10-K 1 h30779e10vk.htm ANADARKO PETROLEUM CORPORATION - DECEMBER 31, 2005 e10vk
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Year Ended December 31, 2005
Commission File No. 1-8968
ANADARKO PETROLEUM CORPORATION
1201 Lake Robbins Drive, The Woodlands, Texas 77380-1046
(832) 636-1000
     
Incorporated in the State of Delaware
  Employer Identification No. 76-0146568
Securities registered pursuant to Section 12(b) of the Act:
Common Stock, par value $0.10 per share
Preferred Stock Purchase Rights
The above Securities are listed on the 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  ü      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  ü .
     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  ü      No           .
     Indicate by check mark if the 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, or a non-accelerated filer. Large accelerated filer  ü Accelerated filer            Non-accelerated filer           .
     Indicate by check mark whether the registrant is a shell company.     Yes                No  ü .
     The aggregate market value of the Company’s common stock held by non-affiliates of the registrant on June 30, 2005 was $19.4 billion based on the average bid and asked price as reported on the New York Stock Exchange.
     The number of shares outstanding of the Company’s common stock as of January 31, 2006 is shown below:
     
Title of Class   Number of Shares Outstanding
Common Stock, par value $0.10 per share   230,441,223
         
Part of    
Form 10-K   Documents Incorporated By Reference
  Part II     Portions of the Anadarko Petroleum Corporation 2005 Annual Report to Stockholders.
  Part III     Portions of the Proxy Statement for the Annual Meeting of Stockholders of Anadarko Petroleum Corporation to be held May 11, 2006 (to be filed with the Securities and Exchange Commission prior to April 3, 2006).


 

TABLE OF CONTENTS
               
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 PART I
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     Fixed Charges and Preferred Stock Dividends
    17  
        17  
        22  
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        23  
           
   
     Executive Officers of the Registrant
    24  
 PART II
        26  
        27  
        28  
        48  
        50  
        107  
        107  
        107  
 PART III
        108  
        108  
        108  
        108  
        108  
 PART IV
        109  
 First Amendment to Anadarko Retirement Restoration Plan
 Amendment to Amended and Restated Anadarko Savings Restoration Plan
 Computation of Ratios of Earnings to Fixed Charges, Combined Fixed Charges and Preferred Stock Dividends
 Portions of the 2005 Annual Report to Stockholders
 List of Significant Subsidiaries
 Consent of KPMG LLP
 Consent of Netherland, Sewell & Associates, Inc.
 Power of Attorney
 Rule 13a-14(a)/15d-14(a) Certification - Chief Executive Officer
 Rule 13a-14(a)/15d-14(a) Certification - Chief Financial Officer
 Section 1350 Certifications
 2005 Report of Netherland, Sewell & Associates, Inc.

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PART I
Item 1. Business
General
      Anadarko Petroleum Corporation is among the largest independent oil and gas exploration and production companies in the world, with 2.45 billion barrels of oil equivalent (BOE) of proved reserves as of December 31, 2005. The Company’s major areas of operations are located in the United States, primarily in Texas, Louisiana, the mid-continent region and the western states, Alaska and in the deepwaters of the Gulf of Mexico, as well as in Canada and Algeria. Anadarko also has production in Venezuela and Qatar and is executing strategic exploration programs in several other countries. The Company actively markets natural gas, oil and natural gas liquids (NGLs) and owns and operates gas gathering systems in its core producing areas. In addition, the Company engages in the hard minerals business 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 where the Company owns most of its fee mineral rights. Anadarko is committed to minimizing the environmental impact of exploration and production activities in its worldwide operations through programs such as carbon dioxide (CO2) sequestration and the reduction of surface area used for production facilities.
      Unless the context otherwise requires, the terms “Anadarko” or “Company” refer to Anadarko Petroleum Corporation and its subsidiaries. The Company’s corporate headquarters are located at 1201 Lake Robbins Drive, The Woodlands, Texas 77380, where the telephone number is (832) 636-1000.
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 Commission (SEC). Anadarko provides access free of charge to all of these SEC filings, as soon as reasonably practicable after filing, 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 filings, please contact: Anadarko Petroleum Corporation, Public Affairs Department, P.O. Box 1330, Houston, Texas 77251-1330 or call (832) 636-1219.
      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, NE, 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, 2005, Anadarko had proved reserves of 7.9 trillion cubic feet (Tcf) of natural gas and 1.1 billion barrels of crude oil, condensate and NGLs. Combined, these proved reserves are equivalent to 2.45 billion barrels of oil or 14.7 Tcf of gas. During 2005, the Company’s reserves increased 3% due to successful exploration and development drilling in the deepwater Gulf of Mexico, onshore United States and Canada. The Company’s reserves have grown 5% over the past three years primarily due to successful exploration and development drilling in the United States and Canada, partially offset by the effect of the disposition of non-core producing properties during 2004. As of December 31, 2005, Anadarko had proved developed reserves of 5.6 Tcf of natural gas and 594 million barrels (MMBbls) of crude oil, condensate and NGLs. Proved developed reserves comprise 62% of total proved reserves.

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      Proved reserve estimates are made by the Company’s engineers. The procedures and controls used by Anadarko in preparing its estimates of proved reserves, as of December 31, 2005, were examined by Netherland, Sewell & Associates, Inc. (NSAI), an independent worldwide petroleum consultant. NSAI reviewed fields comprising 90% of the Company’s total proved reserves, and based on those reviews and investigative analysis, conducted substantive testing on 29% of the Company’s total proved reserves.
      NSAI was able to determine that Anadarko’s estimates of proved oil and gas reserves are, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles in conformity with SEC definitions and guidelines. It should be understood that NSAI’s examination of Anadarko’s oil and gas properties does not constitute a complete reserve study or one of NSAI’s traditional audits. NSAI’s examination consisted of: (1) a review and verification of the internal reserve management and control systems; (2) a series of reviews with each of the asset teams to investigate conformance with SEC definitions and guidelines; and, (3) substantive testing of the reserve estimates, including a detailed evaluation and comparison of the estimates for certain properties.
      Anadarko’s internal controls over reserve additions include using a corporate review team comprised of five technical experts: four members from within Anadarko, who are independent of the operating groups responsible for the reserve estimates, and a member from NSAI. Through participation on the team, NSAI reviewed 79% of the Company’s 2005 proved reserve additions. A copy of the NSAI report is attached as Exhibit 99.1 of this Form 10-K.
      The Company’s estimates of proved reserves, proved developed reserves and proved undeveloped reserves at December 31, 2005, 2004 and 2003 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 Anadarko Petroleum Corporation 2005 Consolidated Financial Statements (Consolidated Financial Statements) under Item 8 of this Form 10-K. The Company files annual estimates of certain proved oil and gas reserves with the U.S. Department of Energy (DOE), which are within 5% of the amounts included in the above estimates.
      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.

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Sales Volumes and Prices
      The following table shows the Company’s annual sales volumes. Volumes for natural gas are in billion cubic feet (Bcf) at a pressure base of 14.73 pounds per square inch. For the computation of million barrels of oil equivalent (MMBOE), six thousand cubic feet (Mcf) of gas is the energy equivalent of one barrel of oil, condensate or NGLs.
      In late 2004, Anadarko completed over $3 billion in pretax asset sales of certain non-core properties through a series of unrelated transactions. Combined, the divested properties represented about 20% of 2004 oil and gas production and about 11% of Anadarko’s year-end 2003 proved reserves. The Company used proceeds from these asset sales to reduce debt, repurchase Anadarko common stock and otherwise to have funds available for reinvestment in other strategic options.
                           
    2005   2004   2003
             
United States
                       
 
Natural gas (Bcf)
    414       499       503  
 
Oil and condensate (MMBbls)
    24       32       34  
 
Natural gas liquids (MMBbls)
    13       16       16  
 
Total (MMBOE)
    106       131       135  
Canada
                       
 
Natural gas (Bcf)
    102       138       140  
 
Oil and condensate (MMBbls)
    3       5       6  
 
Natural gas liquids (MMBbls)
          1       1  
 
Total (MMBOE)
    20       29       30  
Algeria
                       
 
Oil and condensate (MMBbls)
    24       22       19  
 
Total (MMBOE)
    24       22       19  
Other International
                       
 
Oil and condensate (MMBbls)
    8       8       8  
 
Total (MMBOE)
    8       8       8  
Total
                       
 
Natural gas (Bcf)
    516       637       643  
 
Oil and condensate (MMBbls)
    59       67       67  
 
Natural gas liquids (MMBbls)
    13       17       17  
 
Total (MMBOE)
    158       190       192  

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      The following table shows the Company’s annual average sales prices and average production costs. The average sales prices include realized and certain unrealized gains and losses for derivative instruments the Company utilizes to manage price risk related to the Company’s sales volumes. 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. Certain amounts for prior years have been reclassified to conform to the current presentation. Additional information on volumes, prices 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 13 of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
                             
    2005   2004   2003
             
United States
                       
 
Sales price
                       
   
Natural gas (per Mcf)
  $ 7.16     $ 5.18     $ 4.34  
   
Oil and condensate (per barrel)
    44.35       31.65       26.14  
   
Natural gas liquids (per barrel)
    34.56       27.84       21.19  
   
Total (per BOE)
    42.29       30.83       25.47  
 
Production cost (per BOE)
  $ 8.11     $ 6.41     $ 5.49  
Canada
                       
 
Sales price
                       
   
Natural gas (per Mcf)
  $ 7.29     $ 5.17     $ 4.71  
   
Oil and condensate (per barrel)
    49.48       37.37       27.42  
   
Natural gas liquids (per barrel)
    33.75       26.21       21.04  
   
Total (per BOE)
    44.25       31.98       27.89  
 
Production cost (per BOE)
  $ 9.34     $ 8.75     $ 8.01  
Algeria
                       
 
Sales price
                       
   
Oil and condensate (per barrel)
  $ 54.38     $ 34.78     $ 28.43  
 
Production cost (per BOE)
  $ 2.88     $ 2.94     $ 2.44  
Other International
                       
 
Sales price
                       
   
Oil and condensate (per barrel)
  $ 39.37     $ 27.91     $ 23.15  
 
Production cost (per BOE)
  $ 8.40     $ 7.93     $ 8.90  
Total
                       
 
Sales price
                       
   
Natural gas (per Mcf)
  $ 7.19     $ 5.18     $ 4.42  
   
Oil and condensate (per barrel)
    47.92       32.66       26.55  
   
Natural gas liquids (per barrel)
    34.53       27.76       21.18  
   
Total (per BOE)
    44.20       31.34       26.05  
 
Production cost (per BOE)
  $ 7.51     $ 6.43     $ 5.71  
Properties and Activities — United States
Overview Anadarko’s active areas in the United States include the Lower 48 states, Alaska and the Gulf of Mexico. Reserves in the United States comprised 74% of Anadarko’s total proved reserves at year-end 2005. During 2005, the Company’s drilling efforts in the United States resulted in 531 gas wells, 119 oil wells and 5 dry holes. The accompanying maps illustrate by state Anadarko’s net undeveloped and developed lease and fee mineral acreage, number of net producing wells and other data relevant to its domestic onshore and offshore oil and gas operations.

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      The following table presents selected 2005 U.S. operating data by area.
                                                 
    Sales Volumes        
            Drilling Statistics
        Oil and            
    Natural Gas   NGLs   Total   Producing   Wells   Success
    (MMcf/d)   (MBbls/d)   (MBOE/d)   Wells(1)   Drilled(2)   Rate
                         
North Louisiana - Vernon/Ansley
    217             36       316       78       100%  
East Texas - Bossier
    211             35       761       46       100%  
- Carthage
    95       4       20       1,259       28       100%  
Central Texas - Austin Chalk
    95       21       37       1,817       54       100%  
West Texas - Haley
    73             12       30       19       95%  
- Ozona
    45             8       2,082       50       100%  
- EOR
    6       5       7       2,117       66       100%  
Mid-Continent - Kansas/Oklahoma
    84       10       24       1,453       5       100%  
Western States - Tight gas and conventional
    196       14       46       2,120       187       100%  
- Coalbed Methane
    72             12       871       91       100%  
- EOR
    10       13       15       1,553       13       100%  
Other
    27       6       9       598                
                                     
Total Onshore — Lower 48 States
    1,131       73       261       14,977       637          
Alaska
          22       22       48       7 (3)        
Gulf of Mexico
    5       8       9       8       11       64%  
                                     
Total United States
    1,136       103       292       15,033       655       99.2%  
                                     
 
(1)  Gross number of wells in which Anadarko has an interest.
(2)  Includes 631 gross development wells with a 99.8% success rate and 24 gross exploration wells with an 83% success rate.
(3)  The results of these wells are held confidential for competitive reasons.
Onshore — Lower 48 States At the end of 2005, about 60% of the Company’s proved reserves were located onshore in the Lower 48 states. The Company’s 2006 capital budget for this area is about $2 billion and is expected to largely focus on unconventional tight gas plays throughout the region.
North Louisiana The Company’s tight gas drilling program in the Vernon and Ansley areas are focused on development drilling with an increased effort on extending field boundaries. Additionally, a pilot program is underway to test for increased infill drilling opportunities. The Company also has tight gas exploration programs underway in north Louisiana and is encouraged by preliminary results in the Vixen and Liberty Hills prospect areas.
East Texas Development drilling and field extension of the Dowdy Ranch, Dew/ Mimms Creek, Bald Prairie and Marquez fields are the primary focus in the east Texas tight gas Bossier play. Anadarko also continues to be active in its Cotton Valley infill drilling program in the Carthage area.
Central Texas Anadarko’s horizontal drilling program continues to be the focus in central Texas where the objective is to exploit the multiple pay zones and extend field boundaries in the Austin Chalk formation of the Giddings and Brookeland fields. In addition, a successful re-entry program is in place. Anadarko’s exploration activities in the area are currently evaluating the potential of the deep Bossier and Woodbine formations.
West Texas Operations in west Texas are concentrated on increasing production and reserves in the tight gas play of the Haley field where early activity levels and performance is ramping up at a pace comparable to what was achieved in the Company’s two largest domestic gas fields, the Bossier and Vernon. The Company’s efforts also include continued development in the Ozona field and waterflood projects in the Permian basin.
Mid-Continent The Company’s operations in the mid-continent continue to focus on production and development of its long-life, high-margin assets in the Hugoton and Golden Trend fields as well as enhanced oil recovery (EOR) activities in the Norge Marchand field.

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(ONSHORE PROPERTY MAP)
Onshore US map
                                     
    Net   Net   Net   Net
    Undeveloped   Developed   Fee   Producing
    Acres   Acres   Acres   Wells
Onshore:
                               
 
United States
                               
   
Alabama
    228       2,361       11,473        
   
Alaska*
    1,650,929       6,787       7,978       11  
   
Arkansas
    638       1,103       344,604       2  
   
California
    216       318       2,677       1  
   
Colorado
    3,736       12,445       2,898,905       8  
   
Florida
                5,342        
   
Georgia
                2,838        
   
Idaho
                846        
   
Illinois
                1,934        
   
Indiana
                9,912        
   
Iowa
                151        
   
Kansas*
    322,239       304,906       29,906       1,009  
   
Louisiana*
    174,313       39,068       13,131       291  
   
Mississippi
    22,256       1,951       63,880       1  
   
Missouri
                419        
   
Montana
    129,387       2,096       9       59  
   
Nebraska
    4,608       846       27,852       1  
   
Nevada
                433        
   
New Mexico
    2,710       12,915       417       1  
   
North Dakota
    20       1,828             2  
   
Oklahoma*
    66,526       165,605       48,362       516  
   
Oregon
                741        
   
South Carolina
                2,734        
   
Tennessee
                894        
   
Texas*
    527,974       1,019,216       100,425       5,818  
   
Utah
    4,030       22,266       690,322       160  
   
Washington
                2,524        
   
West Virginia
    330                    
   
Wyoming*
    476,903       149,941       4,164,227       2,559  
Office Locations:
                               
 
United States
                               
   
The Woodlands, Texas
                               
*  Drilling activities were conducted in these areas in 2005.

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Western States The majority of the activity in the western states area is associated with developing conventional reservoirs, tight gas, coalbed methane (CBM) and EOR projects. Increased activity is expected in Wamsutter, among other areas in the Land Grant, where the Company’s non-operated positions benefit from net revenue interests greater than its working interest due to Anadarko’s additional royalty interest. The Company operates multiple full-scale CBM properties, as well as active pilot programs. The Company’s operations at the Salt Creek, Monell and Sussex EOR projects (98%-100% working interest (WI)) in Wyoming continue to demonstrate year-over-year increases in oil response due to CO2 injection.
Alaska Anadarko’s activity in Alaska is concentrated primarily on the North Slope. About 3% of the Company’s proved reserves at year-end 2005 were in Alaska. The Company’s capital budget is expected to be about $70 million for Alaska in 2006, which will focus primarily on development activities and preparation for future exploration.
      At the Alpine field (22% WI) on Alaska’s North Slope, a capacity expansion project was completed in 2005 that increased capacity of the Alpine oil processing facility to 140 MBbls/d gross.
      Development of the Nanuq and Fiord satellite fields (both 22% WI) is underway. First production is scheduled for late 2006, with expected peak production of approximately 35 MBbls/d in 2008. Anadarko and the operator are continuing to pursue the state, local and federal permits for three additional Alpine satellites. During the 2004-2005 winter drilling season, the Company participated in exploration wells located in the National Petroleum Reserve-Alaska. Commerciality and potential development scenarios are currently being evaluated.
Gulf of Mexico At year-end 2005, about 11% of the Company’s proved reserves were located offshore in the deepwater of the Gulf of Mexico where Anadarko owns an average 71% interest in 231 blocks and has access to an additional 33 blocks through participation agreements. Anadarko has budgeted about $850 million for capital spending in the deepwater Gulf of Mexico for 2006. In the eastern Gulf of Mexico, facilities will be installed to link several Anadarko-operated natural gas discoveries with the Independence Hub. In the central Gulf of Mexico, the Company expects to bring several high-volume wells on-line at the Marco Polo hub facility and participate in exploration or delineation wells in the foldbelt area.
      Anadarko operates, and a third party owns, the platform and production facilities for the Marco Polo (100% WI) deepwater development project. During 2005, the K2 (52.5% WI) and K2 North (100% WI) fields were tied back subsea to the Marco Polo platform. Production from the K2 field began in 2005. Due to the active 2005 hurricane season, production startup at the K2 North field was delayed several months to January 2006.
      Development plans for a gas processing hub, Independence Hub, and gas export pipeline in the eastern Gulf of Mexico were approved in late 2004. The Company, along with a group of other producers, contracted with a third party to design, construct and own the facility. Anadarko will operate Independence Hub. The facility, capable of processing 1 Bcf of gas per day, will serve several ultra-deepwater natural gas fields, including seven discoveries operated by Anadarko. During 2006, the Company plans to install subsea infrastructure and start the downhole completion phase of previously drilled and suspended wells. Production from Independence Hub is expected to commence in the second half of 2007.
      Anadarko has participation agreements to explore deepwater blocks in the central and western Gulf of Mexico. Anadarko’s exploration program in this area is currently focused on the extensive middle-to-lower Miocene play within the foldbelt area. During 2005, the Company was successful in three out of four exploration wells in this play. The Knotty Head (25% WI) and Big Foot (15% WI) discoveries are outside operated. The Company-operated Genghis Khan (100% WI) discovery and appraisal well is expected to be tied into the Marco Polo complex and on production by the end of 2006. Anadarko expects to remain very active in the region in 2006.
Gas Processing The Company processes gas at various third-party plants under agreements generally structured to provide for the extraction and sale of NGLs in cost efficient plants with flexible volume commitments. The Company has agreements with eight plants in Texas, four plants in the western states area, five plants in the mid-continent area and one plant in the gulf coast area. Anadarko also processes gas and has interests in two Company-operated plants in the western states. Anadarko’s strategy to aggregate gas through Company-owned and third-party gathering systems allows Anadarko to secure processing arrangements in each of the regions where the Company has significant production.

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(OFFSHORE PROPERTY MAP)
Offshore map
                             
    Net   Net   Net
    Undeveloped   Developed   Producing
    Acres   Acres   Wells
Offshore:
                       
 
Gulf of Mexico
                       
   
Western
    426,581              
   
Central*
    293,243       14,366       7  
   
Eastern*
    177,984              
 
California
    2,785              
*  Drilling activities were conducted in these areas in 2005.

