadarko’s assets in this developing play. Anadarko believes that combining its properties with Western’s accelerated the development of these natural gas resources and will produce volume growth through the end of the decade, and possibly longer, with more than 12,000 identified drilling locations in inventory. The acquisition of Western also significantly increased the Company’s holdings in gathering and processing systems.

Divestitures As a result of a portfolio refocusing effort stemming from the acquisitions of Kerr-McGee and Western, Anadarko divested certain properties during 2007 and 2006 for approximately $17 billion before income taxes. Net proceeds from these divestitures were used to retire debt.

During 2006, Anadarko sold its wholly-owned subsidiary, Anadarko Canada Corporation, for approximately $4 billion before taxes. See Discontinued Operations. On the acquisition date, Kerr-McGee’s other assets included approximately $1 billion of assets held for sale. The sale of these assets closed in August 2006 and the proceeds were also used to pay down debt incurred to fund the acquisitions.

During 2007, the Company closed several unrelated divestiture transactions representing approximately $11 billion before income taxes. The most significant of these transactions are discussed below.

In January 2007, the Company sold its interests in the Knotty Head and Big Foot oil discoveries, as well as the Big Foot North prospect in the Gulf of Mexico, for $0.9 billion. During February 2007, Anadarko also closed the sale of its Genghis Khan discovery in the deepwater Gulf of Mexico for $1.3 billion. In March 2007, Anadarko divested control of its interests in 28 Permian basin oil and gas fields in West Texas for $1.0 billion (see Off-Balance Sheet Arrangements), sold its Vernon and Ansley fields located in Jackson Parish, Louisiana, for $1.5 billion and sold substantially all of its interests in the Elk basin and Gooseberry area of the Northern Rockies for $0.4 billion.

In April 2007, Anadarko sold its interests in the Williston basin area of the Northern Rockies for $0.4 billion. In May 2007, Anadarko sold its interests in certain natural gas properties in Oklahoma and Texas for $0.9 billion and also sold a 23% working interest in the K2 Unit in the Gulf of Mexico for $1.2 billion. Anadarko remains the K2 Unit operator with a 42% working interest. In June 2007, Anadarko sold certain of its interests in the Austin Chalk play in central and east Texas for $0.8 billion.

 

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In July 2007, the Company divested control of its interests in the Chaney Dell and Midkiff/Benedum natural gas gathering systems and associated processing plants for $1.9 billion (see Off-Balance Sheet Arrangements below).

In October 2007, the Company divested certain interests in Qatar for approximately $350 million.

In 2008, the Company divested certain oil and gas properties, primarily in Brazil, onshore in the United States and the Gulf of Mexico for approximately $2.5 billion. Proceeds from divestitures in 2008 were used to reduce debt.

In April 2008, Anadarko entered into an agreement to sell a wholly-owned subsidiary, which owns an 18% interest in Petroritupano, S.A. (Petroritupano), a Venezuelan mixed company whose other shareholders are Petróleos de Venezuela, S.A. (PDVSA) and Petrobras Energía, S.A., for $200 million. The closing of this transaction was subject to customary closing conditions, including receipt of approvals by Venezuelan authorities. Anadarko has been informed by the Venezuelan Ministry of Energy and Petroleum that it will not grant approval of the sale transaction because PDVSA intends to acquire Anadarko’s equity interest in Petroritupano. Anadarko has subsequently received a letter from Corporacion Venezolana del Petroleo, S.A. (CVP), an affiliate of PDVSA, in which CVP states its interest in acquiring Anadarko’s equity interest in Petroritupano. At this time, Anadarko is unable to determine when the sale to CVP may be consummated. Anadarko’s investment in Petroritupano is included in other assets at December 31, 2008.

For additional information, see Note 2—Acquisitions, Divestitures and Other under Item 8 of this Form 10-K.

Proved Reserves Anadarko focuses on growth and profitability. Reserve replacement is a key to growth. Future profitability depends partially upon the cost of finding and developing oil and gas reserves, among other factors. Reserve growth can be achieved through successful exploration and development drilling, improved recovery or acquisition of producing properties.

In conjunction with the August 2006 acquisition of Kerr-McGee and Western, Anadarko implemented an asset realignment program. The goal of the Kerr-McGee and Western acquisitions was to provide a more economically efficient platform with higher and more consistent growth potential, with the intent of divesting properties that were no longer deemed to be core to Anadarko’s operations. During 2007, the Company successfully completed the majority of the divestiture stage of the realignment program. As expected, Anadarko’s proved reserves at the end of 2007 were about equal to levels before the acquisitions.

The following discussion of proved reserves, reserve additions and revisions and future net cash flows from proved reserves includes both continuing and discontinued operations. A breakdown of reserve information by continuing and discontinued operations is contained in the Supplemental Information under Item 8 of this Form 10-K.

 

MMBOE    2008     2007     2006  

Proved Reserves

      

Beginning of year

   2,431     3,011     2,449  

Reserve additions and revisions

   188     252     1,043  

Sales in place

   (137 )   (620 )   (287 )

Production

   (205 )   (212 )   (194 )
                  

End of year

   2,277     2,431     3,011  
                  

Proved Developed Reserves

      

Beginning of year

   1,625     1,989     1,524  
                  

End of year

   1,600     1,625     1,989  
                  

The Company’s proved natural gas reserves at year-end 2008 were 8.1 Tcf compared to 8.5 Tcf at year-end 2007 and 10.5 Tcf at year-end 2006. Anadarko’s proved crude oil, condensate and NGLs reserves at year-end 2008 were 0.9 billion barrels compared to 1.0 billion barrels at year-end 2007 and 1.3 billion barrels at year-end 2006. Crude oil, condensate and NGLs comprised about 41%, 42% and 42% of the Company’s proved reserves at year-end 2008, 2007 and 2006 respectively.

 

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The Company’s estimates of proved reserves are made using available geological and reservoir data as well as production performance data. These estimates, made by the Company’s engineers, are reviewed annually and revised, either upward or downward, as warranted by additional data. The available data reviewed include, among other things, seismic data, structure and isopach maps, well logs, production tests, material balance calculations, reservoir simulation models, reservoir pressures, individual well and field performance data, individual well and field projections, offset performance data, operating expenses, capital costs and product prices. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions, as well as changes in the expected recovery rates associated with infill drilling. Sustained decreases in prices, for example, may cause a reduction in some proved reserves due to reaching economic limits sooner.

Reserve Additions and Revisions During 2008, the Company added 188 MMBOE of proved reserves as a result of additions (purchases in place, discoveries, improved recovery and extensions) and revisions. The Company expects the majority of future reserve adds to come from positive revisions associated with infill drilling and extensions of current fields and new discoveries onshore in North America and the deepwaters of the Gulf of Mexico, as well as through improved recovery operations, purchases of proved properties in strategic areas and successful exploration in international growth areas. The success of these operations will directly impact reserve additions or revisions in the future.

Additions During 2008, Anadarko added 102 MMBOE of proved reserves primarily as the result of successful drilling in the Rockies and developments and appraisals in the deepwater Gulf of Mexico. During 2007, Anadarko added 131 MMBOE of proved reserves. Of this amount, 130 MMBOE were as a result of successful drilling in CBM and conventional plays of the Rockies and the initial recognition of proved reserves at the Peregrino field in Brazil. During 2006, Anadarko added 1,118 MMBOE of proved reserves. Of this amount, 1,030 MMBOE were related to purchases in place primarily associated with the acquisitions of Kerr-McGee and Western in August 2006. In addition, the Company added 88 MMBOE of proved reserves primarily as a result of successful drilling in core areas onshore in the United States.

Revisions Total revisions in 2008 were 86 MMBOE or 3.5% of the beginning of year reserve base. The revisions included an increase of 188 MMBOE primarily related to the large onshore natural gas plays, such as the Greater Natural Buttes, Wattenberg and Pinedale fields, as a result of successful infill drilling, in addition to positive revisions to the Peregrino heavy-oil field, offshore Brazil, which was sold in 2008, partially offset by a decrease of 102 MMBOE related to prices for oil and NGLs. Total revisions for 2007 were 121 MMBOE. Revisions in 2007 related primarily to the large onshore natural gas plays such as Greater Natural Buttes, Wattenberg, and Pinedale and Jonah fields, where the reserve bookings for the infill wells are treated as a positive revision, and the increase in oil and natural gas prices. Total revisions for 2006 were (75) MMBOE. Revisions in 2006 related primarily to performance revisions of (136) MMBOE mainly due to downward revisions of the Company’s reserves at the K2 complex in the Gulf of Mexico and adjustments in Algeria, and price revisions of (99) MMBOE primarily due to a significant decrease in natural gas prices since the end of 2005, partially offset by additional infill drilling reserve bookings of 160 MMBOE.

