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

			Page
PART I
	Item 1.	Business		2
		General		2
		Oil and Gas Properties and Activities		2
		Proved Reserves		2
		Sales Volumes and Prices		4
		Properties and Activities — United States		5
		Properties and Activities — Canada		10
		Properties and Activities — Algeria		10
		Properties and Activities — Other International		12
		Drilling Programs		13
		Drilling Statistics		13
		Productive Wells		14
		Properties and Leases		15
		Marketing, Gathering and Liquefied Natural Gas Properties and Activities		15
		Minerals Properties and Activities		16
		Segment and Geographic Information		16
		Employees		16
		Regulatory Matters and Additional Factors Affecting Business		17
		Title to Properties		17
		Capital Spending		17
		Ratios of Earnings to Fixed Charges and Earnings to Combined
		Fixed Charges and Preferred Stock Dividends		17
	Item 1a.	Risk Factors		17
	Item 1b.	Unresolved Staff Comments		22
	Item 2.	Properties		22
	Item 3.	Legal Proceedings		23
	Item 4.	Submission of Matters to a Vote of Security Holders
		Executive Officers of the Registrant		24
PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		26
	Item 6.	Selected Financial Data		27
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		28
	Item 7a.	Quantitative and Qualitative Disclosures About Market Risk		48
	Item 8.	Financial Statements and Supplementary Data		50
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		107
	Item 9a.	Controls and Procedures		107
	Item 9b.	Other Information		107
PART III
	Item 10.	Directors and Executive Officers of the Registrant		108
	Item 11.	Executive Compensation		108
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		108
	Item 13.	Certain Relationships and Related Transactions		108
	Item 14.	Principal Accounting Fees and Services		108
PART IV
	Item 15.	Exhibits, Financial Statement Schedules		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.

1

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.

2

      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.

3

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

4

      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.

5

      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.

6

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.

7

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.

8

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.

9

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 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

34

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%.

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:

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.

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.

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.

48

      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.

49

Item 8. Financial Statements and Supplementary Data

ANADARKO PETROLEUM CORPORATION

INDEX

CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Management		51
Management’s Assessment of Internal Control Over Financial Reporting		51
Reports of Independent Registered Public Accounting Firm		52
Statements of Income, Three Years Ended December 31, 2005		54
Balance Sheets, December 31, 2005 and 2004		55
Statements of Stockholders’ Equity, Three Years Ended December 31, 2005		56
Statements of Comprehensive Income, Three Years Ended December 31, 2005		57
Statements of Cash Flows, Three Years Ended December 31, 2005		58
Notes to Consolidated Financial Statements		59
Supplemental Information on Oil and Gas Exploration and Production Activities		91
Supplemental Quarterly Information		106

50

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.

James T. Hackett

Chairman, President and Chief Executive Officer

R. A. Walker

Senior Vice President, Finance and

Chief Financial Officer

March 2, 2006

51

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.

Houston, Texas

March 2, 2006

52

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.

Houston, Texas

March 2, 2006

53

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.

54

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.

55

ANADARKO PETROLEUM CORPORATION

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.

56

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.

57

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.

58

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.

59

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.

60

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

61

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.

62

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,

63

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.

64

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.

65

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.

66

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		—

67

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

68

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.

69

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.

70

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.

71

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

72

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.

73

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.

74

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

75

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.

76

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		235	$	10.49	$	1,601		250	$	6.41	$	1,240		250	$	4.97
Effect of convertible debentures and ZYP-CODES		—		—				—		—				3		2
Effect of dilutive stock options, performance-based stock awards and common stock put options		—		2				—		2				—		1
Diluted EPS
Net income available to common stockholders before change in accounting principle plus assumed conversion	$	2,466		237	$	10.39	$	1,601		252	$	6.36	$	1,243		253	$	4.91

      For the years ended December 31, 2005, 2004 and 2003, options for zero, 0.7 million and 8.4 million average shares, respectively, of common stock were excluded from the diluted EPS calculation because the options’ exercise price was greater than the average market price of common stock for the respective period.