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Properties and Activities — Canada
Overview At the end of 2005, about 11% of the Company’s proved reserves were located in Canada. In 2005, net sales volumes from the Company’s properties in Canada accounted for 13% of the Company’s total sales volumes. During 2005, drilling activity in Canada included 40 exploration wells with a success rate of 85% and 108 development wells with a success rate of 98%. The Company’s 2006 capital budget for Canada is expected to be about $450 million and is allocated about 70% to development and 30% to exploration activity. The accompanying map illustrates the Company’s net developed and undeveloped lease and fee mineral acreage, number of net producing wells and other data relevant to its Canadian properties.
Fort St. John During 2005, additional compression was added, increasing capacity in the Buckinghorse area where the Company continues to pursue multi-zone, deep natural gas targets in the area. Anadarko also continues to increase its land holdings in the Buckinghorse and Adsett areas of British Columbia where it holds approximately 1 million net acres.
Grande Prairie In the Peace River Arch area of Northern Alberta, the Company continues to have exploration success in a number of conventional gas plays. In addition, an evolving unconventional gas project is expected to provide future growth opportunity. The Company also has the benefit of operating two gas plants in the region.
Edson The Wild River/ Cecilia drilling program continues to be the most active development area for the Company in Canada. Wild River represents about 30% of Anadarko’s Canadian production and reserve base. This multi-zone area is expected to continue to provide growth opportunities in 2006. Additionally in central Alberta, the Company is evaluating a portion of its acreage for CBM production potential.
Medicine Hat In southern Alberta, Anadarko continues to develop a CO2 pilot project near the Company’s Hays gas plant. In southwest Saskatchewan, the Company began the second of three phases of its 115-well Crane Lake North shallow gas program. With use of new drilling and completion technologies, this mature area continues to provide steady production and exploitation opportunities that can be brought on-line quickly.
Other In the Mackenzie Delta, Anadarko continues its evaluation of encouraging Burnt Lake discoveries on Block EL-384. The Company is closely monitoring development related to the Mackenzie Valley pipeline.
Properties and Activities — Algeria
Overview Anadarko is engaged in exploration, development and production activities in Algeria’s Sahara Desert. At the end of 2005, about 13% of the Company’s proved reserves were located in Algeria where a total of eight fields discovered by the Company were on production. In 2005, net sales volumes from the Company’s properties in Algeria represented 15% of the Company’s total sales volumes. In 2005, Anadarko participated in 20 wells with a success rate of 90%. In addition, the Company participated in nine injection or service wells during the year. The Company’s 2006 capital budget for Algeria is expected to be about $130 million and the budget provides for drilling about 30 development and service wells and four exploration wells, as well as engineering design for a production facility on Block 208.
Contracts and Partners Anadarko’s interest in the Production Sharing Agreement (PSA) for Blocks 404, 208 and 211 is 50% before participation at the exploitation stage by Sonatrach, the national oil and gas enterprise 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 also have an exploration program underway on Blocks 404, 208 and 211 and have exploration licenses, under separate PSAs, for Block 406b (60% interest) and Block 403c/e (33% interest). Anadarko and its joint venture partners fund Sonatrach’s share of exploration costs and are entitled to recover these exploration costs out of production in the exploitation phase.

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(CANADA PROPERTY MAP)
Canada map
                                     
    Net   Net   Net   Net
    Undeveloped   Developed   Fee   Producing
    Acres   Acres   Acres   Wells
Canada:
                               
 
Alberta*
    354,185       231,598       518,600       719  
 
British Columbia*
    879,238       93,996             97  
 
Northwest Territories
    349,614       3,413             4  
 
Saskatchewan*
    74,684       281,933       108,901       2,210  
Office Locations:
                               
 
Canada
                               
   
Calgary, Alberta
                               
   
Edson, Alberta
                               
   
Fort St. John, British Columbia
                               
   
Grande Prairie, Alberta
                               
   
Medicine Hat, Alberta
                               
*  Drilling activities were conducted in these areas in 2005.

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Production and Development On Block 404, production from the HBNS field averaged 125 MBbls/d of oil (gross) and production from five of the satellite fields averaged 31 MBbls/d of oil (gross) in 2005. Production from the HBN field, which extends from Block 404 into Block 403 and is unitized with other companies, averaged 77 MBbls/d of oil (gross) in 2005. Anadarko is also actively involved in the unitized Ourhoud field which is located in the southern portion of Block 404 and extends into Block 406a and Block 405. Production from the Ourhoud field averaged 224 MBbls/d of oil (gross) in 2005. Anadarko has several fields farther south on Block 208. Development of the Block 208 fields is progressing and the new facility is expected to be operational in late 2008 with over 150 MBbls/d of oil production capacity.
Exploration During 2005, the Company participated in two exploration wells on Block 404, one of which was successful. Anadarko’s first exploration well in Block 403c/e was drilled in 2005 and is currently pending testing. During 2006, the Company plans to continue exploratory drilling on Blocks 404 and 406b and evaluate the prospect on Block 403c/e for commerciality.
      Anadarko continually monitors the political situation in Algeria and has taken steps to help ensure the safety of employees and the security of its facilities in the remote regions of the Sahara Desert. Anadarko is unable to predict with certainty any effect political events may have on activity planned for 2006 and beyond. However, no material effect has been experienced to date on the Company’s operations in Algeria, where the Company has had activities since 1989.
Properties and Activities — Other International
Overview The Company’s other international oil and gas production and development operations are located primarily in Venezuela and Qatar. The Company has exploration acreage in Qatar, Indonesia and other selected areas. About 2% of the Company’s total proved reserves were located in other international locations at year-end 2005. During 2005, net sales volumes from the Company’s other international properties accounted for 5% of the Company’s total volumes. In 2006, the Company’s capital budget is expected to range from $200 million to $250 million for other international projects and provides for drilling about 20 development and 20 exploration wells.
Venezuela The Company’s operations consist of the Oritupano-Leona contract area, in which the Company has a non-operated 45% participating interest. The Company’s net oil sales volumes from this 395,000 acre area totaled 5 MMBbls during 2005. The development program in 2005 included drilling ten wells with a 100% success rate and workover activity.
      Anadarko’s operations in Venezuela have been governed by an Operating Service Agreement (OSA) that was entered into between the Company and an affiliate of Petroleos de Venezuela, S.A. (PDVSA), the national oil company of Venezuela. In accordance with the 2005 announcement by the Venezuelan Ministry of Energy and Petroleum, the OSA is under renegotiation. The Company and its operating partner, Petrobras Energia Venezuela (Petrobras), recently signed a Transitory Agreement with PDVSA. For additional information see Other Developments under Item 7 of this Form 10-K.
Qatar The Company had interests in 1,549,000 undeveloped lease acres and 19,000 developed acres in Qatar at year-end 2005. Anadarko is the operator and has a 92.5% interest in the Al Rayyan field, which is part of an Exploration and Production Sharing Agreement covering Blocks 12 and 13. Production from the Al Rayyan field, located on Block 12, totaled 3 MMBbls of oil (net) in 2005. An exploration well is scheduled for 2006 in offshore Block 13, which will be the first well drilled in this block. In Block 4 (100% interest), the Company plans to acquire seismic data in 2006 as partial fulfillment of an exploration work program. Anadarko also has a non-operated interest in an Exploration and Production Sharing Agreement covering offshore Block 11 (49% interest). The exploration period for Block 11 has recently been extended until 2007 to evaluate the commerciality of a prospect drilled on the block in 2005 and to further assess exploration potential.

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Indonesia In 2005, Anadarko entered into an outside operated exploration joint venture agreement, under which the Company gained access to 12 Production Sharing Contracts (PSCs) covering about 7,400,000 gross acres onshore and offshore Indonesia. Anadarko has committed to a three-year, $80 million work program to fund exploration activities. The Company has the opportunity to earn up to a 40% interest in each of the PSCs where a successful exploration well is drilled and upon the approval of a plan of development. In 2004, the Company entered into a PSC for exploration and production rights to the nearly 1,000,000 acre North East Madura III Block (100% interest) offshore Indonesia. Under the terms of the PSC, Anadarko will undertake a three-year exploration phase. Anadarko has purchased 3-D seismic data and plans to drill up to four wells on this block in 2006.
Other Anadarko also has active exploration projects in Tunisia and West Africa, as well as activities in other potential new venture areas overseas.
Drilling Programs
      The Company’s 2005 drilling program focused on known oil and gas provinces in the United States (Lower 48, Alaska and Gulf of Mexico), Canada and Algeria. Exploration activity consisted of 67 wells, including 13 wells in the Lower 48, three wells in Alaska, eight wells offshore in the Gulf of Mexico, 40 wells in Canada, two wells in Algeria and one well in other international locations. Development activity consisted of 769 wells, which included 624 wells in the Lower 48, four wells in Alaska, three wells offshore in the Gulf of Mexico, 108 wells in Canada, 18 wells in Algeria and 12 wells in other international locations.
Drilling Statistics
      The following table shows the results of the oil and gas wells drilled and tested:
                                                         
    Net Exploratory   Net Development    
             
    Productive   Dry Holes   Total   Productive   Dry Holes   Total   Total
                             
2005
                                                       
United States
    10.9       3.2       14.1       375.9       1.0       376.9       391.0  
Canada
    15.7       4.7       20.4       78.5       0.6       79.1       99.5  
Algeria
    0.5       0.2       0.7       2.9       0.3       3.2       3.9  
Other International
    0.5             0.5       5.4             5.4       5.9  
                                           
Total
    27.6       8.1       35.7       462.7       1.9       464.6       500.3  
                                           
2004
                                                       
United States
    25.2       9.4       34.6       484.2       4.7       488.9       523.5  
Canada
    25.5       6.0       31.5       159.9       3.6       163.5       195.0  
Algeria
    1.1       1.5       2.6       2.1             2.1       4.7  
Other International
                      8.1             8.1       8.1  
                                           
Total
    51.8       16.9       68.7       654.3       8.3       662.6       731.3  
                                           
2003
                                                       
United States
    22.2       16.3       38.5       452.1       14.4       466.5       505.0  
Canada
    64.6       7.3       71.9       183.7       5.5       189.2       261.1  
Algeria
    1.5       1.5       3.0       4.0       0.3       4.3       7.3  
Other International
    1.0       2.2       3.2       3.5       1.0       4.5       7.7  
                                           
Total
    89.3       27.3       116.6       643.3       21.2       664.5       781.1  
                                           

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      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, 2005:
                                   
    Wells in the process    
    of drilling or   Wells suspended or
    in active completion   waiting on completion
         
    Exploration   Development   Exploration   Development
                 
United States
                               
 
Gross
    10       55       12       7  
 
Net
    7.5       52.0       9.3       6.5  
Canada
                               
 
Gross
    16       23       40       17  
 
Net
    8.1       12.8       9.9       1.5  
Algeria
                               
 
Gross
    1       1              
 
Net
    0.5       0.2              
Other International
                               
 
Gross
    2             1        
 
Net
    0.9             0.6        
Total
                               
 
Gross
    29       79       53       24  
 
Net
    17.0       65.0       19.8       8.0  
Productive Wells
      As of December 31, 2005, the Company had a working interest ownership in productive wells as follows:
                   
    Oil Wells*   Gas Wells*
         
United States
               
 
Gross
    5,590       9,443  
 
Net
    4,203.0       6,243.0  
Canada
               
 
Gross
    418       3,367  
 
Net
    252.7       2,777.4  
Algeria
               
 
Gross
    152        
 
Net
    31.0        
Other International
               
 
Gross
    292        
 
Net
    137.0        
Total
               
 
Gross
    6,452       12,810  
 
Net
    4,623.7       9,020.4  
 
           
* Includes wells containing multiple completions as follows:
               
 
Gross
    42       1,268  
Net
    29.3       1,077.0  

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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, 2005:
                                                                   
    Developed   Undeveloped        
    Lease   Lease   Fee Minerals   Total
                 
    Gross   Net   Gross   Net   Gross   Net   Gross   Net
thousands                                
United States
                                                               
 
Onshore — Lower 48
    2,530       1,737       2,487       1,736       9,403       8,425       14,420       11,898  
 
Offshore
    28       14       1,313       900                   1,341       914  
 
Alaska
    31       7       3,687       1,672       16       8       3,734       1,687  
                                                 
Total
    2,589       1,758       7,487       4,308       9,419       8,433       19,495       14,499  
                                                 
Canada
    1,017       611       3,897       1,658       628       628       5,542       2,897  
Algeria*
    225       55       3,560       1,071                   3,785       1,126  
Other International
    242       117       7,620       4,270                   7,862       4,387  
 
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.
Marketing, Gathering and Liquefied Natural Gas Properties and Activities
Marketing The Company’s marketing department actively manages the sales of its natural gas, crude oil and NGLs. The Company markets its production to customers at competitive prices, attempting to maximize realized prices while managing credit exposure. The Company also purchases natural gas, crude oil and NGLs volumes for resale primarily from partners and producers near Anadarko’s production. These purchases allow the Company to aggregate larger volumes and attract larger, creditworthy customers, which allows the Company to seek to maximize prices received for the Company’s production.
      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 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 and various derivative instruments. However, 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.
Gas Gathering Anadarko owns and operates seven major gas gathering systems in the United States, where the Company has substantial gas production. The systems are: Antioch Gathering System in the Southwest Antioch field of Oklahoma; Hugoton Gathering System in southwest Kansas; Haley Gathering System in west Texas; Dew Gathering System in east Texas; Pinnacle Gathering System in east Texas; CJV/ SEC Gathering System in the Carthage field of east Texas; and, Vernon Gathering System in the Vernon field of north Louisiana.
      The Company’s major gathering systems have nearly 3,000 miles of pipeline connecting about 3,500 wells and averaged over 950 MMcf/d of gas throughput in 2005. In addition, Anadarko operates numerous other smaller gas gathering systems.
Liquefied Natural Gas The Company is constructing a liquefied natural gas (LNG) receiving terminal at Bear Head, Point Tupper in Nova Scotia. The Bear Head facility is expected to give Anadarko leverage to negotiate for stranded gas production and marketing opportunities from national oil companies and other parties by offering them access to premium North American gas markets. Provincial and federal permits have been obtained including environmental assessments, navigable waters authorization and the LNG tank foundation permit. Front-end engineering design has been completed for a terminal capable of processing up to 1 Bcf per day of regasified LNG.

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      During 2005, construction planning, site preparation and tank foundation work progressed. In addition, contracts were executed for construction of the two LNG storage tanks and the marine jetty. The Company may award an engineering, procurement and construction contract in 2006 with commercial operations expected to commence in late 2008 or 2009. During 2005, Anadarko entered into precedent agreements with a third-party transporter in order to secure long-term delivery of natural gas from the Bear Head facility to prospective markets in eastern Canada and the northeastern United States. The Company continues to hold discussions with several parties for long-term supply. For additional information see Obligations and Commitments under Item 7 of this Form 10-K.
Minerals Properties and Activities
      The Company’s minerals properties contribute to operating income through non-operated joint venture and royalty arrangements in coal, trona and industrial mineral mines across the Company’s extensive fee mineral interest in the Land Grant. The Company reinvests the cash flow from its hard minerals operations primarily into its oil and gas operations.
      The Company’s low sulfur coal deposits, located primarily in southern Wyoming, compete with other western coal producers for industrial and utility boiler markets, which burn the coal to produce steam used to generate electricity. The Company’s coal interests use both surface and underground mining methods of extraction. Because of the high extraction and transportation costs, additional development of the Company’s reserves is dependent on increased coal usage in local markets. In addition to fee mineral ownership of and royalty interests in coal reserves, the Company owns a 50% non-operating interest in Black Butte Coal Company. Black Butte Coal Company produces approximately 3 million tons of coal per year.
      The world’s largest known deposit of trona, comprising 90% of the world’s trona resources, is located in the Green River basin in southwestern Wyoming. Natural soda ash, which is produced by refining trona ore, is used primarily in the production of glass, in the paper and water treatment industries and in the manufacturing of certain chemicals and detergents. The Company owns interests in lands containing approximately 50% of these reserves and has leased a portion of those lands to companies that mine and refine trona. In addition to fee mineral ownership of and royalty interest in trona reserves, the Company owns a 49% non-operating interest in the OCI Wyoming LP (OCI) soda ash refining facility near Green River, Wyoming. The OCI facility typically produces about 2 million tons of soda ash per year.
      During 2004, the Company entered into an agreement whereby it sold a portion of its future royalties associated with existing coal and trona leases to a third party for $158 million, net of transaction costs. The Company conveyed a limited-term nonparticipating royalty interest, which was carved out of its royalty interests, that entitles the third party to receive certain amounts in future coal and trona royalty revenue over an 11-year period. For additional information, see Note 8 — Sale of Future Hard Minerals Royalty Revenues of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Segment and Geographic Information
      Information on operations by segment and geographic location is contained in Note 14 of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Employees
      As of December 31, 2005, the Company had about 3,300 employees. Anadarko considers its relations with its employees to be satisfactory. The Company has had no significant work stoppages or strikes pertaining to its employees.

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Regulatory Matters and Additional Factors Affecting Business
      See Risk Factors under Item 1a 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 counsel employed in the various areas in which the Company has conducted exploration activities, 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 Capital Resources and Liquidity under Item 7 of this Form 10-K.
Ratios of Earnings to Fixed Charges and Earnings to Combined Fixed Charges and Preferred Stock Dividends
                         
    2005   2004   2003
             
Ratio of earnings to fixed charges
    14.42       6.31       5.83  
Ratio of earnings to combined fixed charges and preferred stock dividends
    14.03       6.20       5.71  
      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 before income taxes and fixed charges. 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.
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, 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 oil, natural gas, natural gas liquids (NGLs) and other products or services, the price of oil, natural gas, NGLs and other products or services, implementation of plans concerning the Bear Head liquefied natural gas facility, currency

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exchange rates, 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, the securities or capital markets 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.
          Commodity pricing and demand may limit our productivity and profitability.
      Crude oil prices continue to be affected by political developments worldwide, pricing decisions and production quotas of OPEC and the volatile trading patterns in the commodity futures markets. In addition, in OPEC countries in which we have production such as Algeria, Venezuela and Qatar, when the world oil market is weak, we may be subject to periods of decreased production due to government mandated cutbacks. Natural gas prices also continue to be highly volatile. In periods of sharply lower commodity prices, we may curtail production and capital spending projects, as well as delay or defer drilling wells in certain areas because of lower cash flows. Changes in crude oil and natural gas prices can impact our determination of proved reserves and our calculation of the standardized measure of discounted future net cash flows relating to oil and gas reserves. In addition, demand for oil and gas in the United States and worldwide may affect our level of production.
      Under the full cost method of accounting, a noncash charge to earnings related to the carrying value of our oil and gas properties on a country-by-country basis may occur.
      Whether we will be required to take such a charge depends on the prices for crude oil and natural gas at the end of any quarter, as well as the effect of both capital expenditures and changes in proved reserves during that quarter.
      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 oil and gas operations and properties are subject to numerous federal, state and local laws and regulations relating to environmental protection from the time oil and gas projects commence until abandonment. These laws and regulations govern, among other things:
  •  the amounts and types of substances and materials that may be released into the environment;
 
  •  the issuance of permits in connection with exploration, drilling and production activities;
 
  •  the release of emissions into the atmosphere;
 
  •  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. For a description of certain environmental proceedings in which we are involved, see Legal Proceedings under Item 3 of this Form 10-K.
      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 of oil and gas, including blowouts, cratering and fire, any of which could result in damage to, or destruction of, oil and 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 compensa-

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tion 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.
      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 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.
      We operate in other countries and are subject to political, economic and other uncertainties.
      Our operations in areas outside the United States are subject to various risks inherent in foreign operations. These risks may include, among other things:
  •  loss of revenue, property and equipment as a result of hazards such as expropriation, war, insurrection and other political risks;
 
  •  increases in taxes and governmental royalties;
 
  •  renegotiation of contracts with governmental entities, such as currently occurring in Venezuela;
 
  •  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.
      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 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.

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      Our commodity hedging 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 hedging activities to endeavor to protect ourselves from commodity price volatility, we may be prevented from realizing the full benefits of price increases above the levels of the hedges. In addition, we engage in speculative trading in hydrocarbon commodities, which subjects us to additional risk.
      Our drilling activities may not be productive.
      Drilling for oil and 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;
 
  •  fires, explosions, blow-outs and surface cratering;
 
  •  marine risks such as capsizing, collisions and hurricanes;
 
  •  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.
      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:
  •  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 deepwaters (greater than approximately 1,000 feet) of the Gulf of Mexico, where operations are more difficult and costly than in shallower waters. The deepwaters 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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      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 and examined 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 net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate, whereas 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 not be able 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.
      Failure to find a supply source for our Bear Head LNG project could result in losses associated with sunk costs as well as reimbursement fees for certain predevelopment costs associated with termination of the related long-term gas transportation agreements.
      In 2005, the Company entered into precedent agreements with a third party in order to secure delivery of natural gas from the Bear Head facility in Nova Scotia to prospective markets in eastern Canada and the northeastern United States. The precedent agreements contain certain termination rights, including certain rights related to our failure to timely secure an LNG supply for the Bear Head facility. If these agreements are terminated in connection with such a failure to secure supply, then we will be obligated to pay certain reimbursement fees. There are also certain other acquisition costs that may not be recoverable, such as land, construction and permitting fees.
      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.