Sales in Place During 2008, the Company sold properties located in the United States and Brazil representing 46 MMBOE and 91 MMBOE of proved reserves, respectively. In 2007, the Company sold properties located in the United States and Qatar representing 609 MMBOE and 11 MMBOE of proved reserves, respectively. In 2006, the Company sold properties located in Canada representing 248 MMBOE of proved reserves. In addition, sales in place included 39 MMBOE of proved reserves related to government imposed contract changes which resulted in the Company’s Venezuelan properties being exchanged for an equity interest in a new Venezuela operating entity.

Future Net Cash Flows At December 31, 2008, the present value (discounted at 10%) of future net cash flows from Anadarko’s proved reserves was $12.0 billion (stated in accordance with the regulations of the SEC and the Financial Accounting Standards Board (FASB)). This present value was calculated based on prices at year-end

 

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held flat for the life of the reserves, adjusted for any contractual provisions. The decrease of $16.9 billion or 59% in 2008 compared to 2007 is primarily due to lower commodity prices at year-end 2008. See Supplemental Information under Item 8 of this Form 10-K.

The present value of future net cash flows does not purport to be an estimate of the fair market value of Anadarko’s proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil and gas.

Midstream Strategies

Anadarko invests in midstream (gathering, treating and processing) facilities to complement its oil and gas operations in regions where the Company has natural gas production. The Company is better able to control the timing of development of its oil and gas properties and manage both the value received for, and cost of, gathering, treating and processing natural gas through its ownership and operation of these facilities. In addition, Anadarko’s midstream business provides gathering, treating and processing services for third-party customers, including major and independent producers. Anadarko generates revenues in its gathering and processing activities through various fee structures that include fixed-rate, percent of proceeds, or keep-whole agreements. The Company also processes a portion of its gas at various third-party plants.

In 2006, Anadarko significantly increased the size and scope of its midstream business through the acquisitions of Western and Kerr-McGee. Anadarko has 29 systems in seven states (Wyoming, Colorado, Utah, New Mexico, Kansas, Oklahoma and Texas) located in major producing basins of the onshore United States.

In December 2007, a midstream subsidiary issued a $2.2 billion note payable to a related party. At December 31, 2008, the midstream note payable to a related party had an outstanding balance of $1.7 billion, which is guaranteed by Anadarko. See Note 10—Debt and Interest Expense of the Notes to Consolidated Financial Statements under Item 8 and Debt below for additional information.

During the second quarter of 2008, WES completed its initial public offering of 20.8 million common units for net proceeds of $321 million ($343 million less $22 million for underwriting discounts and structuring fees). WES is a Delaware limited partnership formed by Anadarko to own, operate, acquire and develop midstream assets. Anadarko contributed assets to WES in exchange for an aggregate 59.6% limited partner interest (consisting of common and subordinated limited partner units) in WES, a 2% general partner interest and IDRs. IDRs entitle the holder to specified increasing percentages of cash distributions as WES’s per-unit cash distributions increase. In addition, Anadarko maintains control over the assets owned by WES through sole indirect ownership of the general partner interests. Proceeds from the initial public offering were used to reduce debt.

On December 19, 2008, WES acquired additional midstream assets from Anadarko for aggregate consideration of $210 million, consisting of a $175 million note payable to Anadarko and the issuance of 2.6 million common units of WES to Anadarko. In addition, WES issued additional general partner units to its general partner, a wholly-owned subsidiary of Anadarko, to allow it to maintain its 2% general partner interest in WES after contribution by Anadarko of its 2% undivided interest in the midstream assets. Anadarko currently holds an aggregate 61.3% limited partner interest in WES.

Marketing Strategies

The Company’s marketing department actively manages sales of its natural gas, crude oil and NGLs. The Company’s sales of natural gas, crude oil, condensate and NGLs are generally made at the market prices of those products at the time of sale. In 2008, the Company also engaged in sales of greenhouse gas ERCs derived from CO2 injection operations in Wyoming. The Company expects additional sales of ERCs in the future.

The Company also purchases natural gas, crude oil, condensate and NGLs volumes for resale primarily from partners and producers near Anadarko’s production. These purchases allow Anadarko to aggregate larger volumes, fully utilize transportation capacity, attract larger, creditworthy customers and facilitate its efforts to maximize prices received for the Company’s production and minimize balancing issues with customers and pipelines during operational disruptions.

 

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The Company may also engage in trading activities for the purpose of generating profits from exposure to changes in market prices of natural gas, crude oil, condensate and NGLs. The Company does not engage in market-making practices and limits its trading activities to natural gas, crude oil and NGLs commodity contracts. The Company’s trading risk position, typically, is a net short position that is offset by the Company’s natural long position as a producer. See Energy Price Risk under Item 7A of this Form 10-K.

In an effort to protect the Company from commodity price risk stemming from the 2006 acquisitions, the Company entered into derivatives covering 72% and 55% of the acquired companies’ then expected production volumes for 2007 and 2008, respectively. This price risk management program employed collars and other derivatives intended to help ensure a return on investment while maintaining upside potential that could result from higher commodity prices. In the past year, almost all segments of the global economy have experienced a downturn. This downturn, along with the commodity price volatility, have made the creditworthiness, liquidity and financial position of the Company’s counterparties increasingly difficult to evaluate. For this reason, the Company has placed an increased emphasis on the monitoring of counterparty risk. Although Anadarko has not experienced any material financial losses associated with credit deterioration of third parties, in certain situations the Company has declined to transact with some counterparties and changed its sales terms to require some counterparties to pay in advance or post letters of credit for purchases.

Natural Gas Natural gas continues to fulfill a significant portion of North America’s energy needs and the Company believes the importance of natural gas in meeting this energy need will continue. Natural gas prices have varied over the last year, with the first three quarters of the year averaging higher than corresponding quarters in 2007 and a year-on-year decrease in the last quarter of 2008. Price volatility persists due to an increase in supply stemming principally from unconventional gas coupled with a decrease in domestic industrial demand. Anadarko markets its natural gas production to maximize the commodity value and reduce the inherent risks of the physical commodity markets. Anadarko Energy Services Company, a wholly-owned subsidiary of Anadarko, is a marketing company offering supply assurance, competitive pricing, risk management and other services tailored to its customers’ needs. The Company sells natural gas under a variety of contracts and may also receive a service fee related to the level of reliability and service required by the customer. The Company has the marketing capability to move large volumes of gas into and out of the “daily” gas market to take advantage of any price volatility.

The Company owns a significant amount of natural gas firm transportation capacity that is used to help ensure access to downstream markets which increases the ability to produce the Company’s natural gas. This transportation capacity also provides the opportunity to capture incremental value when pricing differentials between physical locations occur. The Company also stores some of its purchased natural gas in contracted storage facilities with the intent of selling the gas at a higher price in the future. Normally, the Company will have forward contracts in place (physical delivery or financial derivative instruments) to sell the stored gas at a fixed price. The Company also utilizes these storage facilities to minimize operational disruptions to its ongoing operations.

Crude Oil, Condensate and NGLs Anadarko’s crude oil, condensate and NGLs revenues are derived from production in the United States (U.S.), Algeria, China and other international areas. Most of the Company’s U.S. crude oil and NGLs production is sold under contracts with prices based on market indices, adjusted for location, quality and transportation. Oil from Algeria is sold by tanker as Saharan Blend to customers primarily in the Mediterranean area. Saharan Blend is a high quality crude that provides refiners large quantities of premium products such as jet and diesel fuel. Oil from China is sold by tanker as Cao Fei Dian (CFD Blend) to customers primarily in the Far East markets. CFD Blend is a heavy sour crude oil which is sold into both the prime fuels refining market and the heavy fuel oil blend stock market. The Company also purchases and sells third-party produced crude oil, condensate and NGLs in the Company’s domestic and international market areas. Included in this strategy is the use of contracted NGLs storage facilities. The Company utilizes this storage to capture market opportunities and to help minimize fractionation and downstream infrastructure disruptions.

 

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Liquidity and Capital Resources

Overview Anadarko’s primary sources of cash during 2008 were cash flow from operating activities, proceeds from divestitures and the initial public offering of WES. The Company used cash primarily to fund Anadarko’s capital spending program, retire debt, pay income taxes, repurchase Anadarko common stock, pay dividends and redeem preferred stock. Anadarko’s primary sources of cash during 2007 were divestiture transactions, cash flow from operating activities and proceeds from the midstream subsidiary note to a related party. The Company used cash primarily to retire debt, fund Anadarko’s capital spending program and pay income taxes and dividends. Anadarko’s primary sources of cash during 2006 were the issuance of debt, cash flow from operating activities and divestitures. During 2006, the Company used cash primarily to fund the acquisitions of Kerr-McGee and Western, fund its capital spending program, repurchase Anadarko common stock, pay dividends and retire debt as well as preferred stock.