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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.
      Repercussions from terrorist activities or armed conflict could harm our business.
      Terrorist activities, anti-terrorist efforts and 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.
      Provisions in our corporate documents and Delaware law could delay or prevent a change of control of us, even if that change would be beneficial to our stockholders.
      Our certificate of incorporation and bylaws contain provisions that may make a change of control of us difficult, even if it would 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, we have adopted a stockholder rights plan, which would cause extreme dilution to any person or group that attempts to acquire a significant interest in us without advance approval of our Board of Directors, while Section 203 of the Delaware General Corporation Law would impose restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock.
      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 extremely 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 2.  Properties
      Information on Properties is contained in Item 1 of this Form 10-K and in Note 19 — Commitments of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

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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 located in Texas, California and Oklahoma. Two companies Anadarko acquired in 2000 and 2002 sold the refineries prior to being acquired by Anadarko. 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.
Litigation The Company is subject to various claims from its royalty owners in the regular course of business as an oil and gas producer, including disputes regarding measurement, costs and expenses beyond the wellhead and basis for royalty valuations. Among such claims, the Company was named as a defendant in a case styled U.S. of America ex rel. Harold E. Wright v. AGIP Company, et al. (the ”Gas Qui Tam case”) filed in September 2000 in the U.S. District Court for the Eastern District of Texas, Lufkin Division. This lawsuit generally alleges that the Company and 118 other defendants undervalued natural gas in connection with a payment of royalties on production from federal and Indian lands. Based on the Company’s present understanding of these various governmental and False Claims Act proceedings, the Company believes that it has substantial defenses to these claims and intends to vigorously assert such defenses. However, if the Company is found to have violated the Civil False Claims Act, the Company could be subject to a variety of sanctions, including treble damages and substantial monetary fines. All defendants jointly filed a motion to dismiss the action on jurisdictional grounds based on Mr. Wright’s failure to qualify as the original source of the information underlying his fraud claims, and the Company filed additional motions to dismiss on separate grounds. In 2005, the trial court declined an early appeal of its order denying the defendants’ motion to dismiss. Meanwhile, the discovery process is ongoing. The court has set a trial date for fall 2007. Management is unable to determine a reasonable range of loss, if any, related to this matter.
Environmental Matters In December 2003, Anadarko Gathering Company voluntarily disclosed the findings of an internal environmental audit for its facilities in Kansas to the Kansas Department of Health and Environment (KDHE). In April 2005, KDHE submitted to Anadarko a Consent Decree and Final Order (Order) alleging certain violations of the Clean Air Act. The Order included an assessment of a proposed penalty amount of $169,000. Anadarko is in discussions with the KDHE to negotiate the final penalty amount.
      The United States Environmental Protection Agency (EPA) has alleged certain violations of the Clean Water Act with respect to the Company’s offshore operations. The Company met with the EPA and agreed to resolve these allegations through the payment of a $60,000 penalty and a Supplemental Environmental Project (SEP) valued at $50,000. The EPA has approved the Company’s SEP proposal and the Company is in the process of implementing this proposal.
      The EPA and the United States Department of Justice (DOJ) have indicated that they are considering a possible enforcement action under the Clean Water Act and the Oil Pollution Act of 1990 against Howell Petroleum Corporation, one of the Company’s subsidiaries, for spills of produced water and oil from its northern Wyoming operations. Representatives of the Company met with the EPA and DOJ in March 2005 to discuss in detail the facts and circumstances surrounding the spills. The EPA and DOJ have completed their factual investigation. The Company is awaiting a response from the EPA and DOJ and is therefore unable to make a reasonable estimate of potential sanctions related to this matter. However, Anadarko believes that the liability with respect to this matter will not have a material effect on 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 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 2005.
Executive Officers of the Registrant
             
    Age at End    
Name   of 2006   Position
         
James T. Hackett
    52    
Chairman of the Board, President and Chief Executive Officer
Robert P. Daniels
    47    
Senior Vice President, Exploration and Production
Karl F. Kurz
    45    
Senior Vice President, Marketing and General Manager, U.S. Onshore
Mark L. Pease
    50    
Senior Vice President, Exploration and Production
Robert K. Reeves
    49    
Senior Vice President, Corporate Affairs & Law and Chief Governance Officer
R. A. Walker
    49    
Senior Vice President, Finance and Chief Financial Officer
Michael O. Bridges
    50    
Vice President, Canada
Mario M. Coll, III
    44    
Vice President, Information Technology Services and Chief Information Officer
Diane L. Dickey
    50    
Vice President, Controller and Chief Accounting Officer
Robert G. Gwin
    43    
Vice President, Treasurer
Preston Johnson, Jr. 
    51    
Vice President, Human Resources
David R. Larson
    49    
Vice President, Investor Relations and Financial Planning
Gregory M. Pensabene
    56    
Vice President, Government Relations
Albert L. Richey
    57    
Vice President, Corporate Development
Charlene A. Ripley
    42    
Vice President, General Counsel, Corporate Secretary and Chief Compliance Officer
Donald R. Willis
    56    
Vice President, Corporate Services
      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 since 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 served as Chief Executive Officer and President of Seagull Energy Corporation from September 1998 until March 1999 and as Chairman of the Board from January 1999 to March 1999, until its merger with Ocean Energy, Inc.
      Mr. Daniels was named 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. Kurz was named Senior Vice President, Marketing and General Manager, U.S. Onshore in 2005. Prior to this position, he served as Vice President, Marketing since 2003 and Manager, Energy Marketing since 2001. He has worked in Anadarko’s marketing department since 2000. Prior to joining the Company, he worked for Vastar Resources in the marketing department since 1995.
      Mr. Pease was named Senior Vice President, Exploration and Production in 2004. Prior to this position, he served as Vice President, U.S. Onshore and Offshore since 2002, Vice President, International and Alaska Operations since September 2001, Vice President, Engineering and Technology since February 2001 and Vice President, Algeria since 1998. He has worked for the Company since 1979.
      Mr. Reeves was named Senior Vice President, Corporate Affairs & Law and Chief Governance Officer in 2004. Prior to joining Anadarko, he served as Executive Vice President, General Counsel and Secretary of Ocean Energy, Inc. and its predecessor companies from 1997 to 2003.

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      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 since 2003 and was President and Chief Financial Officer of 3TEC Energy Corporation from 2000 to 2003. From 1987 to 2000, he worked for Prudential Financial in a variety of merchant banking positions.
      Mr. Bridges was named Vice President, Canada in 2005. Prior to this position he served as General Manager, Canada since 2004, Chief Engineer since 2001 and various other positions since he joined the Company in 1981.
      Mr. Coll was named Vice President, Information Technology Services and Chief Information Officer in 2004. Prior to joining Anadarko, he served as Chief Information Officer and Vice President, Information Management for Devon Energy Corporation from 2003 to 2004, and as Vice President, Operational Planning and Chief Information Officer for Ocean Energy, Inc. and its predecessor companies from 1997 to 2003.
      Ms. Dickey was named Vice President, Controller and Chief Accounting Officer in 2002. Prior to this position, she served as Assistant Controller since 1995. She has worked for the Company since 1978.
      Mr. Gwin was named Vice President, Treasurer in January 2006. Prior to joining Anadarko, he served as Chief Executive Officer of Community Broadband Ventures, LP since November 2004. Prior to this position, he was with Prosoft Learning Corporation, serving as Chairman and Chief Executive Officer since 2002 and Chief Financial Officer since 2000. Prior to this, he held various positions in merchant banking at Prudential Capital, since 1990.
      Mr. Johnson was named Vice President, Human Resources in October 2005. Prior to joining Anadarko, he served as Senior Vice President of Human Resources and Shared Services for CenterPoint Energy since 2000. Prior to this position, he held various positions at Dow Chemical Company.
      Mr. Larson was named Vice President, Investor Relations and Financial Planning in 2005. Prior to this position, he served as Vice President, Investor Relations since 2003 and Manager, Investor Relations since 2000. He worked in the investor relations and other departments at Union Pacific Resources Group Inc. since 1983.
      Mr. Pensabene was named Vice President, Government Relations when he joined the Company in 1997.
      Mr. Richey was named Vice President, Corporate Development in January 2006. Prior to this position, he was Vice President and Treasurer since 1995. He joined the Company as Treasurer in 1987.
      Ms. Ripley was named Vice President, General Counsel and Corporate Secretary in 2004 and in February 2006 assumed the additional role of Chief Compliance Officer. Prior to this position, she served as Vice President and General Counsel since 2003 and Vice President, General Counsel and Secretary of Anadarko Canada Corporation and its predecessor companies since 1998. She served as Senior Counsel for Norcen Energy Resources Limited since 1997.
      Mr. Willis was named Vice President, Corporate Services in 2000. Prior to this position, he served as Manager, Corporate Administration. He has worked for the Company since 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 11, 2006, 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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PART II
Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
      Information on the market price and cash dividends declared per share of common stock is included in Corporate Information in the Anadarko Petroleum Corporation 2005 Annual Report (Annual Report) which is incorporated herein by reference.
      As of January 31, 2006, there were approximately 17,000 record holders of Anadarko common stock. The following table sets forth the amount of dividends paid on Anadarko common stock during the two years ended December 31, 2005:
                                 
    First   Second   Third   Fourth
    Quarter   Quarter   Quarter   Quarter
millions                
2005
  $ 43     $ 43     $ 42     $ 42  
2004
  $ 35     $ 36     $ 35     $ 33  
      The amount of future common stock dividends will depend on earnings, financial condition, capital requirements and other factors, and will be determined by the Directors on a quarterly basis. For additional information, see Dividends under Item 7 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 2005.
                                 
            Total number of   Approximate dollar
    Total       shares purchased   value of shares that
    number of   Average   as part of publicly   may yet be
    shares   price paid   announced plans   purchased under the
Period   purchased(1)   per share   or programs   plans or programs(2)
                 
October
    3,224,394     $ 89.83       3,176,000          
November
    1,309,183     $ 89.79       1,302,900          
December
    1,411,197     $ 93.49       1,381,000          
                         
Fourth Quarter 2005
    5,944,774     $ 90.69       5,859,900     $ 754,000,000  
                         
 
(1)  During the fourth quarter of 2005, 5,859,900 shares were purchased under the Company’s share repurchase programs. During the fourth quarter of 2005, 84,874 shares were related to stock received by the Company for the payment of withholding taxes due on shares issued under employee stock plans.
 
(2)  During October 2005, the Company purchased 3.2 million shares of common stock for $285 million, completing the stock buyback program announced in 2004. In November 2005, the Company announced a new stock buyback program to purchase up to $1 billion in shares of common stock. The Company may purchase additional shares under this program in the future; 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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Item 6. Selected Financial Data
                                                   
    Summary Financial Information*
     
        % change    
dollars in millions, except per share amounts   2005   2005-2004   2004   2003   2002   2001
 
Revenues
  $ 7,100       17     $ 6,079     $ 5,113     $ 3,833     $ 4,718  
Operating Income (Loss)
    4,015       39       2,893       2,199       1,398       (363 )
Net Income (Loss) Available to Common Stockholders before Change in Accounting Principle
    2,466       54       1,601       1,240       825       (183 )
Net Income (Loss)
    2,466       54       1,601       1,287       825       (188 )
Net Cash Provided by Operating Activities
  $ 4,146       29     $ 3,207     $ 3,043     $ 2,196     $ 3,321  
Per Common Share:
                                               
 
Net Income (Loss) — Basic
  $ 10.49       64     $ 6.41     $ 5.16     $ 3.32     $ (0.75 )
 
Net Income (Loss) — Diluted
  $ 10.39       63     $ 6.36     $ 5.09     $ 3.21     $ (0.75 )
 
Dividends
  $ 0.72       29     $ 0.56     $ 0.44     $ 0.325     $ 0.225  
Average Shares Outstanding — Basic
    235       (6 )     250       250       248       250  
Average Shares Outstanding — Diluted
    237       (6 )     252       253       260       250  
Capital Expenditures
  $ 3,437       11     $ 3,090     $ 2,792     $ 2,388     $ 3,316  
 
Total Debt
  $ 3,677       (4 )   $ 3,840     $ 5,058     $ 5,471     $ 5,050  
Stockholders’ Equity
    11,051       19       9,285       8,599       6,972       6,365  
Total Assets
  $ 22,588       12     $ 20,192     $ 20,546     $ 18,248     $ 16,771  
 
Annual Sales Volumes:
                                               
 
Gas (Bcf)
    516       (19 )     637       643       642       695  
 
Oil and Condensate (MMBbls)
    59       (12 )     67       67       75       68  
 
NGLs (MMBbls)
    13       (24 )     17       17       15       15  
 
Total (MMBOE)**
    158       (17 )     190       192       197       199  
 
Average Daily Sales Volumes:
                                               
 
Gas (MMcf/d)
    1,414       (19 )     1,741       1,762       1,760       1,904  
 
Oil and Condensate (MBbls/d)
    162       (12 )     185       184       205       186  
 
NGLs (MBbls/d)
    36       (20 )     45       47       41       42  
 
Total (MBOE/d)
    434       (17 )     520       525       539       546  
 
Oil Reserves (MMBbls)
    1,130       2       1,113       1,226       1,131       1,132  
Gas Reserves (Tcf)
    7.9       5       7.5       7.7       7.2       7.0  
Total Reserves (MMBOE)
    2,449       3       2,367       2,513       2,328       2,305  
 
Number of Employees
    3,300             3,300       3,500       3,800       3,500  
 
  Consolidated for Anadarko Petroleum Corporation and its subsidiaries. Certain amounts for prior years have been reclassified to conform to the current presentation.
**  Natural gas converted to equivalent barrels at the rate of 6,000 cubic feet 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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Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview
General Anadarko Petroleum Corporation’s primary line of business is the exploration, development, production and marketing of natural gas, crude oil, condensate and NGLs. The Company’s major areas of operations are located in the United States, Canada and Algeria. The Company is also active in Venezuela, Qatar and several other countries. The Company’s focus is on adding high-margin oil and natural gas reserves at competitive costs and continuing to develop more efficient and effective ways of exploring for and producing oil and gas. 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 gas reserves, as well as the cost of finding reserves and changes in the levels of costs and expenses required for continuing operations.
      During 2004, Anadarko implemented an asset realignment that resulted in the Company completing over $3 billion in pretax asset sales of certain non-core properties in the latter half of 2004 through a series of unrelated transactions. Combined, the divested properties represented about 11% of Anadarko’s year-end 2003 proved reserves and about 20% of 2004 oil and gas production. The Company used proceeds from these asset sales to reduce debt, repurchase Anadarko common stock and otherwise to have funds available for reinvestment in other strategic options.
Results for the Year Ended December 31, 2005
Selected Data
                         
    2005   2004   2003
millions except per share amounts            
Financial Results
                       
Revenues
  $ 7,100     $ 6,079     $ 5,113  
Costs and expenses
    3,085       3,186       2,914  
Interest expense and other (income) expense
    120       416       225  
Income tax expense
    1,424       871       729  
Net income available to common stockholders
  $ 2,466     $ 1,601     $ 1,287  
Earnings per share — diluted
  $ 10.39     $ 6.36     $ 5.09  
Operating Results
                       
Total proved reserves (MMBOE)
    2,449       2,367       2,513  
Worldwide proved reserve additions (MMBOE)
    291       335       391  
Proved reserve sales in place (MMBOE)
    51       290       14  
Annual sales volumes (MMBOE)
    158       190       192  
Capital Resources and Liquidity
                       
Cash flow from operating activities
  $ 4,146     $ 3,207     $ 3,043  
Capital expenditures
    3,437       3,090       2,792  
Total debt
    3,677       3,840       5,058  
Stockholders’ equity
  $ 11,051     $ 9,285     $ 8,599  
Debt to total capitalization ratio
    25 %     29 %     37 %
Financial Results
Net Income Anadarko’s net income available to common stockholders for 2005 totaled $2.5 billion, or $10.39 per share (diluted), compared to net income available to common stockholders for 2004 of $1.6 billion, or $6.36 per share (diluted). Anadarko had net income available to common stockholders in 2003 of $1.3 billion or $5.09 per share (diluted). The increase in 2005 net income was primarily due to higher net realized commodity prices and lower expenses, partially offset by lower volumes associated with divestitures in late 2004. The increases in earnings per share were also due to lower average shares outstanding in 2005 as a result of stock

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repurchases in late 2004 and throughout 2005. The increase in net income in 2004 was primarily due to higher commodity prices, partially offset by higher expenses.
      In 2003, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations,” and the related cumulative adjustment in the first quarter of 2003 increased net income $47 million or $0.18 per share (diluted).
Revenues
                         
    2005   2004   2003
millions            
Gas sales
  $ 3,709     $ 3,298     $ 2,842  
Oil and condensate sales
    2,838       2,211       1,787  
Natural gas liquids sales
    457       460       365  
Other sales
    96       110       119  
                   
Total
  $ 7,100     $ 6,079     $ 5,113  
                   
      Anadarko’s total revenues for 2005 increased 17% compared to 2004 and total revenues for 2004 increased 19% compared to 2003. The increase in 2005 was primarily due to higher net commodity prices and higher sales volumes from core oil and gas properties, partially offset by lower volumes resulting from the divestiture of non-core properties in late 2004. The increase in revenues in 2004 was primarily due to significantly higher commodity prices, partially offset by slightly lower sales volumes.
      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 and condensate and NGLs. This activity is referred to as price risk management. The impact of price risk management and marketing activities decreased total gas, oil and condensate revenues $204 million during 2005 compared to a decrease of $442 million in 2004. For 2005, these activities resulted in $0.07 per Mcf lower natural gas prices and $3.01 per barrel lower oil prices compared to market prices. For 2004, these activities resulted in $0.24 per Mcf lower natural gas prices and $4.37 per barrel lower oil prices compared to market prices. In 2003, the impact of price risk management and marketing activities decreased total gas, oil and condensate revenues $274 million. For 2003, these activities resulted in $0.28 per Mcf lower natural gas prices and $1.42 per barrel lower oil prices compared to market prices.
Analysis of Sales Volumes
                           
    2005   2004   2003
             
Barrels of Oil Equivalent (MMBOE)
                       
 
United States
    106       131       135  
 
Canada
    20       29       30  
 
Algeria
    24       22       19  
 
Other International
    8       8       8  
                   
 
Total
    158       190       192  
                   
Barrels of Oil Equivalent per Day (MBOE/d)
                       
 
United States
    292       358       368  
 
Canada
    55       79       83  
 
Algeria
    65       61       52  
 
Other International
    22       22       22  
                   
 
Total
    434       520       525  
                   
      During 2005, Anadarko’s daily sales volumes decreased 17% compared to 2004 due to lower sales volumes in the United States and Canada as a result of divestitures of non-core properties in late 2004, representing about 20% or 110 MBOE/d of 2004 sales volumes. This decrease was partially offset by higher volumes associated with successful drilling onshore in the United States, facility expansion in Alaska and higher volumes in Algeria. During 2004, Anadarko’s daily sales volumes decreased slightly compared to 2003 primarily due to the

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divestitures in late 2004, partially offset by higher volumes in Algeria due to the expansion of production facilities and the timing of cargo liftings.
      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. See Energy Price Risk under Item 7a of this Form 10-K.
Natural Gas Sales Volumes and Average Prices
                           
    2005   2004   2003
             
United States (Bcf)
    414       499       503  
 
MMcf/d
    1,136       1,363       1,379  
 
Price per Mcf
  $ 7.16     $ 5.18     $ 4.34  
Canada (Bcf)
    102       138       140  
 
MMcf/d
    278       378       383  
 
Price per Mcf
  $ 7.29     $ 5.17     $ 4.71  
Total (Bcf)
    516       637       643  
 
MMcf/d
    1,414       1,741       1,762  
 
Price per Mcf
  $ 7.19     $ 5.18     $ 4.42  
      Anadarko’s daily natural gas sales volumes in 2005 were down 19% compared to 2004 primarily due to the impact of divestitures in the United States and Canada in late 2004, partially offset by higher volumes associated with successful drilling onshore in the United States. The Company’s daily natural gas sales volumes for 2004 were down slightly compared to 2003 primarily due to slightly lower sales volumes in the United States due to the impact of divestitures in late 2004 and natural production declines in areas that were targeted for divestiture, partially offset by higher volumes associated with successful drilling onshore in the United States. Production of natural gas is generally not directly affected by seasonal swings in demand.
      The Company’s average natural gas price in 2005 increased 39% compared to 2004. The increase in prices in 2005 is attributed to continued strong demand in North America and an active hurricane season in the Gulf of Mexico impacting supply and infrastructure. The higher prices include the impact of price risk management activities on 22% of natural gas sales volumes during 2005 that reduced the Company’s exposure to low prices and limited participation in higher prices. The Company’s average natural gas price in 2004 increased 17% compared to 2003. Continued strong demand in North America contributed to higher natural gas prices. The higher prices in 2004 include the impact of price risk management activities on 36% of natural gas sales volumes during 2004. As of December 31, 2005, the Company had only 1% of its anticipated natural gas wellhead sales volumes for 2006 subject to derivative instruments associated with price risk management. See Energy Price Risk under Item 7a of this Form 10-K.

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Crude Oil and Condensate Sales Volumes and Average Prices
                           
    2005   2004   2003
             
United States (MMBbls)
    24       32       34  
 
MBbls/d
    68       88       93  
 
Price per barrel
  $ 44.35     $ 31.65     $ 26.14  
Canada (MMBbls)
    3       5       6  
 
MBbls/d
    7       14       17  
 
Price per barrel
  $ 49.48     $ 37.37     $ 27.42  
Algeria (MMBbls)
    24       22       19  
 
MBbls/d
    65       61       52  
 
Price per barrel
  $ 54.38     $ 34.78     $ 28.43  
Other International (MMBbls)
    8       8       8  
 
MBbls/d
    22       22       22  
 
Price per barrel
  $ 39.37     $ 27.91     $ 23.15  
Total (MMBbls)
    59       67       67  
 
MBbls/d
    162       185       184  
 
Price per barrel
  $ 47.92     $ 32.66     $ 26.55  
      Anadarko’s daily crude oil and condensate sales volumes for 2005 decreased 12% compared to 2004 due to the impact of divestitures in the United States and Canada in late 2004. These decreases were partially offset by higher volumes in the United States associated with expansion of production facilities in Alaska and successful drilling in the western states and higher volumes in Algeria. Anadarko’s daily crude oil and condensate sales volumes for 2004 were essentially flat with 2003. Higher sales volumes in Algeria and production startup in mid-2004 at the Marco Polo deepwater platform were mostly offset by lower sales volumes in the United States and Canada, due to the impact of divestitures in late 2004 and natural production declines in areas that were targeted for divestitures. Production of oil usually is not affected by seasonal swings in demand.
      Anadarko’s average crude oil price in 2005 increased 47% compared to 2004. The higher crude oil prices in 2005 were attributed to continued political unrest in the Middle East, increased worldwide demand and the impact of hurricanes in the Gulf of Mexico on oil production and infrastructure. The higher prices in 2005 include the impact of price risk management activities on 28% of crude oil and condensate sales volumes that reduced the Company’s exposure to low prices and limited participation in higher prices. The Company’s average crude oil price in 2004 increased 23% compared to 2003. The higher crude oil prices in 2004 were attributed to continuing political unrest in the Middle East and increased worldwide demand. The higher prices include the impact of price risk management activities on 36% of crude oil and condensate sales volumes during 2004. As of December 31, 2005, the Company had less than 1% of its anticipated oil and condensate volumes for 2006 subject to derivative instruments associated with price risk management.
Natural Gas Liquids Sales Volumes and Average Prices
                           
    2005   2004   2003
             
Total (MMBbls)
    13       17       17  
 
MBbls/d
    36       45       47  
 
Price per barrel
  $ 34.53     $ 27.76     $ 21.18  
      Anadarko’s daily NGLs sales volumes in 2005 were down 20% compared to 2004, primarily due to the impact of divestitures in the United States in late 2004. The Company’s 2004 daily NGLs sales volumes were down slightly compared to 2003, primarily due to a decrease in volumes of natural gas processed.
      During 2005, average NGLs prices increased 24% compared to 2004. The 2004 average NGLs prices increased 31% compared to 2003. NGLs production is dependent on natural gas and NGLs prices as well as the economics of processing the natural gas to extract NGLs.

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Costs and Expenses
                         
    2005   2004   2003
millions            
Direct operating
  $ 544     $ 682     $ 630  
Transportation and cost of product
    302       250       198  
General and administrative
    442       423       392  
Depreciation, depletion and amortization
    1,343       1,447       1,297  
Other taxes
    376       312       294  
Impairments related to oil and gas properties
    78       72       103  
                   
Total
  $ 3,085     $ 3,186     $ 2,914  
                   
      During 2005, Anadarko’s costs and expenses decreased 3% compared to 2004 due to the following factors:
  —  Direct operating expense was down $126 million primarily due to the impact of properties divested in late 2004 and down $12 million due to 2004 severance and other costs related to divestitures and reorganization efforts.
  —  Transportation and cost of product expense increased 21% primarily due to higher transportation expenses and NGLs transportation, fractionation and processing costs. The $28 million increase in transportation cost was primarily due to a change in the Company’s marketing strategy whereby the Company is transporting a higher percentage of its natural gas volumes to higher priced markets. The $12 million increase in NGLs transportation and fractionation cost was primarily due to a change in the Company’s marketing strategy whereby the Company is fractionating its raw NGLs stream into the individual products in order to obtain higher sales proceeds for NGLs. Cost of product was up about $12 million primarily due to higher NGLs processing costs as a result of increased natural gas prices. These cost increases are offset by higher natural gas, NGLs and other sales revenues.
  —  General and administrative (G&A) expense increased 4% primarily due to an increase of $51 million in compensation, pension and other postretirement benefits expenses attributed primarily to the rising cost of attracting and retaining a highly qualified workforce, including the Company’s decision to provide a more performance-based compensation program to a broader base of employees. This increase also reflects the continued upward pressure on benefits expenses, including the impact of lower discount rates on estimated pension and other postretirement benefits expenses. Consulting, audit, rent and other miscellaneous expenses combined increased by $14 million. These increases were partially offset by a $28 million decrease in legal expenses and a decrease of $19 million due to 2004 severance and other costs related to divestitures and reorganization efforts.
  —  Depreciation, depletion and amortization (DD&A) expense decreased 7%. DD&A expense includes decreases of $242 million related to lower production volumes and $11 million related to lower asset retirement obligation accretion expense, both primarily due to the impact of 2004 divested properties. These decreases were partially offset by an increase of $149 million primarily due to higher costs associated with finding and developing oil and gas reserves (including the transfer of excluded costs to the DD&A pool).
  —  Other taxes increased 21% primarily due to higher net realized commodity prices, partially offset by the impact of properties divested in 2004.
  —  Impairments of oil and gas properties in 2005 include $35 million related to unsuccessful exploration activities in Tunisia, $30 million related to exploration activities at various international locations and $13 million related to the disposition of properties in Oman.
      During 2004, Anadarko’s costs and expenses increased 9% compared to 2003 due to the following factors:
  —  Direct operating expense, which was up 8% in 2004, includes $12 million in severance and other costs related to 2004 divestiture and reorganization efforts. Excluding these costs, direct operating expenses increased 6% primarily due to higher enhanced oil recovery activity in the western states, production beginning in mid-2004 at the Marco Polo platform, the acquisition of producing properties in mid-2003 and a general increase in service and gathering costs, partially offset by a decrease associated with property divestitures in late 2004.

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  —  Transportation and cost of product expense increased 26%. The increase includes a $60 million increase in transportation expense due to higher transportation rates and marketing volumes. This increase was partially offset by a lower cost of product as a result of a decrease in gas volumes processed into NGLs.
  —  G&A expense increased 8%. In 2004, G&A expense included $19 million in severance and other costs related to 2004 divestitures and reorganization efforts. In 2003, G&A expense included $40 million in restructuring costs related to a cost reduction plan implemented in July and $32 million in benefits and salaries expenses related to executive transitions. Excluding these costs, G&A expense increased 26% in 2004 primarily due to legal settlements of $37 million and an increase of $30 million in employee bonus plan expense primarily due to the Company exceeding internal performance goals.
  —  DD&A expense increased 12%. DD&A expense increases include about $145 million primarily due to higher costs associated with finding and developing oil and gas reserves (including the transfer of excluded costs to the DD&A pool) and $11 million due to higher depreciation of general properties and asset retirement obligation accretion expense, partially offset by a decrease of $6 million related to slightly lower production volumes.
   Other taxes increased 6% primarily due to higher commodity prices in 2004.
  —  Impairments of oil and gas properties in 2004 were due to a $62 million ceiling test impairment for Qatar as a result of lower future production estimates and unsuccessful exploration activities and $10 million related to other international activities.

Interest Expense and Other (Income) Expense
                         
    2005   2004   2003
millions            
Interest Expense
                       
Gross interest expense
  $ 270     $ 334     $ 366  
Premium and related expenses for early retirement of debt
          104       8  
Capitalized interest
    (69 )     (86 )     (121 )
                   
Net interest expense
    201       352       253  
                   
Other (Income) Expense
                       
Operating lease settlement
          63        
Firm transportation keep-whole contract valuation
    (56 )     (1 )     (9 )
Interest income
    (27 )     (16 )     (3 )
Foreign currency exchange (gains) losses
          2       (19 )
Other
    2       16       3  
                   
Total Other (Income) Expense
    (81 )     64       (28 )
                   
Total
  $ 120     $ 416     $ 225  
                   
Interest Expense Anadarko’s gross interest expense decreased 19% during 2005 compared to 2004 primarily due to lower average outstanding debt. Interest expense for 2004 included $104 million of premiums and related expenses for the early retirement of debt in 2004. Gross interest expense in 2004 decreased 9% compared to 2003 due to lower average outstanding debt. Debt has decreased $1.4 billion since December 31, 2003. See Capital Resources and Liquidity.
      In 2005, capitalized interest decreased by 20% compared to 2004. In 2004, capitalized interest decreased by 29% compared to 2003. The 2005 and 2004 decreases were primarily due to lower capitalized costs that qualify for interest capitalization. For additional information about the Company’s policies regarding costs excluded and capitalized interest see Critical Accounting Policies and Estimates — Costs Excluded and Capitalized Interest.
Other (Income) Expense For 2005, the Company had other income of $81 million compared to other expense of $64 million for 2004. The favorable change of $145 million was primarily due to a $63 million loss in 2004 related to an operating lease settlement for the Corpus Christi West Plant Refinery, a favorable change of $55 million related to the effect of higher market values for firm transportation subject to the keep-whole agreement, a $14 million favorable change in other, primarily related to environmental remediation expense in 2004, and an increase in interest income of $11 million.

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      For 2004, the Company had other expense of $64 million compared to other income of $28 million for 2003. The unfavorable change of $92 million was primarily due to a $63 million loss in 2004 related to the operating lease settlement, a $21 million unfavorable change primarily due to a decrease in Canadian foreign currency exchange gains and an $8 million unfavorable change related to the effect of lower market values for firm transportation subject to the keep-whole agreement. For additional information, see Note 21 — Contingencies of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K and Energy Price Risk and Foreign Currency Risk under Item 7a of this Form 10-K.
Income Tax Expense
                         
    2005   2004   2003
millions except percentages            
Income tax expense
  $ 1,424     $ 871     $ 729  
Effective tax rate
    37 %     35 %     37 %
      For 2005, income taxes increased 63% compared to 2004 primarily due to higher income before income taxes. For 2004, income taxes increased 19% compared to 2003 primarily due to higher income before income taxes, partially offset by the effect of the reduction in the Alberta provincial tax rate during 2004 and other items.
      The variances from the 35% statutory rate and the variances between years are caused by income taxes related to foreign activities, state income taxes, cross border financing, Canadian income tax rate reduction, excess U.S. foreign tax credits generated in the current year and other items.
      Current tax expense related to the estimated taxable gains from the 2004 divestitures was recorded during 2004 with a corresponding reduction to deferred tax expense. As a result, total income tax expense and the effective tax rate for 2004 were not impacted by the divestitures.
Operating Results
Proved Reserves Anadarko focuses on growth and profitability. Reserve replacement is the key to growth and future profitability depends on 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.
                         
    2005   2004   2003
MMBOE            
Proved Reserves
                       
Beginning of year
    2,367       2,513       2,328  
Reserve additions and revisions
    291       335       391  
Sales in place
    (51 )     (290 )     (14 )
Production
    (158 )     (191 )     (192 )
                   
End of year
    2,449       2,367       2,513  
                   
Proved Developed Reserves
                       
Beginning of year
    1,517       1,727       1,568  
                   
End of year
    1,524       1,517       1,727  
                   
      The Company’s proved natural gas reserves at year-end 2005 were 7.9 Tcf compared to 7.5 Tcf at year-end 2004 and 7.7 Tcf at year-end 2003. Anadarko’s proved crude oil, condensate and NGLs reserves at year-end 2005 were 1.1 billion barrels compared to 1.1 billion barrels at year-end 2004 and 1.2 billion barrels at year-end 2003. Crude oil, condensate and NGLs comprised about half of the Company’s proved reserves at year-end 2005, 2004 and 2003.
      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

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necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Decreases in prices, for example, may cause a reduction in some proved reserves due to reaching economic limits sooner.
Reserve Additions and Revisions During 2005, the Company added 291 MMBOE of proved reserves as a result of additions (extensions, discoveries, improved recovery and purchases in place) and revisions.
Additions During 2005, Anadarko added 314 MMBOE of proved reserves. Of this amount, 309 MMBOE were added as a result of successful drilling in the deepwater Gulf of Mexico and fields in the north Louisiana Vernon, east Texas Bossier, west Texas Haley and Canadian Wild River areas and successful improved recovery operations in Wyoming. During 2004, Anadarko added 389 MMBOE of proved reserves as a result of successful drilling in its core onshore North American properties and the deepwater Gulf of Mexico, successful improved recovery operations in Wyoming and minor producing property acquisitions. During 2003, Anadarko added 396 MMBOE of proved reserves through successful drilling in its core North American properties, successful improved recovery operations in Wyoming and producing property acquisitions.
      The Company expects the majority of future reserve additions to come from 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.
Revisions Total revisions in 2005 were (23) MMBOE or 1% of the beginning of year reserve base. Performance revisions of (36) MMBOE included the impact of government imposed limits on production in Venezuela, as well as a reduction of NGLs reserves in Algeria resulting from a change in project scope, which improved the value of the project but decreased the ultimate reserves recovery. North America, which represents 84% of the Company’s proved reserves, had a (1) MMBOE or negative 0.1% performance revision from the year-end 2004 proved reserves. A (6) MMBOE revision in Canada was almost entirely offset by a 5 MMBOE revision in the United States. Price revisions of 14 MMBOE were primarily due to the impact of higher year-end prices, partially offset by the impact of recalculating the equity barrels under the service contract in Venezuela as a result of higher prices. Total revisions for 2004 and 2003 were (54) MMBOE and (5) MMBOE, respectively. Revisions in 2004 related primarily to performance revisions of the Company’s reserves at Marco Polo and other properties, partially offset by positive revisions in other areas.
      An analysis of Anadarko’s proved reserve revisions split between performance and price revisions and shown as a percentage of the previous year-end proved reserves is presented in the following graph. During the 10-year period 1996 — 2005, Anadarko’s annual reserve revisions, up or down, have been below 5% of the previous year-end proved reserve base for both types of revisions. The Company believes this is an indicator of the validity of the Company’s processes for estimating reserves. In the aggregate, over the past decade, the average reserve revision has been a negative 0.7% and the average performance-related reserve revision has been a negative 0.6%.
(GRAPH)
History of Reserve Revisions
         
    Performance    
    Revision % of   Price Revision %
    Previous Year-   of Previous Year-
    End Reserve   End Reserve
    Base   Base
1996
  0.1%   1.5%
1997
  3.5%   (4.0)%
1998
  (2.0)%   (4.1)%
1999
  (4.0)%   4.9%
2000
  2.9%   1.1%
2001
  (0.3)%   (2.3)%
2002
  (1.7)%   0.7%
2003
  (0.5)%   0.3%
2004
  (2.2)%   (0.1)%
2005
  (1.5)%   0.5%
10-year average: -0.7% total; -0.6% excluding price

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Sales in Place In 2005, the Company sold properties located in the United States, Oman and Canada representing 25 MMBOE, 25 MMBOE and 1 MMBOE of proved reserves, respectively. In 2004, Anadarko sold properties located in the United States and Canada representing 226 MMBOE and 64 MMBOE of proved reserves, respectively. In 2003, Anadarko sold properties in the United States and Canada representing 8 MMBOE and 6 MMBOE of proved reserves, respectively.
Proved Undeveloped Reserves To improve investor confidence and provide transparency regarding the Company’s reserves, Anadarko reports the status of its proved undeveloped reserves (PUDs) annually. The Company annually reviews all PUDs, with a particular focus on those PUDs that have been booked for three or more years, to ensure that there is an appropriate plan for development. Generally, onshore United States PUDs are converted to proved developed reserves within two years. Certain projects, such as improved oil recovery, arctic development, deepwater development and many international programs, often take longer, sometimes beyond five years. Over 50% of the Company’s PUDs booked prior to 2002 are in Algeria and are being developed according to an Algerian government approved plan. The remaining PUDs booked prior to 2002 are primarily associated with Alaska and ongoing programs in the onshore United States for improved recovery.
      The following data presents the Company’s PUDs vintage, geographic location and percentage of total proved reserves as of December 31, 2005:
(GRAPH)
Worldwide Proved Undeveloped Reserves
         
    PUDs   Cumulative
Years from Initial Booking   (MMBOE)   % of PUDs
0
  295   32%
 
1
  208   54%
 
2
  191   75%
 
3
  46   80%
 
4
  94   90%
 
5+
  91   100%
Worldwide Proved Undeveloped Reserves Analysis
                         
            Percentage of
    PUDs   Percentage of   Total Proved
    (MMBOE)   Total PUDs   Reserves
Country            
United States
    706       76 %     29 %
Algeria
    129       14 %     5 %
Canada
    63       7 %     3 %
Other International
    27       3 %     1 %
                   
Total
    925       100 %     38 %
                   

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      The following graph shows the change in PUDs over the last three years, detailing the changes based on the year the PUDs were originally booked. It illustrates the Company’s effectiveness in converting PUDs to developed reserves over the periods shown.
(GRAPH)
Worldwide Proved Undeveloped Reserves PUD Reserves by Year PUD Booked
                                 
    End of Year (EOY)   End of Year (EOY)   End of Year (EOY)   End of Year (EOY)
Years PUD   2005 PUDs   2004 PUDs   2003 PUDs   2002 PUDs
Booked   (MMBOE)   (MMBOE)   (MMBOE)   (MMBOE)
2005 PUDs
    295                          
2004 PUDs
    208       310                  
2003 PUDs
    191       221       328          
2002 PUDs
    46       64       100       154  
2001 PUDs
    94       132       184       340  
2000 PUDs
    34       47       58       78  
Pre 2000 PUDs
    57       76       116       188  
      In addition, over the last 10 years, Anadarko’s compound annual growth rate (CAGR) for proved reserves has been 17% and for production has been 15%. The Company’s history of production growth relative to proved reserve growth is shown below. This data demonstrates the Company’s ability to convert proved reserves to production in a timely manner. The decrease in proved reserves in 2004 and production in 2005 is primarily related to properties sold in 2004.
(GRAPH)
Reserves Converted to Production
                 
    Proved Reserves (MMBOE)   Produced (MBOE/d)
1995
    526       109  
1996
    601       104  
1997
    708       120  
1998
    935       129  
1999
    991       135  
2000
    2,061       306  
2001
    2,305       546  
2002
    2,328       539  
2003
    2,513       525  
2004
    2,367       520  
2005
    2,449       434  
CAGR
    17       15  

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Future Net Cash Flows At December 31, 2005, the present value (discounted at 10%) of future net cash flows from Anadarko’s proved reserves was $29.3 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 held flat for the life of the reserves, adjusted for any contractual provisions. The increase of $10.6 billion or 57% in 2005 compared to 2004 is primarily due to higher natural gas and oil prices at year-end 2005 and successful exploration and development drilling in North America. 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.
Marketing Strategies
Overview The Company’s marketing department manages sales of its natural gas, crude oil and NGLs. In marketing its production, the Company attempts to maximize realized prices while managing credit exposure. 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.
      The Company also purchases natural gas, crude oil and NGLs volumes for resale primarily from partners and producers near Anadarko’s production. These purchases allow the Company to aggregate larger volumes, attract larger, more creditworthy customers and facilitate its efforts to maximize prices received for the Company’s production.
      The Company may also engage in trading activities for the purpose of generating profits from exposure to changes in market prices of gas, oil, condensate and NGLs. However, the Company does not engage in market-making practices nor does it trade in any non-energy-related commodities. 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.
      Since 2002, all segments of the energy market have experienced increased scrutiny of their financial condition, liquidity and credit. This has been reflected in rating agency credit downgrades of many merchant energy trading companies. Anadarko has not experienced any material financial losses associated with credit deterioration of third-party purchasers; however, 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 supply 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. The tightening of the natural gas supply and demand fundamentals has resulted in extremely volatile natural gas prices, which is expected to continue. Anadarko markets its equity 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 services 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. Included in this strategy is the use of leased natural gas storage facilities and various derivative instruments.
      In 2005, 2004 and 2003, approximately 7%, 12% and 35%, respectively, of the Company’s gas production was sold under long-term contracts to Duke Energy Corporation (Duke). These sales represent 4%, 6% and 22% of total revenues in 2005, 2004 and 2003, respectively. The contracts that represented most of the 2004 and 2003 volumes expired during 2004. The Company integrated the marketing of the natural gas previously sold to Duke into its current marketing operations and now sells it to various purchasers at market prices. Volumes sold to Duke under the long-term contracts were at market prices.
      A company Anadarko acquired in 2000 was a party to several long-term firm gas transportation agreements that supported its gas marketing program within its gathering, processing and marketing business segment, which was sold in 1999 to Duke. Most of these agreements were transferred to Duke in the disposition. One agreement

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was retained, but is managed and operated by Duke. Anadarko is not responsible for the operations of the contracts and does not utilize the associated transportation assets to transport the Company’s natural gas. As part of the disposition, Anadarko pays Duke if transportation market values fall below the fixed contract transportation rates, while Duke pays Anadarko if the transportation market values exceed the contract transportation rates (keep-whole agreement). The term of the keep-whole agreement extends through February 2009. The Company may periodically use derivative instruments to reduce its exposure to potential decreases in future transportation market values. While derivatives are intended to reduce the Company’s exposure to declines in the market value of firm transportation, they also limit the potential to benefit from increases in the market value of firm transportation.
      In January 2006, Anadarko and Duke entered into an agreement to terminate the keep-whole agreement prospectively, subject to the satisfaction of certain conditions precedent. The agreement also provides that Duke will transfer to Anadarko a portfolio of certain gas transportation agreements subject to the keep-whole agreement on several U.S. and Canadian pipelines, effective April 1, 2006. The Company believes the agreement will not have a material effect on its future consolidated financial position, results of operations or cash flow.
Crude Oil, Condensate and NGLs Anadarko’s crude oil, condensate and NGLs revenues are derived from production in the U.S., Canada, Algeria and other international areas. Most of the Company’s U.S. crude oil and NGLs production is sold under 30-day “evergreen” contracts with prices based on market indices and adjusted for location, quality and transportation. Most of the Company’s Canadian oil production is sold on a term basis of one year or greater. Oil from Algeria and other international areas 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 like jet and diesel fuel. 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 leased NGLs storage facilities and various derivative instruments.
Gas Gathering Systems and Processing Anadarko’s investment in gas gathering operations allows the Company to better manage its gas production, improve ultimate recovery of reserves, enhance the value of gas production and expand marketing opportunities. The Company has invested about $206 million to build or acquire gas gathering systems over the last 5 years. The vast majority of the gas flowing through these systems is from Anadarko-operated wells.
      The Company processes gas at various third-party plants under agreements generally structured to provide for the extraction of NGLs in efficient plants with flexible commitments. Anadarko also processes gas and has interests in two Company-operated plants. Anadarko’s strategy to aggregate gas through Company-owned and third-party gathering systems allows Anadarko to secure processing arrangements in each of the regions where the Company has significant production.
Capital Resources and Liquidity
Overview Anadarko’s primary source of cash during 2005 was cash flow from operating activities. The Company used cash flow primarily to fund its capital spending program, repurchase Anadarko common stock and pay dividends. In addition, the Company used $170 million of cash from the 2004 divestitures to retire debt in 2005. The Company funded its capital investment programs in 2004 and 2003 primarily through cash flow from operating activities. In 2004, the Company completed over $3 billion in various pretax asset sales. The Company used proceeds from these asset sales to reduce debt, repurchase Anadarko common stock and otherwise to have funds available for reinvestment in other strategic options.
Cash Flow from Operating Activities Anadarko’s cash flow from operating activities in 2005 was $4.1 billion compared to $3.2 billion in 2004 and $3.0 billion in 2003. The increase in 2005 cash flow, attributed to higher net realized commodity prices, was partially offset by lower sales volumes resulting from the 2004 divestitures. The increase in 2004 cash flow compared to 2003 was attributed to the significant increase in commodity prices, partially offset by higher costs and expenses.
      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

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prices in prior years. Anadarko’s long-term cash flow from operating activities is dependent on commodity prices, reserve replacement and the level of costs and expenses required for continued operations.
Capital Expenditures The following table shows the Company’s capital expenditures by category.
                           