The downturn in the global economy, along with the turmoil in the financial markets and reduced availability to capital, have increased the importance of maintaining ample liquidity. The pace with which the downturn has occurred made the evaluation of the Company’s lenders creditworthiness, liquidity and financial position increasingly difficult. For this reason, the Company has increased its diligence in monitoring its lenders’ funding capabilities. The Company has in place a $1.3 billion RCA and as of December 31, 2008, the Company had no outstanding borrowings under its RCA. The Company may choose to refinance certain portions of its short-term borrowings by issuing long-term debt in the public or private debt markets. To facilitate such financings, the Company may sell securities under its shelf registration statement filed with the SEC in September 2006.

The Company continuously monitors its debt position and coordinates its capital expenditure program with expected cash flows and projected debt repayment schedules. The Company will continue to evaluate funding alternatives, including property divestitures and additional borrowings, to secure funds when needed.

Following is a discussion of significant sources and uses of cash flows during the period. Forward-looking information related to the Company’s liquidity and capital resources are discussed in Outlook that follows.

Sources of Cash

Cash Flow from Operating Activities Anadarko’s cash flow from continuing operating activities in 2008 was $6.4 billion compared to $2.8 billion in 2007 and $4.7 billion in 2006. The increase in 2008 cash flow was attributed to higher commodity prices and lower estimated income tax payments in 2008 compared to 2007 primarily related to the 2007 divestitures, partially offset by the effect of lower sales volumes primarily associated with the 2007 divestitures, and realized derivative losses in 2008. The decrease in 2007 cash flow from continuing operations compared to 2006 was attributed to the impact of income taxes on divestitures and higher costs and expenses, partially offset by the impact of higher sales volumes associated with the acquisitions.

Excluding the impact of acquisitions and divestitures, fluctuations in commodity prices have been the primary reason for the Company’s short-term changes in cash flow from operating activities. Anadarko holds derivative instruments to help manage commodity price risk. Sales volume changes can also impact cash flow in the short-term, but have not been as volatile as commodity prices in prior years. Anadarko’s long-term cash flow from operating activities is dependent on commodity prices, reserve replacement, the level of costs and expenses required for continued operations and the level of acquisition and divestiture activity.

Divestitures In 2008, Anadarko received proceeds of $2.5 billion from divestitures of certain oil and gas properties primarily in Brazil, onshore in the United States and the Gulf of Mexico. Proceeds from divestitures in 2008 were used to reduce debt. During 2007, Anadarko received proceeds of $11.1 billion from its divestiture program. Proceeds from the divestitures in 2007 were used to reduce debt and pay income taxes on taxable gains associated with the divestitures. See Acquisitions and Divestitures.

 

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Master Limited Partnership Initial Public Offering During the second quarter of 2008, WES completed its initial public offering of 20.8 million common units for net proceeds of $321 million. WES is a Delaware limited partnership formed by Anadarko to own, operate, acquire and develop midstream assets. See Note 3-Minority Interests under Part II, Item 8 of this Form 10-K. Proceeds from the offering were used to reduce debt.

Pursuant to the terms of its partnership agreement, WES is required to pay a minimum quarterly distribution of $0.30 per unit to the extent it has sufficient cash available for distribution. During the third quarter of 2008, WES paid a prorated quarterly cash distribution of $0.1582 per unit for the second quarter of 2008, which corresponds to a quarterly distribution of $0.30 per unit on a full quarter basis. In the fourth quarter of 2008, WES paid a quarterly cash distribution of $0.30 per unit for the third quarter of 2008. On January 28, 2009, WES declared a quarterly cash distribution of $0.30 per unit for the fourth quarter of 2008 to be paid on February 13, 2009.

On December 19, 2008, WES acquired additional midstream assets from Anadarko for aggregate consideration of $210 million, consisting of a $175 million note payable to Anadarko and the issuance of 2.6 million common units of WES to Anadarko. In addition, WES issued additional general partner units to its general partner, a wholly-owned subsidiary of Anadarko, to allow it to maintain its 2% general partner interest in WES after contribution by Anadarko of its 2% undivided interest in the midstream assets. Anadarko currently holds an aggregate 61.3% limited partner interest in WES.

Margin Deposits The Company is required to provide margin deposits whenever its unrealized losses on derivative transactions with a counterparty exceed predetermined credit limits, and in some cases only until negotiated maximum limits are reached. Both exchange and over-the-counter traded derivative instruments may be subject to margin deposit requirements. Given the Company’s price risk management position and price volatility, the Company may be required from time to time to deposit cash with or provide letters of credit to its counterparties in order to satisfy these deposit requirements. The Company manages its exposure to margin requirements through negotiated credit arrangements with counterparties, which may include collateral caps. If credit thresholds are exceeded, the Company utilizes available cash or letters of credit to satisfy margin requirements and maintains ample available committed credit facilities to meet its obligations. The Company’s current derivative positions continue to ratably settle such that the Company’s working capital along with its RCA could withstand margin calls resulting from a significant increase in commodity prices. The Company had net margin deposits (cash collateral) of $7 million and $51 million outstanding at December 31, 2008 and 2007, respectively. See Note 1—Summary of Significant Accounting Policies and Note 8—Derivative Instruments of the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

 

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Uses of Cash

Capital Expenditures The following table shows the Company’s capital expenditures relating to continuing operations by category.

 

millions    2008     2007     2006  

Property acquisitions

      

Exploration—unproved

   $ 405     $ (293 )   $ 13,372  

Development—proved

     26       (591 )     14,496  

Exploration

     1,031       834       806  

Development

     3,530       2,805       3,084  
                        

Total oil and gas costs incurred*

     4,992       2,755       31,758  

Less: Corporate acquisitions and non-cash property exchanges

     (106 )     1,001       (27,491 )

Less: Asset retirement costs

     (263 )     (194 )     (158 )

Less: Geological and geophysical, exploration overhead and delay rentals expenses and other

     (344 )     (261 )     (254 )

Less: Amortization of acquired drilling rig contract intangibles

     (5 )     (86 )     —    
                        

Total oil and gas capital expenditures

     4,274       3,215       3,855  

Gathering, processing and marketing and other

     607       775       357  
                        

Total capital expenditures*

   $ 4,881     $ 3,990     $ 4,212  
                        

 

* Oil and gas costs incurred represent costs related to finding and developing oil and gas reserves. Capital expenditures represent additions to property and equipment excluding corporate acquisitions, property exchanges and asset retirement costs. Capital expenditures and cost incurred are presented on an accrual basis. Additions to properties and equipment on the consolidated statement of cash flows include certain adjustments that give effect for the timing of actual cash payments in order to represent a cash basis.

Anadarko’s capital expenditures increased 22% in 2008 compared to 2007. The Company’s capital spending decreased 5% in 2007 compared to 2006. The 2008 increase was due to an increase in development drilling expenditures primarily onshore in the U.S. and exploration lease acquisition activity primarily offshore in the U.S., partially offset by a decrease in expenditures related to construction, and gathering and processing facilities. The decrease in 2007 resulted primarily from a decrease in development drilling and construction expenditures and a decrease in exploration lease acquisition activity, partially offset by an increase in capital expenditures on gathering and processing facilities. Additionally, all of the periods were impacted by rising service and material costs. The variances in the mix of oil and gas spending reflect the Company’s available opportunities based on the near-term ranking of projects by net asset value potential.

The property acquisitions in 2008 primarily related to exploratory nonproducing leases. Proved property acquisitions and unproved property acquisitions in 2007 include adjustments of $(600) million and $(484) million, respectively, related to finalizing the allocation of fair value to oil and gas properties acquired from Kerr-McGee and Western in 2006. The property acquisitions in 2006 related primarily to Kerr-McGee and Western.

Anadarko participated in a total of 2,838 gross wells in 2008 compared to 1,823 gross wells in 2007 and 1,537 gross wells in 2006.

 

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See Outlook below for information regarding sources of cash used to fund capital expenditures for 2009.

The following table provides additional detail of the Company’s drilling activity in 2008, 2007 and 2006.

 

     Gas    Oil    Dry    Total

2008 Exploratory

           

Gross

   13    3    12    28

Net

   9.8    2.3    6.2    18.3

2008 Development

           

Gross

   2,632    166    12    2,810

Net

   1,443.7    127.3    8.4    1,579.4

2007 Exploratory

           

Gross

   33    1    21    55

Net

   18.1    0.3    8.0    26.4

2007 Development

           

Gross

   1,727    34    7    1,768

Net

   894.7    12.0    2.4    909.1

2006 Exploratory

           

Gross

   56    7    13    76

Net

   34.6    3.6    5.7    43.9

2006 Development

           

Gross

   1,183    272    6    1,461

Net

   631.6    205.6    2.2    839.4

 

Gross: total wells in which there was participation.

Net: working interest ownership.