    2005   2004   2003
millions            
Development
  $ 2,278     $ 2,348     $ 1,846  
Exploration
    722       513       713  
Property acquisitions
                       
 
Development — proved
    45       3       203  
 
Exploration — unproved
    269       155       124  
                   
Total oil and gas costs incurred*
    3,314       3,019       2,886  
 
Less: Asset retirement costs
    (37 )     (52 )     (187 )
 
Plus: Asset retirement expenditures
    29       26       20  
                   
Total oil and gas capital expenditures*
    3,306       2,993       2,719  
Gathering and other
    131       97       73  
                   
Total
  $ 3,437     $ 3,090     $ 2,792  
                   
 
Oil and gas costs incurred represent capitalized costs related to finding and developing oil and gas reserves. Capital expenditures represent actual cash outlays excluding corporate acquisitions.
      Anadarko’s capital spending increased 11% in 2005 and 2004 compared to the previous periods. The increase in 2005 includes higher exploration costs in the deepwater Gulf of Mexico. Additionally, both 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 acquisitions in 2005 and 2004 primarily relate to exploratory nonproducing leases. The acquisitions in 2003 primarily relate to the acquisition of producing properties and exploratory nonproducing leases.
      Anadarko participated in a total of 836 gross wells in 2005 compared to 1,069 gross wells in 2004 and 1,069 gross wells in 2003.
      The following table provides additional detail of the Company’s drilling activity in 2005 and 2004.
                                   
    Gas   Oil   Dry   Total
                 
2005 Exploratory
                               
 
Gross
    48       7       12       67  
 
Net
    22.8       4.8       8.1       35.7  
2005 Development
                               
 
Gross
    617       148       4       769  
 
Net
    365.2       97.5       1.9       464.6  
2004 Exploratory
                               
 
Gross
    66       11       27       104  
 
Net
    45.3       6.5       16.9       68.7  
2004 Development
                               
 
Gross
    710       239       16       965  
 
Net
    494.8       159.5       8.3       662.6  
 
Gross: total wells in which there was participation.
Net: working interest ownership.
      The Company’s 2005 exploration and development drilling program is discussed in Oil and Gas Properties and Activities under Item 1 of this Form 10-K.

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Common Stock Repurchase Program During 2005, a $2 billion stock buyback program announced in 2004 was completed and an additional $1 billion stock buyback program was authorized in November. Shares may be repurchased either in the open market or through privately negotiated transactions. During 2005 and 2004, Anadarko purchased 10.8 million and 20.3 million shares of common stock for $0.9 billion and $1.3 billion, respectively, under these programs. The Company expects to purchase additional shares under the current program as anticipated excess cash flow is realized; however, the repurchase program does not obligate Anadarko to acquire any specific number of shares and may be discontinued at any time. At December 31, 2005, $754 million remained available for stock repurchases under the program authorized in 2005.
Debt At year-end 2005, Anadarko’s total debt was $3.7 billion compared to total debt of $3.8 billion at year-end 2004 and $5.1 billion at year-end 2003. During 2005 and 2004, Anadarko repurchased $0.2 billion and $1.2 billion, respectively, aggregate principal amounts of its outstanding debt. The Company used net proceeds from asset divestitures to fund the debt reductions. For additional information on the Company’s debt instruments, such as transactions during the period, years of maturity and interest rates, see Note 6 — Debt and Interest Expense of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Dividends In 2005, Anadarko paid $170 million in dividends to its common stockholders (18 cents per share per quarter). In 2004, Anadarko paid $139 million in dividends to its common stockholders (14 cents per share per quarter). In 2003, Anadarko paid $109 million in dividends to its common stockholders (10 cents per share in the first, second and third quarters and 14 cents per share in the fourth 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 60% debt, exclusive of the effect of any noncash writedowns. As of December 31, 2005, Anadarko’s capitalization ratio was 25% debt; therefore, retained earnings were not restricted as to the payment of dividends.
      In each of the years 2005, 2004, and 2003, the Company also paid $5 million in preferred stock dividends. In 2006 preferred stock dividends are expected to be $5 million.
Outlook The Company’s goals include continuing to find high-margin oil and gas reserves at competitive prices and keeping operating costs at efficient levels. The Company’s 2006 capital expenditure budget is expected to be approximately $4 billion. The Company has allocated about 70% of the budget to development activities, 20% to exploration activities and the remaining 10% for capitalized interest, overhead and other items.
      A significant portion of capital spending in 2006 is expected to focus on unconventional tight gas plays onshore North America, primarily in north Louisiana, west Texas, east Texas and Alberta, Canada. In the eastern Gulf of Mexico, facilities will be installed to link several Anadarko-operated natural gas discoveries with the Independence Hub. In the central Gulf of Mexico, the Company expects to bring several high-volume wells on-line at the Marco Polo hub facility and participate in exploration or delineation wells in the foldbelt area. Outside North America, the international program includes continued development of Block 208 discoveries in Algeria and exploration activity in Algeria, Qatar, Indonesia, Tunisia and West Africa, as well as activities within other potential new venture areas.
      Anadarko’s strategy with respect to its capital program is to maintain a steady level of activity despite the volatile nature of commodity prices. This is accomplished by setting capital activity at levels that are self-funding. When prices exceed targeted levels, as is currently the case, costs tend to increase as well. The cash generated in excess of the amount needed to fund the steady level of capital activity is: systematically returned to shareholders through stock repurchases; used to build additional balance sheet strength through debt reductions; or otherwise made available for reinvestment in other strategic options. Alternatively, when prices are below the Company’s targeted levels, Anadarko could draw upon its strengthened debt capacity to fund a steady level of activity. The Company’s 2006 capital spending noted above was determined at an investment level that is less than cash flow using estimated full year 2006 NYMEX prices; therefore, cash flow in 2006 is expected to be higher than capital spending.
      If capital expenditures exceed operating cash flow, funds are supplemented as needed by short-term borrowings under commercial paper, money market loans or credit agreement borrowings. To facilitate such borrowings, the Company has in place a $750 million committed credit agreement, which is supplemented by

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various noncommitted credit lines that may be offered by certain banks from time to time at then-quoted rates. As of December 31, 2005, the Company had no outstanding borrowings under its credit facility. It is the Company’s policy to limit commercial paper borrowing to levels that are fully back-stopped by unused balances from its committed credit facilities. The Company may choose to refinance certain portions of these short-term borrowings by issuing long-term debt in the public or private debt markets. To facilitate such financings, the Company may file shelf registration statements in advance with the SEC.
      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 sales and additional borrowings, to secure funds when needed.
      In February 2006, the Company’s Board of Directors authorized a two-for-one split of the common stock. The stock split will require that shareholders authorize the issuance of additional shares for this purpose at the Company’s May 11, 2006 annual meeting. If approved, Anadarko’s transfer agent will deliver to each holder of record at the close of business on May 12, 2006, one additional share for every share of common stock held on May 26, 2006. Anadarko’s common stock should begin trading on a post-split basis on May 29, 2006. Based on year-end 2005 shares outstanding, Anadarko would have approximately 460 million shares of common stock outstanding following the proposed stock split.
      At this time, Anadarko has no plans to issue common stock other than through its Dividend Reinvestment and Stock Purchase Plan, the Executives and Directors Benefits Trust, the exercise of stock options, the issuance of restricted stock, performance unit agreements or the Company’s proposed stock split.
Obligations and Commitments
      Following is a summary of the Company’s future payments on obligations as of December 31, 2005:
                                           
    Obligations by Period
     
        2-3   4-5   Later    
    1 Year   Years   Years   Years   Total
millions                    
Total debt
  $ 123     $ 547     $ 52     $ 3,074     $ 3,796  
Operating leases
                                       
 
Drilling rig commitments
    296       1,163       539             1,998  
 
Other
    69       133       79       48       329  
Marketing activities
    78       134       86       153       451  
Oil and gas activities
          184       108       73       365  
Operating Leases Operating lease obligations include $2 billion related to drilling rig commitments that qualify as operating leases. During 2005, Anadarko entered into various agreements to secure the necessary drilling rigs to execute its drilling strategy over the next several years. A review of the Company’s worldwide deepwater drilling inventory, along with the tightening deepwater and onshore rig market, led Anadarko to secure the drilling rigs it needs to execute its strategy. Nearly two-thirds of the proposed contracted rig time is intended to delineate and develop discoveries, with the remainder for high potential exploration. The Company believes these rig-contracting efforts offer compelling economics and facilitate its drilling strategy. In addition to addressing the cost side of the equation, the Company also hedged a portion of its forecasted crude oil sales for the time period covered by the rig commitments to help manage the risk of potential declines in market-based rig rates.
      The Company also has $329 million in commitments under noncancelable operating lease agreements for a production platform and equipment, buildings, facilities and aircraft.
      During 2004, Anadarko and a group of energy companies (Atwater Valley Producers Group) executed agreements with a third party to design, construct, install and own Independence Hub, a semi-submersible platform in the deepwater Gulf of Mexico. The platform structure, expected to be mechanically complete in late 2006, will be operated by Anadarko. First production from Anadarko’s discoveries to be processed on the facility is expected in the second half of 2007. The agreements require a monthly demand charge of about $2 million for five years beginning at the time of mechanical completion, a processing fee based upon production throughput and a transportation fee based upon pipeline throughput. Since the Company’s obligation related to the agreements begins at the time of mechanical completion, the table above does not include any amounts related to these agreements. The agreements do not contain any purchase options, purchase obligations or value guarantees.
      For additional information see Note 19 — Commitments of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

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Marketing Activities Anadarko has entered into various transportation and storage 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 transportation and storage commitments of $451 million, comprised of $370 million in the United States and $81 million in Canada.
LNG Facility — Natural Gas Delivery Commitments In 2005, the Company entered into precedent agreements with a third party in order to secure delivery of natural gas from a LNG facility Anadarko is constructing in Nova Scotia, Canada, called Bear Head, to prospective markets in eastern Canada and the northeastern United States. The third party has agreed to expand the capacity of its pipeline so it can accommodate the projected natural gas volumes from Bear Head. The precedent agreements signed by the parties establish the conditions on which the third party will proceed with design, regulatory approvals and construction of the expansion facilities, and be obligated to transport a specified volume of gas. As a condition to entering into the precedent agreements, Anadarko executed firm service agreements for transportation on the Canadian and United States portions of the pipeline. Upon satisfaction of the obligations under the precedent agreements, the initial term of the transportation agreements is 20 years.
      Based upon the terms, Anadarko projects that annual demand charges due under the firm transportation service agreements may be in the range of $123 million to $182 million per year for the first five years from commencement of full service, potentially escalating by up to 5% in year six and 10% in year seven, exclusive of fuel and surcharges. No later than the eighth year from commencement of full service, rates under the agreements are to be redetermined based on then current conditions.
      The precedent agreements contain certain termination rights. The Company’s potential reimbursement obligation under the precedent agreements increases over time as the third party incurs pre-service costs. According to the original schedule provided by the third party, this reimbursement obligation is expected to increase from about $8 million at December 31, 2005 to $100 million at December 31, 2006, up to a maximum of $215 million in May 2007. Due to the number of factors that need to materialize in order to reasonably project the cumulative obligation and the existence of termination rights, the table above does not include any amounts related to these agreements.
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 2006 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 $365 million, comprised of $198 million in the United States, $45 million in Canada, $15 million in Algeria and $107 million in other international locations. The Company also routinely enters into short-term commitments, which are included in the Company’s 2006 capital budget of $4 billion; therefore, these commitments are not included in the preceding table.
Marketing and Trading Contracts The following tables provide additional information as of December 31, 2005 regarding the Company’s marketing and trading portfolio of physical delivery and financially settled derivative instruments and the firm transportation keep-whole agreement and related financial derivative instruments. See Critical Accounting Policies and Estimates for an explanation of how the fair value for derivatives is calculated.
                         
        Firm    
    Marketing   Transportation    
    and Trading   Keep-whole   Total
millions            
Fair value of contracts outstanding as of December 31, 2004 — assets (liabilities)
  $ 16     $ (54 )   $ (38 )
Contracts realized or otherwise settled during 2005
    1       6       7  
Fair value of new contracts when entered into during 2005
                 
Other changes in fair value
    (12 )     56       44  
                   
Fair value of contracts outstanding as of December 31, 2005 — assets (liabilities)
  $ 5     $ 8     $ 13  
                   

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    Fair Value of Contracts as of December 31, 2005
     
    Maturity       Maturity    
    less than   Maturity   Maturity   in excess    
Assets (Liabilities)   1 Year   1-3 Years   4-5 Years   of 5 Years   Total
millions                    
Marketing and Trading
                                       
 
Prices actively quoted
  $     $ 3     $ 1     $ 1     $ 5  
 
Prices based on models and other valuation methods
                             
Firm Transportation Keep-whole
                                       
 
Prices actively quoted
  $ 30     $     $     $     $ 30  
 
Prices based on models and other valuation methods
          (22 )                 (22 )
Total
                                       
 
Prices actively quoted
  $ 30     $ 3     $ 1     $ 1     $ 35  
 
Prices based on models and other valuation methods
          (22 )                 (22 )
      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 with a counterparty exceed predetermined credit limits. Given the Company’s hedge 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. During 2005, the Company’s margin deposit requirements have ranged from zero to $10 million. The Company had margin deposits of $9 million outstanding at December 31, 2005.
Other In 2005, the Company made contributions of $116 million to its funded pension plans, $5 million to its unfunded pension plans and $7 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. In 2006, the Company expects to contribute about $61 million to its funded pension plans, $10 million to its unfunded pension plans and $7 million to its unfunded other postretirement benefit plans. Future contributions to funded pension plans will be affected by actuarial assumptions, market performance and individual year funding decisions. The Company is unable to accurately predict what contribution levels will be required beyond 2006 for the pension plans; however, they are expected to be at levels lower than those made in 2005. The Company expects future payments for other postretirement benefit plans to continue at slightly increasing levels above those made in 2005.
      During 2004, proceeds from the sale of future royalty revenues were accounted for as deferred revenues and classified as liabilities on the balance sheet. These deferred revenues will be amortized to other sales on a unit-of-revenue basis over the 11-year term of the related agreement. The third party relies solely on the royalty payments to recover their investment and, as such, has the risk of the royalties not being sufficient to recover their investment over the term of the agreement.
      Anadarko is also subject to various environmental remediation and reclamation obligations arising from federal, state and local laws and regulations. As of December 31, 2005, the Company’s balance sheet included a $46 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 on contracts, obligations and arrangements the Company enters into from time to time, see Note 6 — Debt and Interest Expense, Note 7 — Financial Instruments, Note 8 — Sale of Future Hard Minerals Royalty Revenues, Note 9 — Asset Retirement Obligations, Note 20 — Pension Plans, Other Postretirement Benefits and Employee Savings Plans and Note 21 — Contingencies of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

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Critical Accounting Policies and Estimates
Financial Statements and Use of Estimates In preparing financial statements in accordance with generally accepted accounting principles, 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 period. On an ongoing basis, Management reviews its estimates, including those related to litigation, environmental liabilities, income taxes, fair values and determination of proved reserves. Changes in facts and circumstances 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.
Proved Reserves Proved oil and gas reserves, as defined by SEC Regulation S-X Rule 4-10(a) (2i), (2ii), (2iii), (3) and (4), are the estimated quantities of crude oil, natural gas and NGLs that 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, made by the Company’s engineers, are reviewed annually 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. Decreases in prices, for example, may cause a reduction in some proved reserves due to reaching economic limits sooner. A material change in the estimated volumes of reserves could have an impact on the DD&A rate calculation and the financial statements.
      Under the terms of Anadarko’s risk service contract with the national oil company of Venezuela, Anadarko earns a fee that is translated into barrels of oil based on current prices (economic interest method). This means that higher oil prices reduce the Company’s reported production volumes and reserves from that project and lower oil prices increase reported production volumes and reserves. Production volume and reserve changes due to the prices used to determine the Company’s economic interest have no impact on the value of the project.
Properties and Equipment The Company uses the full cost method of accounting for exploration and development activities as defined by the SEC. Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. The application of the full cost method of accounting for oil and gas properties generally results in higher capitalized costs and higher DD&A rates compared to the successful efforts method of accounting for oil and gas properties.
Costs Excluded Properties and equipment include costs that are excluded from costs being depreciated or amortized. Oil and gas costs excluded represent investments in unproved properties and major development projects in which the Company owns a direct interest. These unproved property costs include nonproducing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. Anadarko excludes these costs on a country-by-country basis until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized (the DD&A pool) or a charge is made against earnings for those international operations where a reserve base has not yet been established. Impairments transferred to the DD&A pool increase the DD&A rate for that country. For international operations where a reserve base has not yet been established, an impairment requiring a charge to earnings may be indicated through evaluation of drilling results, relinquishing drilling rights or other information. Costs excluded for oil and gas properties are generally classified and evaluated as significant or individually insignificant properties.

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      Significant properties, primarily comprised of costs associated with domestic offshore blocks, Alaska, the Land Grant and other international areas, are individually evaluated each quarter by the Company’s exploration and engineering staff. Nonproducing leases and geological and geophysical costs are transferred to the DD&A pool based on the progress of the Company’s exploration program. Exploration drilling costs are transferred to the DD&A pool upon the determination of whether proved reserves can be assigned to the properties, which is generally based on drilling results. The Company has a 10- to 12-year exploration and evaluation program for the Land Grant acreage. Costs are transferred to the DD&A pool as they are evaluated. The Land Grant’s mineral interests (both working and royalty interests) are owned by the Company in perpetuity.
      Insignificant properties are comprised primarily of costs associated with onshore properties in the United States and Canada. Nonproducing leases, along with related geological and geophysical costs, are transferred to the DD&A pool over a three- to five-year period based on the lease term. Exploration costs are transferred to the DD&A pool upon the determination of whether proved reserves can be assigned to the properties.
      Other costs excluded from depreciation represent major construction projects that are in progress.
Derivative Instruments Current accounting rules require that all derivative instruments, other than those that meet the normal purchase and sale exception, be recorded at fair value. Quoted market prices are the best evidence of fair value. If quotations are not available, management’s best estimate of fair value is based on the quoted market price of derivatives with similar characteristics or on valuation techniques.
      The Company’s derivative instruments are either exchange traded or transacted in an over-the-counter market. The fair values of the derivative instruments are based on quoted market prices, option pricing models and other internally developed valuation models. Option fair values are based on the Black-Scholes option pricing model and verified against the applicable counterparty’s fair values. The fair value of the short-term portion of the firm transportation keep-whole agreement is calculated based on quoted natural gas basis differentials. Basis differentials are the difference in value between gas at various delivery points and the NYMEX gas futures contract price. Management believes that natural gas basis price quotes beyond the next twelve months are not reliable indicators of fair value due to a lack of liquidity. Accordingly, the fair value of the long-term portion is estimated based on an internally developed model that utilizes historical natural gas basis differentials.
      Derivative accounting rules require that fair value changes of derivative instruments that do not qualify for hedge accounting be reported in current period earnings, rather than in the period the derivatives are settled and/or the hedged transaction is settled. This can result in significant volatility in earnings. The Company prefers to utilize hedge accounting for those derivative instruments that are used to manage price risk associated with its forecasted oil and gas production, foreign currency exchange rate risk and interest rates. However, some of these derivatives do not qualify for hedge accounting. Derivative accounting rules are complex and subject to interpretation in their application. Interpretative guidance continues to evolve and, as a result, it is possible the Company’s accounting policy for derivative instruments could be modified in the future.
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 all significant 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 tax contingencies and, if required, establishes accruals for such contingencies. 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
New Accounting Principles SFAS No. 123 (revised 2004), “Share-Based Payment,” requires the recognition of expense for the fair value of share-based payments. The statement is effective for the Company beginning January 1, 2006. The Company adopted the fair value method of accounting for share-based payments effective January 1, 2003, using the “modified prospective method” described in SFAS No. 148, Accounting for Stock-Based Compensation — Transition and Disclosure. For 2005, 2004 and 2003, the Company used the Black-Scholes option pricing model to estimate the value of stock options granted to employees. Anadarko expects to continue to use this acceptable option pricing model upon the required adoption of SFAS No. 123(R) on January 1, 2006. The Company does not anticipate that the adoption of SFAS No. 123(R) will have a material impact on its results of operations or its financial position. Certain amounts attributable to the benefits of tax deductions in excess of recognized compensation in the financial statements that have been previously reported in the statement of cash flow as operating activities — other items net — will be reported as financing activities since they relate to the issuance of common stock. These amounts were $53 million, $36 million and $1 million in 2005, 2004 and 2003, respectively.
Other Developments
      Anadarko’s operations in Venezuela have been governed by an Operating Service Agreement (OSA) that was entered into in November 1993 between the Company and an affiliate of Petroleos de Venezuela, S.A. (PDVSA), the national oil company of Venezuela. Anadarko and its partner in the OSA, Petrobras Energia Venezuela (Petrobras), have conducted their OSA operations via a Venezuelan joint venture in which Petrobras acts as operator. In 2005, the Venezuelan Ministry of Energy and Petroleum announced that all OSAs concluded by PDVSA between 1992 and 1997 will be subject to renegotiation. The Company and Petrobras signed a Transitory Agreement with PDVSA in September 2005. Under this agreement, the parties are currently negotiating the conversion of the OSA to a company in which Anadarko, Petrobras and PDVSA will each have an interest. PDVSA is expected to have a majority participation interest in this company. The Company cannot predict at this time the outcome of these negotiations. Related to these developments, PDVSA has limited the fees paid to the Company by applying a cap to the revenues with respect to the oil production from the OSA. The Company’s revenues for 2005 were reduced by $48 million to reflect the cumulative estimated impact of the reduced fees through December 2005. The Company recorded revenues from Venezuela of $193 million in 2005.
      In January 2006, the Company paid approximately $6 million of Venezuela tax related to an assessment by SENIAT, the Venezuela national tax authority, which included an increase in corporate income tax rates (67.7% for 2001 and 50% for 2002-2004).
      For the year ended December 31, 2005, approximately 2% of the Company’s income before income taxes, total assets and proved reserves were associated with operations located in Venezuela. The Company is unable to determine the impact of the current situation in Venezuela on future operating results or proved reserves.

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Item 7a. Quantitative and Qualitative Disclosures About Market Risk
      The Company’s primary market risks are fluctuations in energy prices, foreign currency exchange rates and interest rates. These fluctuations can affect revenues and the cost of operating, investing and financing activities. The Company’s risk management policy provides 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. For information regarding the Company’s accounting policies related to derivatives and additional information related to the Company’s derivative instruments, see Note 1 — Summary of Significant Accounting Policies and Note 7 — Financial 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, NGLs and the firm transportation keep-whole agreement. Management expects energy prices to remain volatile and unpredictable. If energy prices decline significantly, revenues and cash flow would significantly decline. The Company has substantially more exposure to unfavorable changes in energy prices in 2006 than it did in prior years due to a decreased level of derivative instruments in place. In 2005, Anadarko had derivative instruments in place to reduce price risk on about 25% of its oil and gas production. For 2006, derivative instruments in place to reduce price risk on its forecasted oil and gas production are less than 2%. In addition, a noncash writedown of the Company’s oil and gas properties could be required under full cost accounting rules if prices declined significantly, even if it is only for a short period of time. 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 6 Bcf of natural gas and 17 MMBbls of crude oil as of December 31, 2005 (excluding physical delivery fixed price contracts not accounted for as derivative instruments). As of December 31, 2005, the Company had a net unrealized loss of $53 million on these derivative instruments. Utilizing the actual derivative contractual volumes, a 10% increase in underlying commodity prices would result in an additional loss on these derivative instruments of approximately $53 million. However, this loss would be substantially offset by a gain in the value of that portion of the Company’s equity production that is hedged.
Derivative Instruments Held for Trading Purposes As of December 31, 2005, the Company had a net unrealized gain of $11 million (gains of $42 million and losses of $31 million) on derivative financial instruments entered into for trading purposes and a net unrealized loss of $6 million (losses of $52 million and gains of $46 million) on physical delivery contracts entered into for trading purposes and accounted for as derivatives. Utilizing the actual derivative contractual volumes and assuming a 10% increase in underlying commodity prices, the potential additional loss on these derivative instruments would be $1 million.
Firm Transportation Keep-Whole Agreement A company Anadarko acquired in 2000 was a party to several long-term firm gas transportation agreements that supported its gas marketing program which was sold in 1999 to Duke. As part of the disposition, Anadarko pays Duke if transportation market values fall below the fixed contract transportation rates, while Duke pays Anadarko if the transportation market values exceed the contract transportation rates (keep-whole agreement). The term of the keep-whole agreement extends through February 2009. The Company may periodically use derivative instruments to reduce its exposure under the keep-whole agreement to potential decreases in future transportation market values. Due to decreased liquidity, the use of derivative instruments to manage this risk is generally limited to the forward 12 months. As of December 31, 2005, other current assets included $30 million and other long-term liabilities included $22 million related to this agreement. As of December 31, 2004, accounts payable included $15 million and other long-term liabilities included $39 million related to this agreement. A 10% unfavorable change in the December 31, 2005 natural gas basis differentials would result in a loss of $32 million on the keep-whole agreement. The future gain or loss from this agreement cannot be accurately predicted. For additional information related to the keep-whole agreement see Note 7 — Financial Instruments of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

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      For additional information regarding the Company’s marketing and trading portfolio and the firm transportation keep-whole agreement see Marketing Strategies under Item 7 of this Form 10-K.
Interest Rate Risk Anadarko is also exposed to risk resulting from changes in interest rates as a result of the Company’s floating rate obligations. The Company believes the potential effect that reasonably possible near term changes in interest rates may have on interest expense or the fair value of the Company’s fixed-rate debt instruments is not material. The Company did not have any derivative instruments related to interest rate risk in place as of December 31, 2005.
Foreign Currency Risk The Company has Canadian subsidiaries which use the Canadian dollar as their functional currency. The Company’s other international subsidiaries use the U.S. dollar as their functional currency. To the extent that business transactions in these countries are not denominated in the respective country’s functional currency, the Company is exposed to foreign currency exchange rate risk.
      A Canadian subsidiary has notes and debentures denominated in U.S. dollars. The potential foreign currency remeasurement impact on earnings from a 10% unfavorable change in the December 31, 2005 Canadian exchange rate against the U.S. dollar would be a loss of about $5 million based on the outstanding debt at December 31, 2005.
      For additional information related to foreign currency risk see Note 7 — Financial Instruments of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

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Item 8. Financial Statements and Supplementary Data
ANADARKO PETROLEUM CORPORATION
INDEX
CONSOLIDATED FINANCIAL STATEMENTS
         
    Page
     
    51  
    51  
    52  
    54  
    55  
    56  
    57  
    58  
    59  
    91  
    106  

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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 U.S. generally accepted accounting principles. 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 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, 2005. 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, 2005 the Company’s internal control over financial reporting is effective based on those criteria.
      KPMG LLP has issued an audit report on our assessment of the Company’s internal control over financial reporting as of December 31, 2005.
-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
March 2, 2006

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Anadarko Petroleum Corporation:
We have audited management’s assessment, included in the accompanying Management’s Assessment of Internal Control Over Financial Reporting, that Anadarko Petroleum Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and 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, management’s assessment that Anadarko Petroleum Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
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, 2005 and 2004, 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, 2005, and our report dated March 2, 2006 expressed an unqualified opinion on those consolidated financial statements.
KPMG LLP
Houston, Texas
March 2, 2006

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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, 2005 and 2004, 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, 2005. 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, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Anadarko Petroleum Corporation’s internal control over financial reporting as of December 31, 2005, 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 March 2, 2006 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
KPMG LLP
Houston, Texas
March 2, 2006

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ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
                         
    Years Ended December 31
     
    2005   2004   2003
millions except per share amounts            
Revenues
                       
Gas sales
  $ 3,709     $ 3,298     $ 2,842  
Oil and condensate sales
    2,838       2,211       1,787  
Natural gas liquids sales
    457       460       365  
Other sales
    96       110       119  
                   
Total
    7,100       6,079       5,113  
                   
Costs and Expenses
                       
Direct operating
    544       682       630  
Transportation and cost of product
    302       250       198  
General and administrative
    442       423       392  
Depreciation, depletion and amortization
    1,343       1,447       1,297  
Other taxes
    376       312       294  
Impairments related to oil and gas properties
    78       72       103  
                   
Total
    3,085       3,186       2,914  
                   
Operating Income
    4,015       2,893       2,199  
Interest Expense and Other (Income) Expense
                       
Interest expense
    201       352       253  
Other (income) expense
    (81 )     64       (28 )
                   
Total
    120       416       225  
                   
Income Before Income Taxes
    3,895       2,477       1,974  
Income Tax Expense
    1,424       871       729  
                   
Net Income Before Cumulative Effect of Change in Accounting Principle
    2,471     $ 1,606     $ 1,245  
                   
Preferred Stock Dividends
    5       5       5  
                   
Net Income Available to Common Stockholders Before
Cumulative Effect of Change in Accounting Principle
  $ 2,466     $ 1,601     $ 1,240  
                   
Cumulative Effect of Change in Accounting Principle
                47  
                   
Net Income Available to Common Stockholders
  $ 2,466     $ 1,601     $ 1,287  
                   
Per Common Share
                       
Net income — before change in accounting principle — basic
  $ 10.49     $ 6.41     $ 4.97  
Net income — before change in accounting principle — diluted
  $ 10.39     $ 6.36     $ 4.91  
Change in accounting principle — basic
  $     $     $ 0.19  
Change in accounting principle — diluted
  $     $     $ 0.18  
Net income — basic
  $ 10.49     $ 6.41     $ 5.16  
Net income — diluted
  $ 10.39     $ 6.36     $ 5.09  
Dividends
  $ 0.72     $ 0.56     $ 0.44  
 
Average Number of Common Shares Outstanding — Basic
    235       250       250  
                   
Average Number of Common Shares Outstanding — Diluted
    237       252       253  
                   
See accompanying notes to consolidated financial statements.

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ANADARKO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
                   
    December 31
     
    2005   2004
millions        
ASSETS
               
Current Assets
               
Cash and cash equivalents
  $ 739     $ 874  
Accounts receivable, net of allowance:
               
 
Customers
    1,338       1,040  
 
Others
    581       310  
Other current assets
    258       278  
             
Total
    2,916       2,502  
             
Properties and Equipment
               
Original cost (includes unproved properties of $1,309 and $1,642 as of December 31, 2005 and 2004, respectively)
    28,455       25,175  
Less accumulated depreciation, depletion and amortization
    10,593       9,262  
             
Net properties and equipment — based on the full cost method of accounting for
oil and gas properties
    17,862       15,913  
             
Other Assets
    614       468  
             
Goodwill
    1,196       1,309  
             
Total Assets
  $ 22,588     $ 20,192  
             
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current Liabilities
               
Accounts payable
  $ 1,725     $ 1,460  
Accrued expenses
    556       364  
Current debt
    122       169  
             
Total
    2,403       1,993  
             
Long-term Debt
    3,555       3,671  
             
Other Long-term Liabilities
               
Deferred income taxes
    4,719       4,414  
Other
    860       829  
             
Total
    5,579       5,243  
             
Stockholders’ Equity
               
Preferred stock, par value $1.00 per share
               
 
(2.0 million shares authorized, 0.1 million shares issued as of December 31, 2005 and 2004)
    89       89  
Common stock, par value $0.10 per share
               
 
(450.0 million shares authorized, 266.3 million and 262.2 million shares issued as of December 31, 2005 and 2004, respectively)
    27       26  
Paid-in capital
    6,063       5,741  
Retained earnings
    6,957       4,661  
Treasury stock (34.4 million and 23.5 million shares as of December 31, 2005 and 2004, respectively)
    (2,423 )     (1,476 )
Employee Stock Ownership Plan (0.1 million shares as of December 31, 2004)
          (7 )
Executives and Directors Benefits Trust, at market value (2.0 million shares as of December 31, 2005 and 2004)
    (189 )     (130 )
Accumulated other comprehensive income (loss):
               
 
Unrealized loss on derivative instruments
    (5 )     (23 )
 
Foreign currency translation adjustments
    549       482  
 
Minimum pension liability
    (17 )     (78 )
             
 
Total
    527       381  
             
Total
    11,051       9,285  
             
Commitments and Contingencies
           
             
Total Liabilities and Stockholders’ Equity
  $ 22,588     $ 20,192  
             
See accompanying notes to consolidated financial statements.

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
                         
    Years Ended December 31
     
    2005   2004   2003
millions            
Preferred Stock
                       
Balance at beginning of year
  $ 89     $ 89     $ 101  
Preferred stock repurchased
                (12 )
                   
Balance at end of year
    89       89       89  
                   
Common Stock
                       
Balance at beginning of year
    26       26       25  
Common stock issued
    1             1  
                   
Balance at end of year
    27       26       26  
                   
Paid-in Capital
                       
Balance at beginning of year
    5,741       5,453       5,326  
Common stock issued
    263       260       120  
Revaluation to market for Executives and Directors Benefits Trust
    59       28       7  
                   
Balance at end of year
    6,063       5,741       5,453  
                   
Retained Earnings
                       
Balance at beginning of year
    4,661       3,199       2,021  
Net income
    2,471       1,606       1,292  
Dividends paid — preferred
    (5 )     (5 )     (5 )
Dividends paid — common
    (170 )     (139 )     (109 )
                   
Balance at end of year
    6,957       4,661       3,199  
                   
Treasury Stock
                       
Balance at beginning of year
    (1,476 )     (166 )     (166 )
Purchase of treasury stock
    (947 )     (1,310 )      
                   
Balance at end of year
    (2,423 )     (1,476 )     (166 )
                   
Employee Stock Ownership Plan
                       
Balance at beginning of year
    (7 )     (22 )     (42 )
Release of shares
    7       15       20  
                   
Balance at end of year
          (7 )     (22 )
                   
Executives and Directors Benefits Trust
                       
Balance at beginning of year
    (130 )     (102 )     (95 )
Revaluation to market
    (59 )     (28 )     (7 )
                   
Balance at end of year
    (189 )     (130 )     (102 )
                   
Accumulated Other Comprehensive Income (Loss)
                       
Balance at beginning of year
    381       122       (198 )
Unrealized gain (loss) on derivative instruments
    18       97       (35 )
Foreign currency translation adjustments
    67       182       337  
Minimum pension liability adjustments
    61       (20 )     18  
                   
Balance at end of year
    527       381       122  
                   
Total Stockholders’ Equity
  $ 11,051     $ 9,285     $ 8,599  
                   
See accompanying notes to consolidated financial statements.

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ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                           
    Years Ended December 31
     
    2005   2004   2003
millions            
Net Income Available to Common Stockholders
  $ 2,466     $ 1,601     $ 1,287  
Add: Preferred stock dividends
    5       5       5  
                   
Net Income Available to Common Stockholders Before Preferred Stock Dividends
    2,471       1,606       1,292  
                   
Other Comprehensive Income (Loss), Net of Income Taxes
                       
Unrealized gains (losses) on derivative instruments:
                       
 
Unrealized losses during the period1
    (126 )     (165 )     (154 )
 
Reclassification adjustment for loss included in net income2
    144       262       119  
                   
 
Total unrealized gains (losses) on derivative instruments
    18       97       (35 )
Foreign currency translation adjustments3
    67       182       337  
Minimum pension liability adjustments4
    61       (20 )     18  
                   
Total
    146       259       320  
                   
Comprehensive Income
  $ 2,617     $ 1,865     $ 1,612  
                   
                         
1net of income tax benefit of:
  $ 73     $ 96     $ 91  
2net of income tax expense of:
    (82 )     (153 )     (67 )
3net of income tax expense of:
    (9 )     (22 )     (59 )
4net of income tax benefit (expense) of:
    (35 )     11       (11 )
See accompanying notes to consolidated financial statements.

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ANADARKO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
                             
    Years Ended December 31
     
    2005   2004   2003
millions            
Cash Flow from Operating Activities
                       
Net income before cumulative effect of change in
accounting principle
  $ 2,471     $ 1,606     $ 1,245  
Adjustments to reconcile net income before cumulative effect of change in accounting principle to net cash provided by operating activities:
                       
 
Depreciation, depletion and amortization
    1,343       1,447       1,297  
 
Deferred income taxes
    566       276       505  
 
Impairments related to oil and gas properties
    78       72       103  
 
Other noncash items
    (35 )     64       14  
 
Changes in assets and liabilities:
                       
   
(Increase) decrease in accounts receivable
    (563 )     (239 )     46  
   
Increase (decrease) in accounts payable and accrued expenses
    373       270       (68 )
   
Other items — net
    (87 )     (289 )     (99 )
                   
Net cash provided by operating activities
    4,146       3,207       3,043  
                   
Cash Flow from Investing Activities
                       
Additions to properties and equipment
    (3,408 )     (3,064 )     (2,772 )
Acquisition costs, net of cash acquired
          (46 )      
Sales of properties and equipment and other assets
    155       3,073       138  
                   
Net cash used in investing activities
    (3,253 )     (37 )     (2,634 )
                   
Cash Flow from Financing Activities
                       
Additions to debt
    7       21       358  
Retirements of debt
    (170 )     (1,237 )     (772 )
Increase (decrease) in accounts payable, banks
    86       (43 )     49  
Sale of future hard minerals royalty revenues
          158        
Dividends paid
    (175 )     (144 )     (114 )
Purchase of treasury stock
    (947 )     (1,310 )      
Retirement of preferred stock
                (12 )
Issuance of common stock
    168       194       100  
                   
Net cash used in financing activities
    (1,031 )     (2,361 )     (391 )
                   
Effect of Exchange Rate Changes on Cash
    3       3       10  
                   
Net (Decrease) Increase in Cash and Cash Equivalents
    (135 )     812       28  
Cash and Cash Equivalents at Beginning of Year
    874       62       34  
                   
Cash and Cash Equivalents at End of Year
  $ 739     $ 874     $ 62  
                   
See accompanying notes to consolidated financial statements.

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2005, 2004 and 2003
1.  Summary of Significant Accounting Policies
General  Anadarko Petroleum Corporation is engaged in the exploration, development, production and marketing of natural gas, crude oil, condensate and natural gas liquids (NGLs). The Company also engages in the hard minerals business through non-operated joint ventures and royalty arrangements in several coal, trona (natural soda ash) and industrial mineral mines. The terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its subsidiaries.
Principles of Consolidation and Use of Estimates  The consolidated financial statements include the accounts of Anadarko and its subsidiaries. All significant intercompany transactions have been eliminated. The Company accounts for investments in affiliated companies (generally 20% to 50% owned) using the equity method of accounting. The financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America. Certain amounts for prior periods have been reclassified to conform to the current presentation. In preparing financial statements, 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 period. On an ongoing basis, Management reviews its estimates, including those related to litigation, environmental liabilities, income taxes, fair values and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.
Changes in Accounting Principles  Statement of Financial Accounting Standards (SFAS) No. 153, “Exchanges of Nonmonetary Assets,” requires the use of fair value measurement for exchanges of nonmonetary assets. The statement was effective for the Company beginning in the third quarter 2005 and applied prospectively for any nonmonetary exchanges occurring after the effective date. The adoption of SFAS No. 153 did not have a material impact on the Company’s financial statements.
      In September 2005, the Emerging Issues Task Force (EITF) concluded in Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” that purchases and sales of inventory with the same party in the same line of business should be accounted for as nonmonetary exchanges, if entered into in contemplation of one another. Anadarko presents purchase and sale activities related to its marketing and trading activities on a net basis in the income statement. The conclusion reached on EITF Issue No. 04-13 did not have an impact on the Company’s consolidated financial statements.
      Financial Accounting Standards Board (FASB) Staff Position (FSP) FAS 109-1, “Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004,” provides guidance on the application of SFAS No. 109, “Accounting for Income Taxes,” to the tax deduction on qualified production as provided for in the American Jobs Creation Act of 2004 (Jobs Act). FSP FAS 109-1 provides that the deduction should be treated as a special deduction under the provisions of SFAS No. 109. The adoption of FSP FAS 109-1 did not have a material impact on the consolidated financial statements.
      FSP FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004,” provides guidance on the application of SFAS No. 109 to the special one-time dividends received deduction on the repatriation of certain undistributed foreign earnings to a U.S. taxpayer as provided for in the Jobs Act. In 2005, Anadarko’s Chief Executive Officer and Board of Directors approved a domestic reinvestment plan for a $500 million repatriation of foreign earnings under the Jobs Act. The $26 million tax effect of this repatriation was recorded as current tax expense in 2005.
      In 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which requires the fair value of a liability for an asset retirement obligation to be recorded in the period incurred and a corresponding increase in the carrying amount of the related long-lived asset. See Note 9.
      In 2003, the Company adopted the fair value method of accounting for stock-based employee compensation using the prospective method described in SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure.” The disclosure provisions of SFAS No. 148 were adopted in 2002. See Note 2.