The Company’s 2008 exploration and development drilling program is discussed in Oil and Gas Properties and Activities under Item 1 of this Form 10-K.

Debt At year-end 2008, Anadarko’s total debt was $12.3 billion compared to total debt of $14.7 billion at year-end 2007 and $23.0 billion at year-end 2006. As of December 31, 2007, current debt included $1 billion under a variable-rate 354-day facility. This facility was fully repaid and concurrently retired in February 2008. Also in 2008, the Company retired $580 million aggregate principal amount of Floating Rate Notes due September 2009. In 2008 the Company repaid an aggregate principal amount of $2.4 billion of debt (including the variable-rate 354-day facility) that was outstanding at December 31, 2007.

In March 2008, the Company entered into a $1.3 billion, five-year RCA with a syndicate of United States and foreign lenders. Under the terms of the RCA, the Company can, under certain conditions, request an increase in the borrowing capacity under the RCA up to a total available credit amount of $2.0 billion. The RCA has a maximum 65% debt to total book capitalization covenant (excluding non-cash charges). The RCA terminates in March 2013. The RCA replaced a $750 million revolving credit facility which was scheduled to mature in 2009 and was retired. As of December 31, 2008, the Company had no outstanding borrowings under the RCA. Anadarko was in compliance with existing covenants and the full amount of the RCA was available for borrowing at December 31, 2008.

The Company plans to repay current debt of $1.5 billion outstanding at December 31, 2008 with cash on hand, cash flow from operations and, if necessary, funds available under the $1.3 billion RCA or debt refinancing.

 

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The following table shows the Company’s debt-to-capital ratio.

 

     December 31,     December 31,  
millions except percentages    2008     2007  

Current debt

   $ 1,472     $ 1,396  

Long-term debt

     9,128       11,151  
                

Total debt excluding related party debt

     10,600       12,547  
                

Midstream subsidiary note payable to a related party

     1,739       2,200  
                

Total debt

   $ 12,339     $ 14,747  
                

Equity

   $ 18,795     $ 16,364  
                

Debt-to-capital ratio

     39.6 %     47.4 %

In January 2008, Anadarko entered into forward-looking 18-month interest rate swaps effective March 2008 with an aggregate notional principal amount of $1.0 billion whereby the Company will pay a weighted-average fixed interest rate of 2.74% and receive a floating interest rate indexed to the three-month LIBOR rate. Anadarko discontinued hedge accounting on January 1, 2007, therefore all gains and losses associated with these swaps will be recorded to interest expense.

In anticipation of the refinancing of existing debt obligations, Anadarko entered into swaps to fix interest rates and in doing so mitigated a portion of the risk it had to unfavorable interest rate changes prior to the future issuance of debt. In December 2008, Anadarko entered into three-year forward-looking 10-year swap agreements with a combined notional principal amount of $400 million, a three-year forward-looking 30-year swap agreement with a notional principal amount of $100 million, and four-year forward-looking 30-year swap agreements with a combined notional principal amount of $250 million. Under each of these agreements, the Company will pay a fixed interest rate and receive a floating interest rate indexed to the three-month LIBOR rate.

In January 2009, Anadarko entered into three-year forward-looking 10-year swap agreements with a combined notional principal amount of $350 million, three-year forward-looking 30-year swap agreements with a combined notional principal amount of $1.15 billion, four-year forward-looking 10-year swap agreements with a combined notional principal amount of $250 million, and four-year forward-looking 30-year swap agreements with a combined notional principal amount of $500 million. Under each of these agreements, the Company will pay a fixed interest rate and receive a floating interest rate indexed to the three-month LIBOR rate.

For additional information on the Company’s debt instruments, such as transactions during the period, years of maturity and interest rates, see Note 8—Derivative Instruments and Note 10—Debt and Interest Expense of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Midstream Subsidiary Note Payable to a Related Party In December 2007, Anadarko and an entity formed by a group of unrelated third-party investors (the Investor) formed Trinity Associates LLC (Trinity). As discussed in Note 6—Investments of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K, Trinity was initially capitalized with a $100 million cash contribution from Anadarko in exchange for Class A member and managing member interests in Trinity and a $2.2 billion cash contribution from the Investor in exchange for a Class B member cumulative preferred interest. Trinity invested $100 million in a U.S. Government securities money market fund and loaned $2.2 billion to a wholly-owned subsidiary of Anadarko, Midstream Holding. The Company used all of the loan proceeds received by Midstream Holding to repay a portion of the Company’s acquisition facility indebtedness. The principal balance owed by Midstream Holding to Trinity is reflected in the consolidated balance sheet as Midstream Subsidiary Note Payable to a Related Party. Midstream Holdings may repay the loan in whole or in part at any time prior to maturity. Initially, Midstream Holding’s obligations under the loan agreement were not guaranteed by Anadarko Petroleum Corporation, but were unconditionally guaranteed, jointly and severally, by all of Midstream Holding’s subsidiaries.

In December 2008, Anadarko provided an unconditional parental guaranty for the payment of principal and interest on the remaining balance of the Midstream Subsidiary Note Payable to a Related Party in exchange for

 

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the removal of various covenants in the loan agreement. The guaranty is also jointly and severally guaranteed by certain midstream subsidiaries. Midstream Holding was in compliance with all previously existing covenants as of the date the Anadarko parental guaranty was provided. The Midstream Subsidiary Note Payable to a Related Party will have the same priority with respect to the payment of principal and interest as Anadarko’s other debt. At December 31, 2008, the Midstream Note Payable to a Related Party had an outstanding balance of $1.7 billion.

Common Stock Repurchase Program In August 2008, the Company announced a $5 billion share-repurchase program under which shares may be repurchased either in the open market or through privately negotiated transactions. The program is authorized to extend through August 2011 and replaces the $1 billion stock buyback program authorized in 2005. The repurchase program does not obligate Anadarko to acquire any specific number of shares and may be discontinued at any time. During 2008 and 2006, Anadarko purchased 10.0 million and 2.5 million shares of common stock for $600 million and $118 million, respectively, under these programs through purchases in the open market and under share-repurchase agreements. During 2007, no shares were repurchased under the program in effect at that time.

Dividends In 2008, 2007 and 2006, Anadarko paid $170 million, $170 million and $167 million, respectively, in dividends to its common stockholders (nine cents per share per quarter). Anadarko has paid a dividend to its common stockholders continuously since becoming an independent company in 1986. The amount of future dividends for Anadarko common stock will depend on earnings, financial conditions, capital requirements and other factors, and will be determined by the Board of Directors on a quarterly basis.

The covenants in the Company’s credit agreement provide for a maximum capitalization ratio of 65% debt, exclusive of the effect of any non-cash write-down’s. Although the covenants of the agreement do not specifically restrict the payment of dividends, the Company could be limited in the amount of dividends it could pay in order to stay below the maximum capitalization ratio. Based on these covenants as of December 31, 2008, retained earnings of approximately $12.3 billion were not limited as to the payment of dividends.

In 2008, 2007 and 2006, Anadarko paid $1 million, $3 million and $3 million, respectively, in preferred stock dividends. The preferred stock was redeemed and subsequently retired in the second quarter of 2008.

Outlook The Company’s goals include continuing to find or acquire high-margin oil and gas reserves at competitive prices while keeping operating costs at efficient levels.

Anadarko’s strategy involves developing its portfolio of primarily unconventional resources that give the Company a stable base of capital-efficient, predictable and repeatable development opportunities to consistently grow the Company at competitive rates. Exploring in high-potential, proven and emerging basins worldwide provides the Company with differential growth. Anadarko’s exploration success creates value by expanding its future resource potential, while providing the flexibility to manage risk by monetizing discoveries.

The Company has an approved 2009 capital spending budget, including expensed geology and geophysics costs, of approximately $4.0 billion to $4.5 billion. The Company has allocated about 70% of capital spending to development activities, 20% to exploration activities and 10% to gas gathering and processing activities and other items. The Company expects capital spending by area to be approximately 30% for the Rockies, 15% for the Southern region, 20% for the Gulf of Mexico, 25% for International and Alaska and 10% for Midstream and other. Primary emphasis will be on production growth in the Rockies and continued development in the Gulf of Mexico, exploration, appraisal and development wells in Ghana and in Algeria. Production is expected to begin in Ghana in late 2010. The Company’s capital discipline strategy is to set capital activity at levels that can be funded with operating cash flows and existing cash on hand. Anadarko believes that its expected level of cash flow and cash on hand will be sufficient to fund the Company’s projected operational program for 2009.

In addition, to support 2009 cash flows, Anadarko has implemented price risk management on approximately 24% of its anticipated natural gas wellhead sales volumes and approximately 28% of its anticipated oil and condensate sales volumes for 2009.