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2005, 2004 and 2003
1.  Summary of Significant Accounting Policies (Continued)
      In 2003, the Company adopted SFAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” that requires additional disclosures about plan assets, obligations, cash flows and net periodic benefit cost of pension plans and other postretirement benefit plans. See Note 20.
Properties and Equipment  The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (SEC). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.
      Operating fees received related to the properties in which the Company owns an interest are netted against expenses. Fees received in excess of costs incurred are recorded as a reduction to the full cost pool.
Costs Excluded  Properties and equipment include costs that are excluded from costs being depreciated or amortized. Oil and gas costs excluded represent investments in unproved properties and major development projects in which the Company owns a direct interest. These unproved property costs include nonproducing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. Anadarko excludes these costs on a country-by-country basis until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized (the depreciation, depletion and amortization (DD&A) pool) or a charge is made against earnings for those international operations where a reserve base has not yet been established. For international operations where a reserve base has not yet been established, an impairment requiring a charge to earnings may be indicated through evaluation of drilling results, relinquishing drilling rights or other information. Costs excluded for oil and gas properties are generally classified and evaluated as significant or individually insignificant properties.
      Significant properties, primarily comprised of costs associated with domestic offshore blocks, Alaska, the Land Grant and other international areas, are individually evaluated each quarter by the Company’s exploration and engineering staff. Nonproducing leases and geological and geophysical costs are transferred to the DD&A pool based on the progress of the Company’s exploration program. Exploration drilling costs are transferred to the DD&A pool upon the determination of whether proved reserves can be assigned to the properties, which is generally based on drilling results. The Company has a 10- to 12-year exploration and evaluation program for the Land Grant acreage. Costs are transferred to the DD&A pool as they are evaluated. The Land Grant’s mineral interests (both working and royalty interests) are owned by the Company in perpetuity.
      Insignificant properties are comprised primarily of costs associated with onshore properties in the United States and Canada. Nonproducing leases, along with related geological and geophysical costs, are transferred to the DD&A pool over a three- to five-year period based on the lease term. Exploration costs are transferred to the DD&A pool upon the determination of whether proved reserves can be assigned to the properties.
      Other costs excluded from depreciation represent major construction projects that are in progress.
Depreciation, Depletion and Amortization  The depreciable base for oil and gas properties includes the sum of capitalized costs net of accumulated DD&A, estimated future development costs and asset retirement costs not accrued in oil and gas properties, less costs excluded from amortization and salvage. The depreciable base of oil and gas properties and mineral investments are amortized using the unit-of-production method. All other properties are stated at original cost and depreciated using the straight-line method over the useful life of the assets, which ranges from three to 40 years. Properties and equipment carrying values do not purport to represent replacement or market values.

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2005, 2004 and 2003
1.  Summary of Significant Accounting Policies (Continued)
Capitalized Interest  Interest is capitalized as part of the historical cost of acquiring assets. Oil and gas investments in unproved properties and major development projects, on which DD&A expense is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready for service. Capitalized interest is calculated by multiplying the Company’s weighted-average interest rate on debt by the amount of qualifying costs. Capitalized interest cannot exceed gross interest expense. As oil and gas costs excluded are transferred to the DD&A pool, the associated capitalized interest is also transferred to the DD&A pool. As major construction projects are completed, the associated capitalized interest is amortized over the useful life of the asset with the underlying cost of the asset.
Ceiling Test  Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test determines a limit, on a country-by-country basis, on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated DD&A and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, generally using prices in effect at the end of the period held flat for the life of production and including the effect of derivative instruments that qualify as cash flow hedges, discounted at 10%, net of related tax effects, plus the cost of unevaluated properties and major development projects excluded from the costs being amortized. If capitalized costs exceed this limit, the excess is charged to expense and reflected as additional accumulated DD&A. For cash flow hedge effect information, see Supplemental Information on Oil and Gas Exploration and Production Activities — Discounted Future Net Cash Flows.
Revenues  The Company recognizes sales revenues based on the amount of gas, oil, condensate and NGLs sold to purchasers when delivery to the purchaser has occurred and title has transferred. This occurs when production has been delivered to a pipeline or a tanker lifting has occurred. The Company follows the sales method of accounting for gas imbalances. If the Company’s excess sales of production volumes for a well exceed the estimated remaining recoverable reserves of the well, a liability is recorded. No receivables are recorded for those wells on which the Company has taken less than its ownership share of production.
      The Company enters into buy/sell arrangements for a portion of its crude oil production. Under these arrangements, barrels are sold at prevailing market prices at a location and in a simultaneous transaction with the same third party, barrels are re-purchased at a different location at the market prices prevailing at that location. The barrels are then sold at prevailing market prices at the re-purchase location. These arrangements are often a requirement of private transporters. In these transactions, the re-purchase price is more than the original sales price with the difference representing a transportation fee. Other buy/sell arrangements are entered to move the ultimate sales point of the Company’s production to a more liquid location and thereby avoid potential marketing fees and deductions from the market price in the field. In these transactions, the sales price in the field and the re-purchase price are each at prevailing market prices for the respective location. Anadarko uses these buy/sell arrangements in its marketing and trading activities and, as such, reports these transactions in the income statement on a net basis.
      Marketing margins related to the Company’s equity production, realized gains and losses on derivative instruments that receive cash flow hedge accounting treatment, unrealized gains and losses attributable to ineffectiveness of derivative instruments that receive cash flow hedge accounting treatment, and unrealized gains and losses on derivative instruments that were undertaken to manage the price risk of the Company’s production that do not receive cash flow hedge accounting treatment are included in gas sales, oil and condensate sales and NGLs sales. The marketing margin related to purchases of third-party commodities is included in other sales.
Derivative Instruments  The majority of the derivative instruments utilized by Anadarko are in conjunction with its marketing and trading activities or to manage the price risk attributable to the Company’s expected oil

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2005, 2004 and 2003
1.  Summary of Significant Accounting Policies (Continued)
and gas production. Anadarko also periodically utilizes derivatives to manage its exposure associated with the firm transportation keep-whole agreement, foreign currency exchange rates and interest rates. All derivatives, other than those that meet the normal purchases and sales exception, are carried on the balance sheet at fair value.
      Anadarko prefers to apply hedge accounting for derivatives utilized to manage price risk associated with the Company’s oil and gas production, foreign currency exchange rate risk and interest rate risk. However, some of these derivatives do not qualify for hedge accounting. In these instances, unrealized gains and losses are recognized currently in earnings. For those derivatives that qualify for hedge accounting, Anadarko formally documents the hedging relationship including the risk management objective and strategy for undertaking the hedge. Each hedge is also assessed for effectiveness quarterly. Under hedge accounting, the derivatives may be designated as a hedge of exposure to changes in fair values, cash flows or foreign currencies. If the hedge relates to the exposure of fair value changes to a recognized asset or liability or an unrecognized firm commitment, the unrealized gains and losses on the derivative and the unrealized gains and losses on the hedged item are both recognized currently in earnings. If the hedge relates to exposure of variability in the cash flow of a forecasted transaction, the effective portion of the unrealized gains and losses on the derivative is reported as a component of accumulated other comprehensive income and reclassified into earnings in the same period the hedged transaction is recorded. The ineffective portion of unrealized gains and losses attributable to cash flow hedges, if any, is recognized currently in gas sales and oil and condensate sales. Hedge ineffectiveness is that portion of the derivative’s unrealized gains and losses that exceed the hedged item’s unrealized gains and losses. In those instances where it becomes probable that a hedged forecasted transaction will not occur, the unrealized gain or loss is reclassified from accumulated other comprehensive income to earnings in the current period. Accounting for unrealized gains and losses attributable to foreign currency hedges that qualify for hedge accounting is dependent on whether the hedge is a fair value or a cash flow hedge.
      Unrealized gains and losses attributable to derivative instruments used in the Company’s marketing and trading activities (including both physical delivery and financially settled purchase and sale contracts), the firm transportation keep-whole agreement and derivatives used to manage the exposure of the keep-whole agreement are recognized currently in earnings. The marketing and trading unrealized gains and losses that are attributable to the Company’s production are recorded to gas sales and oil and condensate sales. The marketing and trading unrealized gains and losses that are attributable to third-party production are recorded to other sales. The gains and losses attributable to the firm transportation keep-whole agreement and associated derivatives are recorded to other (income) expense.
      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 valuations are based on the Black-Scholes option pricing model and verified against third-party quotations. The fair value of the short-term portion of the firm transportation keep-whole agreement is calculated based on quoted natural gas basis differentials, while the fair value of the long-term portion is estimated based on an internally developed model that utilizes historical natural gas basis differentials. See Note 7.
Inventories  Materials and supplies and commodity inventories are stated at the lower of average cost or market and removed at carrying value.
Goodwill  Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed in previous mergers and acquisitions. The Company assesses the carrying amount of goodwill by testing the goodwill for impairment annually and upon certain events. The impairment test requires allocating goodwill and all other assets and liabilities to business levels referred to as reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense. Anadarko’s goodwill relates to its oil and gas reporting unit.

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2005, 2004 and 2003
1.  Summary of Significant Accounting Policies (Continued)
      Goodwill impairment tests were performed annually as well as upon the Company’s property divestitures in 2004, and no goodwill impairments were indicated. The change in goodwill in 2005 was primarily due to the adjustment of deferred income tax liabilities related to previous acquisitions. Future changes in goodwill may result from, among other things, changes in foreign currency exchange rates, changes in deferred income tax liabilities related to previous acquisitions, divestitures, impairments or future acquisitions. See Note 18.
Legal Contingencies  The Company is subject to legal proceedings, claims and liabilities which arise in the ordinary course of its business. The Company accrues for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as further information develops or circumstances change. See Note 21.
Environmental Contingencies  The Company accrues for losses associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than the time of the completion of the remediation feasibility study. These accruals are adjusted as further information develops or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable. See Note 21.
Income Taxes  The Company files various United States federal, state and foreign income tax returns. Deferred federal, state and foreign income taxes are provided on all significant temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases.
Cash Equivalents  The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Stock-Based Compensation  Effective January 2003, the Company accounts for stock-based compensation under the fair value method. Under the fair value method, the Company records compensation expense over the vesting period using the straight-line method. The Company grants various types of stock-based awards including stock options, nonvested equity shares and performance-based equity units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Nonvested equity-share awards are valued using the market price on grant date. For performance-based stock awards, the fair value of the market condition portion of the award is measured using a Monte Carlo simulation and the performance condition portion of the award is measured at the market price of the Company’s common stock on the grant date. If the requisite service period is not satisfied, compensation expense is reversed. If the requisite service period is satisfied, expense is not adjusted unless the award contains a performance condition. If an award contains a performance condition, expense is recognized only for those shares that ultimately vest using the fair value per share measured at grant date. See Notes 2 and 11.
Earnings Per Share  The Company’s basic earnings per share (EPS) amounts have been computed based on the average number of shares of common stock outstanding for the period. Diluted EPS amounts include the effect of the Company’s outstanding stock options and performance-based stock awards under the treasury stock method if including such potential shares of common stock is dilutive. Diluted EPS amounts also include the net effect of the Company’s convertible debentures in 2003 and Zero Yield Puttable Contingent Debt Securities (ZYP-CODES) assuming the conversions occurred at the beginning of the year through the period outstanding, if including such potential common shares is dilutive. See Note 11.
New Accounting Principles  SFAS No. 123 (revised 2004), “Share-Based Payment,” requires the recognition of expense for the fair value of share-based payments. The statement is effective for the Company beginning January 1, 2006. The Company adopted the fair value method of accounting for share-based payments effective January 1, 2003, using the “modified prospective method” described in SFAS No. 148. For 2005, 2004 and 2003,

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2005, 2004 and 2003
1.  Summary of Significant Accounting Policies (Continued)
the Company used the Black-Scholes option pricing model to estimate the value of stock options granted to employees. Anadarko expects to continue to use this acceptable option pricing model upon the required adoption of SFAS No. 123(R) on January 1, 2006. The Company does not anticipate that the adoption of SFAS No. 123(R) will have a material impact on its results of operations or its financial position. Certain amounts attributable to the benefits of tax deductions in excess of recognized compensation in the financial statements that have been previously reported in the statement of cash flow as operating activities — other items net — will be reported as financing activities since they relate to the issuance of common stock. These amounts were $53 million, $36 million and $1 million in 2005, 2004 and 2003, respectively.
2.  Stock-Based Compensation
      For share-based awards granted or modified after January 2003, the Company uses the fair value method of accounting for stock-based employee compensation expense. For share-based awards granted prior to 2003, Anadarko applies the intrinsic value method whereby no compensation expense is recognized for stock options granted with an exercise price equal to the market value of Anadarko common stock on the date of grant.
      If compensation expense for all stock option grants had been determined using the fair value method, the Company’s pro forma net income and EPS would have been as shown below:
                         
    2005   2004   2003
millions except per share amounts            
Net income available to common stockholders, as reported
  $ 2,466     $ 1,601     $ 1,287  
Add: Stock-based employee compensation expense included in income, after income taxes
    20       14       12  
Deduct: Total stock-based employee compensation expense determined under the fair value method, after income taxes
    (21 )     (18 )     (30 )
                   
Pro forma net income available to common stockholders
  $ 2,465     $ 1,597     $ 1,269  
                   
Basic EPS - as reported
  $ 10.49     $ 6.41     $ 5.16  
Basic EPS - pro forma
  $ 10.48     $ 6.40     $ 5.09  
Diluted EPS - as reported
  $ 10.39     $ 6.36     $ 5.09  
Diluted EPS - pro forma
  $ 10.37     $ 6.34     $ 5.02  
      The fair value of each option grant was estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions:
                         
    2005   2004   2003
             
Expected option life – years
    5.4       5.2       5.3  
Risk-free interest rate
    4.5 %     3.5 %     3.3 %
Dividend yield
    0.7 %     0.6 %     0.6 %
Volatility
    29.6 %     33.6 %     40.4 %
3.  Divestitures
      Anadarko announced a refocused strategy in June 2004 that included the divestiture of certain properties. During 2004, the Company completed over $3 billion in pretax asset sales in the United States and Canada through a series of separate unrelated transactions with various third parties. The properties divested were primarily located in the shallow waters of the Gulf of Mexico, the Western Canadian Sedimentary basin and the mid-continent region of the United States.

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2005, 2004 and 2003
3.  Divestitures (Continued)
      Under full cost accounting rules, gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. The dispositions did not significantly alter the relationship between capitalized costs and proved reserves; therefore, the proceeds from these transactions were recognized as an adjustment of capitalized costs in the respective country cost centers.
4.  Inventories
      The major classes of inventories, which are included in other current assets, are as follows:
                 
    2005   2004
millions        
Materials and supplies
  $ 101     $ 79  
Natural gas
    53       29  
Crude oil and NGLs
    27       29  
             
Total
  $ 181     $ 137  
             
5.  Properties and Equipment
      A summary of the original cost of properties and equipment by classification follows:
                 
    2005   2004
millions        
Oil and gas
  $ 26,145     $ 22,958  
Minerals
    1,208       1,208  
Marketing and trading
    516       454  
General
    586       555  
             
Total
  $ 28,455     $ 25,175  
             
      Oil and gas properties include costs of $1.3 billion and $1.6 billion at December 31, 2005 and 2004, respectively, which were excluded from capitalized costs being amortized. These amounts represent costs associated with unproved properties and major development projects in which the Company owns a direct interest. At December 31, 2005 and 2004, the Company’s investment in countries where proved reserves have not been established was $107 million and $116 million, respectively.
      During 2005, 2004 and 2003, the Company made provisions for impairments of oil and gas properties of $78 million, $72 million and $103 million, respectively. The impairments in 2005 include $35 million related to unsuccessful exploration activities in Tunisia, $30 million related to exploration activities at various international locations and $13 million related to the disposition of properties in Oman. The impairments in 2004 and 2003 included ceiling test impairments of oil and gas properties in Qatar of $62 million and $68 million, respectively, as a result of lower future production estimates and other international exploration activities.
      Total interest costs incurred during 2005, 2004 and 2003 were $270 million, $438 million and $374 million, respectively. Of these amounts, the Company capitalized $69 million, $86 million and $121 million during 2005, 2004 and 2003, respectively, as part of the cost of properties. The interest rates for capitalization are based on the Company’s weighted-average cost of borrowings used to finance the expenditures applied to costs excluded on which exploration, development and construction activities are in progress.
      Properties and equipment include internal costs related to exploration, development and construction activities of $176 million, $174 million and $187 million capitalized during 2005, 2004 and 2003, respectively.

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2005, 2004 and 2003
6.  Debt and Interest Expense
                                 
    2005   2004
         
    Principal   Carrying Value   Principal   Carrying Value
millions                
Debt
                               
6.5% Notes due 2005
  $     $     $ 170     $ 169  
7.375% Debentures due 2006
    42       42       42       42  
7% Notes due 2006
    51       50       51       50  
53/8% Notes due 2007
    142       142       142       142  
3.25% Notes due 2008
    350       350       350       349  
6.75% Notes due 2008
    47       46       47       45  
7.8% Debentures due 2008
    8       8       8       8  
7.3% Notes due 2009
    52       51       52       51  
63/4% Notes due 2011
    950       917       950       913  
61/8% Notes due 2012
    170       168       170       168  
5% Notes due 2012
    82       81       82       81  
7.05% Debentures due 2018
    114       106       114       106  
Zero Yield Puttable Contingent Debt Securities due 2021
    30       30       30       30  
7.5% Debentures due 2026
    112       106       112       106  
7% Debentures due 2027
    54       54       54       54  
6.625% Debentures due 2028
    17       17       17       17  
7.15% Debentures due 2028
    235       213       235       213  
7.20% Debentures due 2029
    135       135       135       135  
7.95% Debentures due 2029
    117       117       117       117  
71/2% Notes due 2031
    900       862       900       862  
7.73% Debentures due 2096
    61       61       61       61  
7.5% Debentures due 2096
    78       72       78       72  
71/4% Debentures due 2096
    49       49       49       49  
                         
Total debt
  $ 3,796       3,677     $ 3,966       3,840  
                         
Less current debt
            122               169  
                         
Total long-term debt
          $ 3,555             $ 3,671  
                         
      As of December 31, 2005, current debt represents $93 million principal amount of notes and debentures due in 2006 and $30 million principal amount of ZYP-CODES due 2021 that may be put to the Company in March 2006 at the option of the holders. None of the Company’s notes, debentures or securities contain ratings triggers accelerating the debt or requiring repayment. All of the Company’s debt is senior unsecured debt; therefore, all debt has equal priority with respect to the payment of both principal and interest.
      The unamortized debt discount of $119 million and $126 million as of December 31, 2005 and 2004, respectively, will be amortized over the terms of the debt issues.
      The Company has commercial paper programs that allow Anadarko to borrow funds, at rates as offered, by issuing notes to investors for terms of up to one year.
      In May 2005, the Company redeemed for cash $170 million principal amount of 6.5% Notes. In July, September and October 2004, Anadarko repurchased $1.2 billion aggregate principal amount of certain series of its outstanding debt. Premiums and related expenses for these early retirements of debt totaled $104 million and were recorded as interest expense. The Company used proceeds from asset divestitures to fund the debt reductions.

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2005, 2004 and 2003
6.  Debt and Interest Expense (Continued)
      In September 2004, the Company entered into a $750 million, five-year Revolving Credit Agreement with a syndicate of 20 U.S. and Canadian lenders. Under the terms of the agreement, the Company can, under certain conditions, request an increase in the agreement up to a total available credit amount of $1.25 billion. The credit agreement has a maximum 60% debt to capital covenant (not affected by noncash charges), and there are no material adverse change covenants nor any ratings triggers in the agreement preventing funding or requiring repayment. The agreement terminates in August 2009. As of December 31, 2005, the Company had no outstanding borrowings under this agreement; however, outstanding letters of credit on the agreement have reduced the available credit amount by less than $1 million.
      In May 2003, the Company issued $350 million principal amount of 3.25% Notes due 2008. The net proceeds from this issuance were used to reduce floating rate debt that was incurred in April 2003 to redeem the Zero Coupon Convertible Debentures due 2020. In April 2003, Anadarko redeemed for cash its callable Zero Coupon Convertible Debentures due 2020. Anadarko funded the $384 million redemption with available credit facilities that carried a lower effective interest rate.
      At December 31, 2005 and 2004, a Canadian subsidiary had outstanding $50 million of fixed-rate notes and debentures denominated in U.S. dollars. During 2005, 2004 and 2003, the Company recognized gains of $2 million, $4 million and $20 million, respectively, before income taxes associated with the foreign currency remeasurement of this debt.
      In April and May 2001, Anadarko Finance Company, a wholly owned finance subsidiary of Anadarko, issued a total of $1.9 billion in notes. The intercompany debt resulting from these transactions is of a long-term investment nature; therefore, net foreign currency translation gains of $63 million, $138 million and $376 million for 2005, 2004 and 2003, respectively, were recorded as a component of other comprehensive income.
                         
    2005   2004   2003
millions            
Interest Expense
                       
Gross interest expense
  $ 270     $ 334     $ 366  
Premium and related expenses for early retirement of debt
          104       8  
Capitalized interest
    (69 )     (86 )     (121 )
                   
Net interest expense
  $ 201     $ 352     $ 253  
                   
      Total sinking fund and installment payments related to debt for the five years ending December 31, 2010 are shown below.
         
millions    
2006
  $ 123  
2007
    142  
2008
    405  
2009
    52  
2010
     

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2005, 2004 and 2003
7.  Financial Instruments
      The following information provides the carrying value and estimated fair value of the Company’s financial instruments:
                   
    Carrying    
    Amount   Fair Value
millions        
2005
               
Cash and cash equivalents
  $ 739     $ 739  
Total debt
    3,677       4,264  
Derivative instruments (including firm transportation keep-whole agreement)
               
 
Asset
    98       98  
 
Liability
    (138 )     (138 )
2004
               
Cash and cash equivalents
  $ 874     $ 874  
Total debt
    3,840       4,525  
Derivative instruments (including firm transportation keep-whole agreement)
               
 
Asset
    52       52  
 
Liability
    (160 )     (160 )
Cash and Cash Equivalents  The carrying amount reported on the balance sheet approximates fair value.
Debt  The fair value of debt at December 31, 2005 and 2004 is the value the Company would have to pay to retire the debt, including any premium or discount to the debt holder for the differential between stated interest rate and year-end market rate. The fair values are based on quoted market prices and, where such quotes were not available, on the average rate in effect at year-end.
Derivative Instruments  The Company is exposed to price risk from changing commodity prices. Management believes it is prudent to periodically minimize the variability in cash flows on a portion of its oil and gas production. To meet this objective, the Company enters into various types of derivative financial instruments to manage fluctuations in cash flows resulting from changing commodity prices. The Company also uses fixed price physical delivery sales contracts to accomplish this objective. The types of derivative financial instruments utilized by the Company include futures, swaps and options.
      Anadarko also enters into derivative financial instruments (futures, swaps and options) and physical delivery contracts for trading purposes with the objective of generating profits from exposure to changes in the market price of natural gas and crude oil. Derivative financial instruments are also used to meet customers’ pricing requirements while achieving a price structure consistent with the Company’s overall pricing strategy. In addition, the Company may use options and swaps to reduce exposure on its firm transportation keep-whole commitment with Duke Energy Corporation (Duke).
      Futures contracts are generally used to fix the price of expected future gas sales and oil sales at major industry trading locations; e.g., Henry Hub, Louisiana for gas and Cushing, Oklahoma for oil. Swap agreements are generally used to fix or float the price of oil and gas at major trading locations. Basis swaps are used to fix or float the price differential between the price of gas at Henry Hub and various other market locations. Physical delivery purchase and sale agreements require the receipt or delivery of physical product at a specified location and price. The pricing can be fixed or market-based. Options are generally used to fix a floor and a ceiling price (collar) for expected future gas sales and oil sales. Settlements of futures contracts are guaranteed by the New York Mercantile Exchange (NYMEX) or the International Petroleum Exchange and have nominal credit risk. Swap, over-the-counter traded option and physical delivery agreements expose the Company to credit risk to

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2005, 2004 and 2003
7.  Financial Instruments (Continued)
the extent the counterparty is unable to meet its settlement commitment. The Company monitors the creditworthiness of each counterparty and assesses the impact, if any, on fair valuation and hedge accounting criteria. In addition, the Company routinely exercises its contractual right to net realized gains against realized losses in settling with its swap and option counterparties.
Oil and Gas Activities  At December 31, 2005 and 2004, the Company had option contracts, swap contracts and fixed price physical delivery contracts in place to hedge the sales price of a portion of its expected future sales of equity oil and gas production (non-trading activities). The fixed price physical delivery contracts are excluded from derivative accounting treatment under the normal sale provision. The derivative financial instruments receive hedge accounting treatment if they qualify and are so designated. For those derivatives that do not qualify for hedge accounting, unrealized gains and losses are recognized currently in oil and gas revenues.
      The fair value and the accumulated other comprehensive income balance applicable to the derivative financial instruments (excluding the physical delivery sales contracts) are as follows:
                   
    2005   2004
millions        
Fair Value — Asset (Liability)
               
 
Current
  $ (28 )   $ (58 )
 
Long-term
  $ (25 )     (12 )
             
 
Total
  $ (53 )   $ (70 )
             
Accumulated other comprehensive loss before income taxes
  $ (8 )   $ (35 )
Accumulated other comprehensive loss after income taxes
  $ (5 )   $ (22 )
      The difference between the fair value and the unrealized loss before income taxes recognized in accumulated other comprehensive income is due to premiums, recognition of unrealized gains and losses on derivatives that did not qualify for hedge accounting and hedge ineffectiveness. The net losses of $8 million ($5 million after income taxes) in the accumulated other comprehensive income balance as of December 31, 2005 are expected to be reclassified into gas and oil sales beyond 2006 as the hedged transactions occur.
      Gains attributable to cash flow hedge ineffectiveness of $10 million and $12 million were recognized in revenue during 2005 and 2004, respectively. During 2005 and 2004, net unrealized losses of zero and $22 million, respectively, (before income taxes) were reclassified from accumulated other comprehensive income to gas and oil sales for certain cash flow hedges of expected future years production for which hedge accounting was discontinued since the expected production was probable of not occurring due to either property divestitures or well performance.

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2005, 2004 and 2003
7.  Financial Instruments (Continued)
      Below is a summary of the Company’s financial derivative instruments and fixed price physical delivery sales contracts related to its oil and gas activities (non-trading) as of December 31, 2005, including the hedged volumes per day and the related weighted-average prices. The natural gas prices are NYMEX Henry Hub. The crude oil prices are a combination of NYMEX Cushing and Brent Dated. Cash flow hedges on natural gas beyond 2006 and on crude oil beyond 2011 are not significant.
                   
        Hedge Accounting
    2006   Applied
Natural Gas        
Two-Way Collars (thousand MMBtu/d)
    10       No  
Price per MMBtu
               
 
Ceiling sold price
  $ 5.88          
 
Floor purchased price
  $ 4.00          
Fixed Price Physical Delivery (thousand MMBtu/d)
    11       No  
Price per MMBtu
  $ 2.87          
Total (thousand MMBtu/d)
    21          
     
 
   MMBtu — million British thermal units
   MMBtu/d — million British thermal units per day
                           
        Five Year    
        Average   Hedge Accounting
    2006   2007-2011   Applied
Crude Oil            
Two-Way Collars (MBbls/d)
    1             No  
Price per barrel
                       
 
Ceiling sold price
  $ 26.32     $          
 
Floor purchased price
  $ 22.00     $          
Three-Way Collars (MBbls/d)
          9       Yes  
Price per barrel
                       
 
Ceiling sold price
  $     $ 85.43          
 
Floor purchased price
  $     $ 49.46          
 
Floor sold price
  $     $ 34.46          
Total (MBbls/d)
    1       9          
     
 
   MBbls/d — thousand barrels per day
      A two-way collar is a combination of options, a sold call and a purchased put. The sold call establishes a maximum price (ceiling) and the purchased put establishes a minimum price (floor) the Company will receive for the volumes under contract. A three-way collar is a combination of options, a sold call, a purchased put and a sold put. The sold call establishes a maximum price the Company will receive for the volumes under contract. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the reference price (i.e., NYMEX) plus the difference between the purchased put and the sold put strike price. The fixed price hedges consist of swaps and physical delivery contracts and establish a fixed price the Company will receive for the volumes under contract.

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2005, 2004 and 2003
7.  Financial Instruments (Continued)
Marketing and Trading Activities  Unrealized gains and losses attributed to the Company’s marketing and trading derivative instruments (both physically and financially settled) are recognized currently in earnings. The fair values of these derivatives as of December 31, 2005 and 2004 are as follows:
                   
    2005   2004
millions        
Fair Value — Asset (Liability)
               
 
Current
  $     $ 11  
 
Long-term
    5       5  
             
 
Total
  $ 5     $ 16  
             
Firm Transportation Keep-Whole Agreement A company Anadarko acquired in 2000 was a party to several long-term firm gas transportation agreements that supported its gas marketing program within its gathering, processing and marketing (GPM) business segment, which was sold in 1999 to Duke. Most of these agreements were transferred to Duke in the GPM disposition. One agreement was retained, but is managed and operated by Duke. Anadarko is not responsible for the operations of any of the contracts and does not utilize the associated transportation assets to transport the Company’s natural gas. As part of the GPM disposition, Anadarko pays Duke if transportation market values fall below the fixed contract transportation rates, while Duke pays Anadarko if the transportation market values exceed the contract transportation rates (keep-whole agreement). The term of the agreement extends through February 2009.
      The Company may periodically use derivative instruments to reduce its exposure to potential decreases in future transportation market values. While derivatives are intended to reduce the Company’s exposure to declines in the market value of firm transportation, they also limit the potential to benefit from increases in the market value of firm transportation. Due to decreased liquidity, the use of derivative instruments to manage this risk is generally limited to the forward 12 months. Unrealized gains and losses attributed to the keep-whole agreement and any associated derivative instruments are recognized currently in earnings.
      The fair value of the short-term portion of the firm transportation keep-whole agreement is calculated based on quoted natural gas basis differentials. Basis differentials are the difference in value between gas at various delivery points and the NYMEX gas futures contract price. Management believes that natural gas basis price differential quotes beyond the next 12 months are not reliable indicators of fair value due to decreasing liquidity. Accordingly, the fair value of the long-term portion is estimated based on historical regional natural gas basis differentials. The Company recognized other income of $56 million, $1 million and $9 million during 2005, 2004 and 2003, respectively, related to the keep-whole agreement and associated derivative instruments. Net (payments to) receipts from Duke for 2005 and 2004 were $1 million and $(20) million, respectively. As of December 31, 2005, other current assets included $30 million and other long-term liabilities included $22 million related to the keep-whole agreement and associated derivative instruments. As of December 31, 2004, accounts payable included $15 million and other long-term liabilities included $39 million related to the keep-whole agreement and associated derivative instruments.
      As of December 31, 2005 and 2004, the Company’s derivative financial instruments related to the firm transportation keep-whole agreement were insignificant.

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2005, 2004 and 2003
7.  Financial Instruments (Continued)
Foreign Currency Risk  The Company has Canadian subsidiaries that use the Canadian dollar as their functional currency. The Company’s other international subsidiaries use the U.S. dollar as their functional currency. To the extent that business transactions in these countries are not denominated in the respective country’s functional currency, the Company is exposed to foreign currency exchange rate risk. In addition, in these subsidiaries, certain asset and liability balances are denominated in currencies other than the subsidiary’s functional currency. These asset and liability balances are remeasured for the preparation of the subsidiary’s financial statements using a combination of current and historical exchange rates, with any resulting remeasurement adjustments included in net income during the period.
8. Sale of Future Hard Minerals Royalty Revenues
      In 2004, the Company entered into an agreement whereby it sold a portion of its future royalties associated with existing coal and trona leases to a third party for $158 million, net of transaction costs. The Company conveyed a limited-term nonparticipating royalty interest, which was carved out of the Company’s royalty interests, that entitles the third party to receive up to $229 million in future coal and trona royalty revenue over an 11-year period. Additionally, the third party is entitled to receive 5% of the aggregate royalties earned during the first ten years of the agreement that exceed $400 million. The Company retains 100% of the aggregate royalty payment receipts between $229 million and $400 million during the term of the agreement and 95% of the aggregate royalty payment receipts that are in excess of $400 million during the first ten years of the agreement. The third party relies solely on the royalty payments to recover their investment and, as such, has the risk of the royalties not being sufficient to recover their investment over the term of the agreement.
      Proceeds from this 2004 transaction were accounted for as deferred revenues, classified as liabilities on the balance sheet and reported as a financing activity in the statement of cash flows. The deferred revenues are amortized to other sales on a unit-of-revenue basis over the term of the agreement. During 2005 and 2004, the Company amortized $16 million and $10 million, respectively, of deferred revenues to other sales revenues related to this agreement. Proceeds from the transaction are reported in financing activities in the statement of cash flows and were primarily used to repurchase shares of Anadarko common stock.
      The specified future amounts that the third-party investor expects to receive, prior to the 5% of any excess described above, are shown below. These amounts and the payment timing are subject to change based upon the actual royalties received by the Company during the term of the agreement.
         
millions    
2006
  $ 24  
2007
    24  
2008
    24  
2009
    24  
2010
    24  
Later years
    74  
       
Total
  $ 194  
       

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2005, 2004 and 2003
9.  Asset Retirement Obligations
      The majority of Anadarko’s asset retirement obligations relate to the plugging and abandonment of oil and gas properties. In 2003, the Company adopted SFAS No. 143 which requires the fair value of a liability for an asset retirement obligation to be recorded in the period incurred with a corresponding increase in the carrying amount of the related long-lived asset. The related cumulative effect adjustment to 2003 net income was an increase of $74 million before income taxes or $47 million after income taxes, or $0.18 per share (diluted). Additionally in 2003, the Company recorded an initial asset retirement obligation liability of $278 million and an increase to net properties and equipment and other assets of $352 million. The Company did not recalculate historical quarterly full cost ceiling test calculations in determining the cumulative effect adjustment to net income. Excluding the cumulative effect adjustment to net income, the application of SFAS No. 143 did not have a material impact on the Company’s DD&A expense, net income or EPS in 2003.
      The asset retirement obligations are recorded at fair value and accretion expense, recognized in DD&A expense over the life of the property, increases the liability to its expected settlement value. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost.
      The following table shows changes in the Company’s asset retirement obligations. Liabilities settled in 2004 include asset retirement obligations that were assumed by the purchasers of divested properties. Revisions in estimated liabilities include, among other things, revisions to estimated property lives and the timing of settling asset retirement obligations.
                 
    2005   2004
millions        
Carrying amount of asset retirement obligations at beginning of year
  $ 210     $ 477  
Liabilities incurred
    56       37  
Liabilities settled
    (10 )     (285 )
Accretion expense
    15       25  
Revisions in estimated liabilities
    (19 )     (51 )
Impact of foreign currency exchange rate changes
    1       7  
             
Carrying amount of asset retirement obligations at end of year
  $ 253     $ 210  
             
10.  Preferred Stock
      Anadarko has $89 million of 5.46% Series B Cumulative Preferred Stock issued in the form of 0.89 million Depositary Shares, each Depositary Share representing 1/10th of a share of the 5.46% Series B Cumulative Preferred Stock. The preferred stock has no stated maturity and is not subject to a sinking fund or mandatory redemption. The shares are not convertible into other securities of the Company.
      Anadarko has the option to redeem the shares at $100 per Depositary Share on or after May 15, 2008. Holders of the shares are entitled to receive, when, and as declared by the Board of Directors, cumulative cash dividends at an annual dividend rate of $5.46 per Depositary Share. In the event of a liquidation of the Company, the holders of the shares will be entitled to receive liquidating distributions in the amount of $100 per Depositary Share, for a total of $89 million, plus any accrued or unpaid dividends, before any distributions are made on the Company’s common stock.
      Anadarko repurchased $12 million of preferred stock during 2003. No gain or loss was recorded in 2003 related to the preferred stock repurchases. For each of the years 2005, 2004 and 2003, dividends of $54.60 per share (equivalent to $5.46 per Depositary Share) were paid to holders of preferred stock.

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2005, 2004 and 2003
11.  Common Stock and Stock Options
      The changes in the Company’s shares of common stock are as follows:
                         
    2005   2004   2003
millions            
Shares of common stock issued
                       
Beginning of year
    262       257       255  
Exercise of stock options
    4       5       2  
                   
End of year
    266       262       257  
                   
Shares of common stock held in treasury
                       
Beginning of year
    23       3       3  
Purchase of treasury stock
    11       20        
                   
End of year
    34       23       3  
                   
Shares of common stock held for Employee Stock Ownership Plan
                       
Beginning of year
          1       1  
Release of Shares
          (1 )      
                   
End of year
                1  
                   
Shares of common stock held for Executives and Directors Benefits Trust
                       
Beginning of year
    2       2       2  
                   
End of year
    2       2       2  
                   
Shares of common stock outstanding at end of year
    230       237       251  
                   
      In each quarter of 2005, dividends of 18 cents per share were paid to holders of common stock. In each quarter of 2004 and in the fourth quarter of 2003, dividends of 14 cents per share were paid to holders of common stock. For the first, second and third quarters of 2003, dividends of 10 cents per share were paid to holders of common stock. The covenants in the Company’s credit agreement provide for a maximum capitalization ratio of 60% debt, exclusive of the effect of any noncash writedowns. Retained earnings were not restricted as to the payment of dividends at December 31, 2005 and 2004.
      Under the Anadarko Stockholders Rights Plan, Rights were attached automatically to each outstanding share of common stock in 1998. Each Right, at the time it becomes exercisable and transferable apart from the common stock, entitles stockholders to purchase from the Company 1/1000th of a share of a new series of junior participating preferred stock at an exercise price of $175. The Right will be exercisable only if a person or group acquires 15% or more of Anadarko common stock or announces a tender offer or exchange offer, the consummation of which would result in ownership by a person or group of 15% or more of Anadarko common stock. The Board of Directors may elect to exchange and redeem the Rights. The Rights expire in 2008.
      During 2005, a $2 billion stock buyback program announced in 2004 was completed and an additional $1 billion stock buyback program was authorized. Shares may be repurchased either in the open market or through privately negotiated transactions. The repurchase program does not obligate Anadarko to acquire any specific number of shares and may be discontinued at any time. During 2005 and 2004, Anadarko purchased 10.8 million and 20.3 million shares of common stock for $0.9 billion and $1.3 billion, respectively, under these programs through purchases in the open market, under share repurchase agreements or in connection with put option agreements.

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2005, 2004 and 2003
11.  Common Stock and Stock Options (Continued)
      As of December 31, 2005 and 2004, the Company had 2 million shares of common stock in the Anadarko Petroleum Corporation Executives and Directors Benefits Trust (Trust) to secure present and future unfunded benefit obligations of the Company. These obligations are provided for under pension plans and deferred compensation plans for certain employees and nonemployee directors of the Company. The obligations recorded in other long-term liabilities — other are $34 million and $25 million as of December 31, 2005 and 2004, respectively. The shares issued to the Trust are not considered outstanding for quorum or voting calculations and are not included in the calculation of EPS. The fair market value of these shares is included in common stock and paid-in capital and as a reduction to stockholders’ equity. See Note 20.
      Certain employees may be granted options to purchase shares of Anadarko common stock and other stock related awards under the 1999 Stock Incentive Plan. Stock options are generally granted at the fair market value of Anadarko common stock on the date of grant and have a maximum term of seven years from the date of grant. Stock option vesting terms range from one to four years.
      Nonemployee directors may be granted nonqualified stock options under the 1998 Director Stock Plan. Stock options are granted at the fair market value of Anadarko common stock on the date of grant and have a maximum term of ten years from the date of grant. Stock option vesting terms range from the date of grant up to two years.
      Unexercised stock options are included in the diluted EPS using the treasury stock method. Information regarding the Company’s stock option plans is summarized below:
                                                 
    2005   2004   2003
             
        Weighted-       Weighted-       Weighted-
        Average       Average       Average
        Exercise       Exercise       Exercise
    Shares   Price   Shares   Price   Shares   Price
option shares in millions                        
Shares under option at beginning of year
    8.1     $ 46.18       12.6     $ 43.28       15.3     $ 42.68  
Granted
    0.4     $ 87.71       0.5     $ 61.94       1.0     $ 43.31  
Exercised
    (3.7 )   $ 44.53       (4.9 )   $ 40.40       (2.1 )   $ 35.82  
Surrendered or expired
        $ 57.77       (0.1 )   $ 48.49       (1.6 )   $ 47.55  
                                     
Shares under option at end of year
    4.8     $ 51.14       8.1     $ 46.18       12.6     $ 43.28  
                                     
Options exercisable at December 31
    3.5     $ 46.64       6.5     $ 44.90       9.5     $ 42.82  
                                     
Shares available for future grant at end of year
    8.2               1.5               2.1          
                                     
Weighted-average fair value of options granted during the year
          $ 28.85             $ 22.97             $ 17.83  

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2005, 2004 and 2003
11.  Common Stock and Stock Options (Continued)
      The following table summarizes information about the Company’s stock options outstanding at December 31, 2005:
                                         
    Options Outstanding   Options Exercisable
         
        Weighted-        
    Options   Average   Weighted-   Options   Weighted-
Range of   Outstanding   Remaining   Average   Exercisable   Average
Exercise   at Year   Contractual   Exercise   at Year   Exercise
Prices   End   Life (Years)   Price   End   Price
                     
options in millions                
$30.03-42.26
    0.8       1.9     $ 35.07       0.7     $ 33.79  
$42.91-48.44
    1.1       5.4     $ 44.70       0.6     $ 44.57  
$48.53-48.53
    1.7       1.5     $ 48.53       1.7     $ 48.53  
$49.00-96.25
    1.2       5.5     $ 70.41       0.5     $ 60.43  
                               
Total
    4.8       3.5     $ 51.14       3.5     $ 46.64  
                               
      In addition, the Plans provide that shares of common stock may be granted to certain employees and nonemployee directors as restricted stock. Generally, restricted stock is subject to forfeiture restrictions and cannot be sold, transferred or disposed of during the restriction period. The holders of the restricted stock have all the rights of a stockholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions paid with respect to such shares. During 2005, 2004 and 2003, the Company granted 0.9 million, 0.3 million and 1.1 million shares, respectively, of restricted stock with a weighted-average grant date fair value of $84.76, $64.12 and $43.64 per share, respectively. In 2005, 2004 and 2003, expense related to restricted stock grants was $20 million, $11 million and $12 million, respectively.
      Anadarko and key officers of the Company have two Performance Unit Agreements with three-year terms under the 1999 Stock Incentive Plan. The agreements provide for issuance of up to a maximum of 353,200 shares of Anadarko common stock through the end of 2008. The number of shares to be issued will be determined based on a market objective and a performance objective. The shares are equally weighted between the two objectives. The number of performance units to be issued with respect to the first objective will be determined by comparing the Company’s total shareholder return to the total shareholder return of a predetermined group of peer companies over the performance period. The number of performance units to be issued with respect to the second objective will be determined based on the Company’s reserve replacement efficiency ratio over the performance period. During 2005, the Company recognized expense of $2 million under the agreements.
      Anadarko and a key officer of the Company have entered into a Performance Share Agreement under the 1999 Stock Incentive Plan. The agreement provides for issuance of up to 80,000 shares of Anadarko common stock after a two-year period that ended in 2005 and a four-year period ending in 2007. The number of shares to be issued is determined by comparing the Company’s total shareholder return to the total shareholder return of a predetermined group of peer companies. In February 2006, 14,400 shares were issued for the period ended in 2005. During both 2005 and 2004, the Company recognized expense of $1 million under the agreement.

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ANADARKO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2005, 2004 and 2003
11.  Common Stock and Stock Options (Continued)
      The reconciliation between basic and diluted EPS is as follows:
                                                                         
    For the Year Ended   For the Year Ended   For the Year Ended
    December 31, 2005   December 31, 2004   December 31, 2003
             
        Per Share       Per Share       Per Share
    Income   Shares   Amount   Income   Shares   Amount   Income   Shares   Amount
millions except per share amounts                                    
Basic EPS
                                                                       
Net income available to common stockholders before change in accounting principle
  $ 2,466