If capital expenditures were to exceed operating cash flow, funds would be supplemented as needed by short-term borrowings. To facilitate such borrowings, the Company has in place a $1.3 billion RCA and as of December 31, 2008, the Company had no outstanding borrowings under its RCA. The Company may choose to

 

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refinance certain portions of its short-term borrowings by issuing long-term debt in the public or private debt markets. To facilitate such financings, the Company may sell securities under its shelf registration statement filed with the SEC in September 2006.

The Company plans to repay current debt of $1.5 billion outstanding at December 31, 2008 with cash on hand, cash flow from operations and, if necessary, funds available under the $1.3 billion RCA or debt refinancing.

The Company continuously monitors its debt position and coordinates its capital expenditure program with expected cash flows and projected debt repayment schedules. The Company will continue to evaluate funding alternatives, including property divestitures and additional borrowings, to secure funds when needed.

For additional information on factors that could impact Anadarko’s future results of operations, cash flows from operating activities or financial position see Critical Accounting Estimates below and Risk Factors under Item 1A of this Form 10-K.

Off-Balance Sheet Arrangements

In 2007, Anadarko contributed certain of its oil and gas properties and gathering and processing assets, with an aggregate fair value of approximately $2.9 billion at the time of contribution, to newly formed unconsolidated entities in exchange for noncontrolling mandatorily redeemable interests in those entities. Subsequent to their formation, the investee entities loaned Anadarko an aggregate of $2.9 billion, which the Company used to repay its acquisition-related debt. Anadarko has a legal right to setoff and intends to net-settle its obligations under each of the notes payable to the investees and the distributable value of its interest in the corresponding investee. Accordingly, the $2.9 billion aggregate principal amount of such notes does not affect Anadarko’s reported debt balance, since the notes and the carrying amount of Anadarko’s investments in the investees are presented on the consolidated balance sheet on a net basis. The related interest expense on these obligations and Anadarko’s equity in earnings for Anadarko’s investment in these entities are recorded in other income (expense), net. Note 6—Investments of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K provides additional information with respect to each of these transactions. Completion of these transactions resulted in Anadarko divesting control of its interests in certain non-core exploration and production and midstream assets and operations, while retaining a participating 5% interest in profits, losses and residual value of the investees.

With respect to each investee, liquidation of the investee or redemption of Anadarko’s interest in the investee is expected to result in Anadarko net-settling in cash its obligation under the corresponding note payable with the distributable value of its interest in the investee. The Company does not currently expect such net settlement to have a material effect on its future financial condition, results of operations or cash flows. Each of Anadarko’s noncontrolling interests in the investees is optionally redeemable by Anadarko or the controlling investor in or after 2022 and is mandatorily redeemable in 2037.

 

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Obligations and Commitments

Following is a summary of the Company’s obligations as of December 31, 2008:

 

     Obligations by Period
millions    1 Year    2-3
Years
   4-5
Years
   More
than 5
Years
   Total

Total debt

              

Principal—current debt

   $ 1,472    $ —      $ —      $ —      $ 1,472

Principal—long-term debt

     —        1,625      252      9,032      10,909

Midstream subsidiary note payable to a related party

     —        —        1,739      —        1,739

Permian LLC and Midstream LLCs debt(1)

     —        —        —        2,853      2,853

Interest

     659      1,208      967      7,366      10,200

Permian LLC and Midstream LLCs interest(1)

     86      173      174      2,468      2,901

Operating leases

              

Drilling rig commitments

     1,051      1,792      1,014      —        3,857

Production platforms

     64      118      90      314      586

Other

     78      123      59      55      315

Asset retirement obligations

     16      213      147      992      1,368

Midstream and marketing activities

     169      296      234      274      973

Oil and gas activities

     470      436      142      95      1,143

Derivative liabilities

     24      15      9      3      51

FIN 48 liabilities, interest and penalties(2)

     56      56      —        42      154

Environmental liabilities

     43      26      10      40      119
                                  

Total(3)

   $ 4,188    $ 6,081    $ 4,837    $ 23,534    $ 38,640
                                  

 

(1)

Anadarko has legal right of setoff and intends to net-settle its obligations under each of the notes payable to the investees and the distributable value of its interest in the corresponding investee. Accordingly, the investment and the obligation are presented net on the consolidated balance sheet and included in other long-term liabilities—other for all periods presented. The interest expense on these obligations and Anadarko’s equity earnings for Anadarko’s investment in these entities are recorded in other income (expense), net. See Note 6—Investments of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K and Off-Balance Sheet Arrangements discussed above.

 

(2)

See Note 16—Income Taxes of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

(3)

This table does not include the Company’s pension or postretirement benefit obligations. See Note 22—Pension Plans, Other Postretirement Benefits and Employee Savings Plans of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K and Other below.

Operating Leases Operating lease obligations include several drilling rig commitments that qualify as operating leases. Over the past three years, Anadarko has entered into several agreements to secure the necessary drilling rigs to execute its drilling strategy over several years. A previous review of the Company’s worldwide deepwater drilling inventory, along with the tightening deepwater and onshore rig market experienced in prior years, led Anadarko to secure the drilling rigs it needs to execute its strategy. The Company believes these rig-contracting efforts offer compelling economics and facilitate its drilling strategy. The portion of lease payments associated with successful exploratory wells and development wells, net of amounts billed to partners, will be capitalized as a component of oil and gas properties.

The Company also has $0.9 billion in commitments under noncancelable operating lease agreements for production platforms and equipment, buildings, facilities and aircraft.

For additional information see Note 13—Commitments of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

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Asset Retirement Obligations Anadarko is obligated to dispose of long-lived assets upon their abandonment. The majority of Anadarko’s asset retirement obligations relate to the plugging and abandonment of oil and gas properties. The asset retirement obligation (ARO) is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company’s credit-adjusted risk-free interest rate. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.

Midstream and Marketing Activities Anadarko has entered into various transportation, storage and purchase agreements in order to access markets and provide flexibility for the sale of its natural gas and crude oil in certain areas. The above table includes amounts related to these commitments.

Oil and Gas Activities As is common in the oil and gas industry, Anadarko has various long-term contractual commitments pertaining to exploration, development and production activities, which extend beyond the 2009 budget. The Company has work-related commitments for, among other things, drilling wells, obtaining and processing seismic and fulfilling rig commitments. The preceding table includes long-term drilling and work- related commitments of $1,143 million, comprised of $589 million in the United States, $80 million in Algeria and $474 million in other international locations.

The Company also has option and swap contracts in place to manage price risk associated with a portion of its expected future sales of its oil and gas production. Both exchange and over-the-counter traded derivative instruments are subject to margin deposit requirements. Margin deposits are required of the Company whenever its unrealized losses on derivative instruments with a counterparty exceed predetermined credit limits. Given the Company’s price risk management position and price volatility, the Company may be required from time to time to advance cash to its counterparties in order to satisfy these margin deposit requirements. The Company had net margin deposits (cash collateral) of $7 million outstanding at December 31, 2008.

Marketing and Trading Contracts The following tables provide information as of December 31, 2008 regarding the Company’s marketing and trading portfolio of physical delivery and financially settled derivative instruments. See Critical Accounting Estimates for an explanation of how the fair value for derivatives is calculated.

 

millions    Marketing
and Trading
 

Fair value of contracts outstanding as of December 31, 2007—assets (liabilities)

   $ 11  

Contracts realized or otherwise settled during 2008

     (12 )

Fair value of new contracts when entered into during 2008

     1  

Other changes in fair value

     48  
        

Fair value of contracts outstanding as of December 31, 2008—assets (liabilities)

   $ 48  
        

 

     Fair Value of Contracts as of December 31, 2008

Assets (Liabilities)

millions

   Maturity
less than
1 Year
   Maturity
1-3 Years
   Maturity
4-5 Years
   Maturity
in excess
of 5 Years
   Total

Marketing and Trading

              

Prices actively quoted

   $ 48    $ —      $ —      $ —      $ 48

Environmental Anadarko is also subject to various environmental remediation and reclamation obligations arising from federal, state and local laws and regulations. As of December 31, 2008, the Company’s balance sheet included a $119 million liability for remediation and reclamation obligations, most of which were incurred by companies that Anadarko has acquired. The Company continually monitors the liability recorded and the remediation and reclamation process, and believes the amount recorded is appropriate. For additional information see Legal Proceedings—Environmental Matters under Item 3 of this Form 10-K.

 

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Other In 2008, the Company made contributions of $63 million to its funded pension plans, $13 million to its unfunded pension plans and $19 million to its unfunded other postretirement benefit plans. Contributions to the funded plans increase the plan assets while contributions to unfunded plans are used for current benefit payments. Based on the impact of recent market volatility on the plan assets, the Company expects to contribute up to $250 million to its funded pension plans, $23 million to its unfunded pension plans and $22 million to its unfunded other postretirement benefit plans in 2009. Future contributions to funded pension plans will be affected by actuarial assumptions, market performance and individual year funding decisions. The Company is unable to predict what contribution levels will be required beyond 2009 for the funded pension plans. The Company expects future payments for other postretirement benefit plans to be at levels similar to those made in 2008.

For additional information on contracts, obligations and arrangements the Company enters into from time to time, see Note 10—Debt and Interest Expense, Note 8—Derivative Instruments, Note 13—Commitments, and Note 14—Contingencies of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Discontinued Operations

In November 2006, Anadarko sold its wholly-owned subsidiary, Anadarko Canada Corporation, for approximately $4 billion before income taxes. Accordingly, the Canadian oil and gas operations have been classified as discontinued operations in the consolidated statements of income and cash flows. The following table summarizes selected data pertaining to discontinued operations.

 

millions except per share amounts    2008     2007    2006  

Revenues and other

   $ —       $ 24    $ 717  
                       

Income from discontinued operations

   $ —       $ 18    $ 311  

Gain on disposition of discontinued operations

     98       8      2,494  
                       

Income from discontinued operations before income taxes

     98       26      2,805  

Income tax expense

     35       15      530  
                       

Income from discontinued operations, net of taxes

   $ 63     $ 11    $ 2,275  
                       

Earnings per common share from discontinued operations—diluted

   $ 0.13     $ 0.02    $ 4.91  

Annual sales volumes (MMBOE)

     —         —        17  

Cash flow provided by (used in) operating activities

   $ (5 )   $ 134    $ (178 )

Capital expenditures

   $ —       $ —      $ 537  

Income from discontinued operations for 2008 and 2007 related primarily to the impact of an adjustment to an indemnity obligation provided by the Company to the purchaser, as well as expenses associated with finalizing exit activities, discussed in Note 14—Contingencies of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Income from discontinued operations, net of tax, for 2007 decreased compared to 2006 primarily due to the gain on the sale of Canadian operations recognized in 2006, which was partially offset by an increase in Canadian taxes associated with the gain on sale.

Under the Company’s initial 364-day term loan agreement, the Company was required to use net cash proceeds from significant dispositions to repay debt. Because the Canadian assets were subject to this requirement, approximately $58 million of interest expense related to the portion of debt that was repaid with proceeds from the sale of the Canadian operations is included in results of discontinued operations for 2006.

 

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Critical Accounting Estimates

In preparing financial statements in accordance with GAAP, management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting periods. On an ongoing basis, management reviews its estimates, including those related to determination of properties and equipment, proved reserves, goodwill, asset retirement obligations, litigation, environmental liabilities, pension liabilities and costs, income taxes and fair values. Changes in facts and circumstances or discovery of new information may result in revised estimates and actual results may differ from these estimates. Management considers the following to be its most critical accounting policies and estimates that involve judgment and discusses the selection and development of these policies and estimates with the Company’s Audit Committee.

Oil and Gas Activities

Anadarko uses the successful efforts method to account for its oil and gas activities. Under this method, acquisition costs and the costs associated with drilling exploratory well costs are capitalized pending the determination of proved oil and gas reserves. Geological and geophysical costs and other costs of carrying properties such as delay rentals are expensed as incurred.

Acquisition Costs

Acquisition costs of unproved properties are assessed for impairment during the holding period and transferred to proved oil and gas properties to the extent associated with successful exploration activities. Significant undeveloped leases are assessed periodically for impairment individually, based on the Company’s current exploration plans, and a valuation allowance is provided if impairment is indicated.

For unproved oil and gas properties with individually insignificant lease acquisition costs, costs are amortized on a group basis over the average lease terms at rates that provide for full amortization of unsuccessful leases upon expiration. Costs of expired or abandoned leases are charged against the valuation allowance, while costs of productive leases are transferred to proved oil and gas properties. Amortization of individually insignificant leases and impairment of unsuccessful leases are included in exploration expense.

Significant undeveloped leasehold costs are assessed for impairment at a lease level or resource play (for example, Greater Natural Buttes area in the Rocky Mountain region), while leasehold acquisition costs associated with prospective areas that have had limited or no previous exploratory drilling are generally assessed for impairment by major prospect area.

A majority of the Company’s unproved leasehold costs are associated with properties acquired in the Kerr-McGee and Western acquisitions in 2006 and to which proved developed producing reserves are also attributed. Generally, economic recovery of unproved reserves in such areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by the Company’s continuing exploitation program. Ultimate recovery of potentially recoverable reserves in areas with established production generally has greater likelihood than in areas with limited or no prior drilling activity.

Another portion of the Company’s unproved leasehold costs are associated with the Land Grant acreage, where the Company owns mineral interests in perpetuity and plans to continue to explore and evaluate the acreage.

A change in the Company’s expected future plans for exploration and development could cause a write-down in the Company’s unproved property.

Exploratory Costs

Under the successful efforts method of accounting, exploratory costs associated with a discovery well are initially capitalized, or suspended, pending determination of whether proved reserves can be attributed to the area as a result of drilling. At the end of each quarter, management reviews the status of all suspended exploratory drilling costs in light of ongoing exploration activities—in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government

 

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sanctioning, whether development negotiations are under way and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory drilling costs are expensed. Therefore, at any point in time, the Company may have capitalized costs on its consolidated balance sheet associated with exploratory wells that may be charged to exploration expense in a future period. At December 31, 2008, suspended exploratory drilling costs were $279 million compared to $308 million at December 31, 2007.

Proved Reserves

Anadarko estimates proved oil and gas reserves as defined by the SEC and the FASB. This definition includes crude oil, natural gas, and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

The Company’s estimates of proved reserves are made using available geological and reservoir data as well as production performance data. These estimates are reviewed annually by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions, as well as changes in the expected recovery rates associated with infill drilling. Decreases in prices, for example, may cause a reduction in some proved reserves due to reaching economic limits earlier. A material adverse change in the estimated volumes of proved reserves could have a negative impact on DD&A expense and impairment expense.

In December 2008, the SEC released the final rule for Modernization. The Modernization disclosure requirements will permit reporting of oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices and the use of new technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Companies will also be allowed to disclose probable and possible reserves in SEC filed documents. In addition, companies will be required to report the independence and qualifications of its reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit. The Modernization disclosure requirements become effective for Anadarko’s Annual Report on Form 10-K for the year ended December 31, 2009. The SEC is coordinating with the FASB to obtain the revisions necessary to provide consistency with the Modernization. In the event that consistency is not achieved in time for companies to comply with the Modernization, the SEC will consider delaying the compliance date. A significant change as a result of the Modernization rule relates to the calculation of reserves. Currently, reserves are calculated on a single-day year-end price. Under the Modernization rule, reserves will be calculated on an average price which will reduce the volatility (volatility as demonstrated in 2008) of the reserve calculation.

Fair Value

The Company estimates fair value for the measurement of derivatives, long-lived assets during certain impairment tests, reporting units for goodwill impairment testing, certain exchanges, guarantees, and the initial measurement of an ARO. When the Company is required to measure fair value, and there is not a market observable price for the asset or liability, or a market observable price for a similar asset or liability, the Company generally utilizes an income valuation approach. This approach utilizes management’s best assumptions regarding expectations of projected cash flows, and discounts the expected cash flows using a commensurate risk adjusted discount rate. Such evaluations involve a significant amount of judgment since the results are based on expected future events or conditions, such as sales prices; estimates of future oil and gas production or throughput; development and operating costs and the timing thereof; economic and regulatory climates and other factors. The Company’s estimates of future net cash flows are inherently imprecise because they reflect management’s expectation of future conditions that are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs and other factors, and are consistent with assumptions used in the Company’s business plans and investment decisions.

 

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Business Combinations

Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities of the acquired business and recording deferred taxes for any differences between the allocated values and tax basis of assets and liabilities. Any excess of the purchase price over the amounts assigned to assets and liabilities is recorded as goodwill.

Purchase Price Allocation

The purchase price allocation is accomplished by recording the asset or liability at its estimated fair value. Estimated deferred taxes are based on available information concerning the tax basis of the acquired company’s assets and liabilities and carryforwards at the merger date, although such estimates may change in the future as additional information becomes known. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed relative to the total acquisition cost.

Goodwill

At December 31, 2008, the Company had $5.3 billion of goodwill recorded related to past business combinations. This goodwill is not amortized, but is required to be assessed for impairment annually, or more often as facts and circumstances warrant. The first step of that process is to compare the fair value of the reporting unit to which goodwill has been assigned to the carrying amount of the associated net assets and goodwill. The reporting units used to evaluate and measure goodwill for impairment are determined from the manner in which the business is managed. A reporting unit is an operating segment or a component that is one level below an operating segment. Anadarko has allocated goodwill to three reporting units. These reporting units are oil and gas exploration and production, gathering and processing, and transportation. Goodwill is tested annually on January 1. The Company completed its January 1, 2008 annual goodwill impairment tests with no impairment indicated. As a result of general economic conditions, declines in commodity prices, and declines in its market capitalization compared to the book value of its stockholders’ equity during the fourth quarter of 2008, the Company determined an interim impairment test as of December 31, 2008 was appropriate. The results of this interim goodwill impairment test also resulted in no impairment indicated. Anadarko considered its conclusions in light of its year-end market capitalization being approximately 6% below the book value of its stockholders’ equity, and concluded the assessment that no impairment was appropriate when considering that the market value for one share of Anadarko common stock does not consider any premium that might be paid by a buyer who would obtain control of Anadarko’s entire oil and gas, gathering and processing, or transportation reporting units. Although Anadarko cannot predict when or if goodwill will be impaired in the future, impairment charges may occur if the Company is unable to replace the value of its depleting asset base or if other adverse events (for example, lower sustained oil and gas prices) reduce the fair value of the associated reporting unit.

Because quoted market prices for the Company’s reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units for purposes of performing the goodwill impairment test. Management uses all available information to make these fair value estimates, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets and observed for the oil and gas exploration and production reporting unit and market multiples of EBITDAX for the gathering and processing and transportation reporting units. In estimating fair value of its oil and gas reporting unit, the Company assumed production profiles utilized in its year-end estimation of reserves that are disclosed in the Company’s supplemental oil and gas disclosures, market prices considering the forward price curve for oil and gas, adjusted for location and quality differentials that the Company currently receives, as well as capital and operating costs consistent with year-end pricing, adjusted for management’s view that such costs should decline in the near term to realign with lower commodity prices, and discount rates that management believes a market participant would utilize to consider the risks inherent in Anadarko’s operations. For the Company’s midstream reporting units, the Company estimated fair value based on an estimated multiple of projected 2009 earnings before interest, taxes, depreciation and amortization (EBITDA). The Company

 

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considered the relatively few transactions in the market, as well as trading multiples for peers to determine an appropriate multiple to apply against the Company’s projected EBITDA for its gathering and processing and transportation reporting units. A lower fair value estimate in the future for any of these reporting units could result in impairment. Examples of factors that could cause a lower fair value estimate could be sustained declines in prices, increases in costs, and changes in discount rate assumptions due to market conditions.

Impairment of Assets

A long-lived asset other than unproved oil and gas property is evaluated for potential impairment whenever events or changes in circumstances indicate that its carrying amount may be greater than its future net cash flows. Impairment loss, if any, is measured as the excess of its carrying amount over the asset’s estimated fair value. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of future production volumes, prices and costs, considering all available information at the date of the impairment review.

Derivative Instruments

All derivative instruments, other than those that meet specific exclusions, are recorded at fair value. If market quotes are not available to estimate fair value, management’s best estimate of fair value is based on the quoted market price of derivatives with similar characteristics or utilizing industry standard valuation techniques.

The Company’s derivative instruments are either exchange traded or transacted in an over-the-counter market. Valuation is determined by reference to readily available public data. Option fair values are measured using the Black-Scholes-Merton option pricing model and verified by comparing a sample to market quotes for similar options if available. Unrealized gains or losses on derivatives are recorded within Anadarko’s current earnings.

Benefit Plan Obligations

The Company has non-contributory defined benefit pension plans, including both qualified and supplemental plans, and a foreign contributory defined benefit pension plan. The Company also provides certain health care and life insurance benefits for retired employees. Determination of the projected benefit obligations for the Company’s defined benefit pension and postretirement plans is important to the recorded amounts for such obligations on the balance sheet and to the amount of benefit expense in the income statement. This also impacts the Company’s decisions for amounts contributed into the plans.

Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to discount rate for measuring the present value of future plan obligations; expected long-term rates of return on plan assets; rate of future increases in compensation levels; and health care cost projections. Anadarko develops demographics and utilizes the work of third-party actuaries to assist in the measurement of these obligations.

Discount rate

The discount rate assumption used by the Company is meant to reflect the interest rate at which the pension and other postretirement obligations could effectively be settled on the measurement date. The Company currently uses a yield curve analysis, for a majority of the plans, to support the discount rate assumption. This analysis involves the creation of a hypothetical Aa spot yield curve represented by a series of high-quality, non-callable, marketable bonds, then discounts the projected cash flows from each plan at interest rates on the created curve specifically applicable to the timing of each respective cash flow. The present values of the cash flows are then accumulated, and a weighted-average discount rate is calculated by imputing the single discount rate that equates to the total present value of the cash flows. The consolidated discount rate assumption is determined by evaluation of the weighted-average discount rates determined for each of the Company’s significant pension and postretirement plans. The weighted-average discount rate assumption used by the Company as of December 31, 2008 was 6.0% for pension plans and other postretirement plans.

 

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Expected long-term rate of return

The expected long-term rate of return on assets assumption was determined using the year-end 2008 pension investment balances by category and projected target asset allocations for 2009. The expected return for each of these categories was determined by using capital market projections, with consideration of actual five-year performance statistics for investments in place. The weighted-average expected long-term rate of return on plan assets assumption used by the Company as of December 31, 2008 was 7.75%.

Rate of compensation increases

The Company determines this assumption based on its long-term plans for compensation increases specific to employee groups covered and expected economic conditions. The assumed rate of salary increases includes the effects of merit increases, promotions and general inflation. The weighted-average rate of increase in long-term compensation levels assumption used by the Company as of December 31, 2008 was 5.0%.

Health care cost trend rate

The health care cost trend assumptions are developed based on historical cost data, the near-term outlook and an assessment of likely long-term trends. A 9.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2009, decreasing gradually to 5.0% in 2017 and later years.

Environmental Obligations and Other Contingencies

Management makes judgments and estimates in accordance with applicable accounting rules when it establishes reserves for environmental remediation, litigation and other contingent matters. Provisions for such matters are charged to expense when it is probable that a liability has been incurred and reasonable estimates of the liability can be made. Estimates of environmental liabilities are based on a variety of matters, including, but not limited to, the stage of investigation, the stage of the remedial design, evaluation of existing remediation technologies, and presently enacted laws and regulations. In future periods, a number of factors could significantly change the Company’s estimate of environmental remediation costs, such as changes in laws and regulations, or changes in their interpretation or administration, revisions to the remedial design, unanticipated construction problems, identification of additional areas or volumes of contaminated soil and groundwater, and changes in costs of labor, equipment and technology. Consequently, it is not possible for management to reliably estimate the amount and timing of all future expenditures related to environmental or other contingent matters and actual costs may vary significantly from the Company’s estimates. The Company’s in-house legal counsel and environmental personnel regularly assess these contingent liabilities and, in certain circumstances, outside legal counsel or consultants are utilized.

Income Taxes

The amount of income taxes recorded by the Company requires the interpretation of complex rules and regulations of various taxing jurisdictions throughout the world. The Company has recognized deferred tax assets and liabilities for temporary differences, operating losses and tax credit carryforwards. The Company routinely assesses the realizability of its deferred tax assets and reduces such assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. The Company routinely assesses potential uncertain tax positions and, if required, establishes accruals for such amounts. The accruals for deferred tax assets and liabilities are subject to a significant amount of judgment by Company management and are reviewed and adjusted routinely based on changes in facts and circumstances. Although Company management believes its tax accruals are adequate, material changes in these accruals may occur in the future, based on the progress of ongoing tax audits, changes in legislation and resolution of pending tax matters.

 

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Recent Accounting Developments

In June 2008, the FASB issued FASB Staff Position (FSP) Emerging Issues Task Force (EITF) No. 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” FSP EITF No. 03-6-1 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and are therefore required to be included in the earnings allocation in calculating earnings per share (EPS) under the two-class method described in SFAS No. 128, “Earnings per Share.” FSP EITF No. 03-6-1 requires companies to treat unvested share-based payment awards that have non-forfeitable rights to dividend or dividend equivalents as a separate class of securities in calculating EPS. FSP EITF No. 03-6-1 is effective for fiscal years beginning after December 15, 2008; early adoption is not permitted. The Company adopted FSP EITF No. 03-6-1 effective January 1, 2009. FSP EITF No. 03-6-1 will not affect Anadarko’s presentation of EPS.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (SFAS No. 161). SFAS No. 161 does not change the accounting policy for derivatives, but requires enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items (if any) are accounted for, and how they affect the Company’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for Anadarko for annual and interim periods beginning with the first quarter of 2009. Anadarko did not elect early adoption. SFAS No. 161 is a disclosure requirement that does not affect Anadarko’s consolidated financial statements.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—An Amendment of ARB No. 51”. SFAS No. 160 establishes new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. Specifically, this statement requires the recognition of a noncontrolling interest (minority interest) as a component of consolidated equity. This is a change from the current practice to present noncontrolling interests in liabilities or between liabilities and stockholders’ equity. Similarly, SFAS No. 160 requires consolidated net income and comprehensive income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interests. Anadarko will be required to adopt accounting provisions of SFAS No. 160 prospectively with respect to transactions involving noncontrolling financial interests that occur on or after January 1, 2009. Presentation and disclosure requirements of SFAS No. 160 will also be applied effective January 1, 2009, but with respect to all periods presented. After adopting SFAS No. 160 in 2009, the Company will apply provisions of this standard to noncontrolling interests created or acquired in future periods. Upon adoption, the Company will reclassify its minority interests to stockholders’ equity.

For additional information on recently issued accounting standards not yet adopted, see Note 1—Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

 

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The Company’s primary market risks are fluctuations in energy prices and interest rates. These fluctuations can affect revenues and cash flow from operating, investing and financing activities. The Company’s risk management policies provide for the use of derivative instruments to manage these risks. The types of derivative instruments utilized by the Company include futures, swaps, options and fixed price physical delivery contracts. The volume of derivative instruments utilized by the Company is governed by the risk management policy and can vary from year to year. Both exchange and over-the-counter traded derivative instruments may be subject to margin deposit requirements. Given the Company’s price risk management position and price volatility, the Company may be required from time to time to deposit cash or provide letters of credit with its counterparties in order to satisfy these margin requirements. For additional information see Liquidity and Capital Resources—Margin Deposits under Part II, Item 7 of this Form 10-K.

For information regarding the Company’s accounting policies and additional information related to the Company’s derivative and financial instruments, see Note 1—Summary of Significant Accounting Policies, Note 10—Debt and Interest Expense and Note 8—Derivative Instruments of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Energy Price Risk The Company’s most significant market risk is the pricing for natural gas, crude oil and NGLs. Management expects energy prices to remain volatile and unpredictable. If energy prices decline significantly, revenues and cash flow would significantly decline. In addition, a non-cash write-down of the Company’s oil and gas properties could be required under successful efforts accounting rules if future oil and gas commodity prices sustained significant decline. Below is a sensitivity analysis of the Company’s commodity price related derivative instruments.

Derivative Instruments Held for Non-Trading Purposes The Company had derivative instruments in place to reduce the price risk associated with future equity production of 322 Bcf of natural gas and 34 MMBbls of crude oil as of December 31, 2008. As of December 31, 2008, the Company had a net unrealized gain of $619 million on these derivative instruments. Utilizing the actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by approximately $149 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by approximately $111 million. However, a loss or gain would be substantially offset by an increase or decrease, respectively, in the value of that portion of the Company’s production covered by the derivative instruments.

Derivative Instruments Held for Trading Purposes As of December 31, 2008, the Company had a net unrealized gain of $48 million (gains of $78 million and losses of $30 million) on derivative financial instruments entered into for trading purposes. Utilizing the actual derivative contractual volumes, a 10% increase or decrease in underlying commodity prices would result in a loss or gain, respectively, on these derivative instruments of $5 million.

For additional information regarding the Company’s marketing and trading portfolio, see Marketing Strategies under Item 7 of this Form 10-K.

Interest Rate Risk As of December 31, 2008, Anadarko had outstanding $3.1 billion of variable-rate debt (including the midstream subsidiary note payable to a related party) and $9.2 billion of fixed-rate debt. A 10% increase in LIBOR interest rates would increase gross interest expense approximately $9 million per year.

In January 2008, Anadarko entered into forward-looking 18-month interest rate swaps effective March 2008 with an aggregate notional principal amount of $1.0 billion whereby the Company will pay a weighted-average fixed interest rate of 2.74% and receive a floating interest rate indexed to the three-month LIBOR rate.

In anticipation of the refinancing of existing debt obligations, Anadarko entered into swaps to fix interest rates and in doing so mitigated a portion of the risk it had to unfavorable interest rate changes prior to the future issuance of debt. In December 2008, Anadarko entered into three-year forward-looking 10-year swap agreements with a combined notional principal amount of $400 million, a three-year forward-looking 30-year swap

 

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agreement with a notional principal amount of $100 million, and four-year forward-looking 30-year swap agreements with a combined notional principal amount of $250 million. Under each of these agreements, the Company will pay a fixed interest rate and receive a floating interest rate indexed to the three-month LIBOR rate.

In January 2009, Anadarko entered into three-year forward-looking 10-year swap agreements with a combined notional principal amount of $350 million, three-year forward-looking 30-year swap agreements with a combined notional principal amount of $1.15 billion, four-year forward-looking 10-year swap agreements with a combined notional principal amount of $250 million, and four-year forward-looking 30-year swap agreements with a combined notional principal amount of $500 million. Under each of these agreements, the Company will pay a fixed interest rate and receive a floating interest rate indexed to the three-month LIBOR rate.

 

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Item 8. Financial Statements and Supplementary Data

ANADARKO PETROLEUM CORPORATION

INDEX

CONSOLIDATED FINANCIAL STATEMENTS

 

     Page

Report of Management

   69

Management’s Assessment of Internal Control Over Financial Reporting

   69

Reports of Independent Registered Public Accounting Firm

   70

Statements of Income, Three Years Ended December 31, 2008

   72

Balance Sheets, December 31, 2008 and 2007

   73

Statements of Stockholders’ Equity, Three Years Ended December 31, 2008

   74

Statements of Comprehensive Income, Three Years Ended December 31, 2008

   75

Statements of Cash Flows, Three Years Ended December 31, 2008

   76

Notes to Consolidated Financial Statements

   77

Supplemental Quarterly Information

   125

Supplemental Information on Oil and Gas Exploration and Production Activities

   126

 

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ANADARKO PETROLEUM CORPORATION

REPORT OF MANAGEMENT

Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this annual report. The consolidated financial statements present fairly the Company’s financial position, results of operations and cash flows in conformity with accounting principles generally accepted in the United States. In preparing its consolidated financial statements, the Company includes amounts that are based on estimates and judgments that Management believes are reasonable under the circumstances. The Company’s financial statements have been audited by KPMG LLP, an independent registered public accounting firm appointed by the Audit Committee of the Board of Directors. Management has made available to KPMG LLP all of the Company’s financial records and related data, as well as the minutes of the stockholders’ and Directors’ meetings.

MANAGEMENT’S ASSESSMENT OF INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting. Anadarko’s internal control system was designed to provide reasonable assurance to the Company’s Management and Directors regarding the preparation and fair presentation of published financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008. This assessment was based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, we believe that as of December 31, 2008 the Company’s internal control over financial reporting is effective based on those criteria.

 

/s/ JAMES T. HACKETT

James T. Hackett

Chairman, President and Chief Executive Officer

 

/s/ R. A. WALKER

R. A. Walker

Senior Vice President, Finance and

Chief Financial Officer

February 24, 2009

 

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Anadarko Petroleum Corporation:

We have audited Anadarko Petroleum Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Anadarko Petroleum Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Assessment of Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Anadarko Petroleum Corporation and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Anadarko Petroleum Corporation and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of income, stockholders’ equity, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2008, and our report dated February 24, 2009 expressed an unqualified opinion on those consolidated financial statements.

 

/s/ KPMG LLP

Houston, Texas

February 24, 2009

 

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Anadarko Petroleum Corporation:

We have audited the accompanying consolidated balance sheets of Anadarko Petroleum Corporation and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of income, stockholders’ equity, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2008. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Anadarko Petroleum Corporation and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for uncertainty in income taxes in 2007.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Anadarko Petroleum Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 24, 2009 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

 

/s/ KPMG LLP

Houston, Texas

February 24, 2009

 

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ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

 

     Years Ended December 31  
     2008    2007     2006  
millions except per share amounts                  

Revenues and Other

       

Gas sales

   $ 6,254    $ 4,119     $ 4,186  

Oil and condensate sales

     6,502      4,807       4,618  

Natural gas liquids sales

     802      719       594  

Gathering, processing and marketing sales

     1,082      1,487       718  

Gains (losses) on divestitures and other, net

     1,083      4,760       114  
                       

Total

     15,723      15,892       10,230  
                       

Costs and Expenses

       

Oil and gas operating

     1,104      1,101       822  

Oil and gas transportation and other

     553      453       341  

Exploration

     1,369      905       737  

Gathering, processing and marketing

     800      1,025       553  

General and administrative

     866      936       768  

Depreciation, depletion and amortization

     3,194      2,840       1,752  

Other taxes

     1,452      1,234       549  

Impairments

     223      51       327  
                       

Total

     9,561      8,545       5,849  
                       

Operating Income

     6,162      7,347       4,381  

Other (Income) Expense

       

Interest expense

     742      1,092       650  

Other (income) expense, net

     51      (74 )     (6 )

Minority interests

     23             
                       

Total

     816      1,018