12.  Statements of Cash Flows Supplemental Information

      The amounts of cash paid for interest (net of amounts capitalized) and income taxes are as follows:

	2005		2004		2003
millions
Interest	$	191	$	345	$	262
Income taxes	$	439	$	256	$	90

13.  Major Customers

      The Company’s natural gas is sold to interstate and intrastate gas pipelines, direct end-users, industrial users, local distribution companies and gas marketers. Crude oil and condensate are sold to marketers, gatherers and refiners. NGLs are sold to direct end-users, refiners and marketers. These purchasers are located in the United States, Bermuda, Canada, Singapore and Switzerland. The majority of the Company’s receivables are paid within two months following the month of purchase.

      The Company generally performs a credit analysis of customers prior to making any sales to new customers or increasing credit for existing customers. Based upon this credit analysis, the Company may require a standby letter of credit or a financial guarantee. As of December 31, 2005 and 2004, accounts receivable are shown net of allowance for uncollectible accounts of $6 million and $9 million, respectively.

      In 2005, 2004 and 2003, sales to affiliates of Duke were $747 million, $903 million and $1.4 billion, respectively, which accounted for 11%, 15% and 28% of the Company’s total 2005, 2004 and 2003 revenues, respectively. These sales relate primarily to the Company’s oil and gas segment.

77

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

14.  Segment and Geographic Information

      Anadarko’s primary business segments are vertically integrated business units that are principally within the oil and gas industry. These segments are managed separately because of their unique technology, marketing and distribution requirements. The Company’s three segments are upstream oil and gas activities, marketing and trading activities and minerals activities. The oil and gas exploration and production segment finds and produces natural gas, crude oil, condensate and NGLs. The marketing and trading segment is responsible for gathering, transporting and selling most of Anadarko’s natural gas production as well as volumes of gas, oil and NGLs purchased from third parties. The marketing and trading segment is also responsible for the development of liquefied natural gas facilities and markets. The minerals segment participates in non-operated joint ventures and royalty arrangements in several coal, trona (natural soda ash) and industrial mineral mines. The segment shown as All Other and Intercompany Eliminations includes other smaller operating units, corporate activities, financing activities and intercompany eliminations.

      The Company’s accounting policies for segments are the same as those described in the summary of significant accounting policies. Management evaluates segment performance based on operating income and various other factors. Transfers between segments are accounted for at market value.

      The following table illustrates information related to Anadarko’s business segments. Operating income (loss), shown in the table below, agrees to the consolidated statement of income where it reconciles to income before income taxes.

		Oil and Gas		Marketing					All Other and
		Exploration		and					Intercompany
		and Production		Trading			Minerals		Eliminations			Total
millions
2005
Total Revenues		$	6,909	$	198		$	40	$	(47	)	$	7,100
Depreciation, depletion and amortization			1,262		21			3		57			1,343
Impairments related to oil and gas properties			78		—			—		—			78
Other costs and expenses			1,231		178			2		253			1,664
	Total costs and expenses		2,571		199			5		310			3,085
Operating income (loss)		$	4,338	$	(1	)	$	35	$	(357	)	$	4,015
Net properties and equipment		$	15,928	$	405		$	1,188	$	341		$	17,862
Capital expenditures		$	3,306	$	77		$	—	$	54		$	3,437
Goodwill		$	1,196	$	—		$	—	$	—		$	1,196
2004
Total Revenues		$	5,872	$	202		$	35	$	(30	)	$	6,079
Depreciation, depletion and amortization			1,367		20			4		56			1,447
Impairments related to oil and gas properties			72		—			—		—			72
Other costs and expenses			1,210		149			2		306			1,667
	Total costs and expenses		2,649		169			6		362			3,186
Operating income (loss)		$	3,223	$	33		$	29	$	(392	)	$	2,893
Net properties and equipment		$	14,017	$	357		$	1,192	$	347		$	15,913
Capital expenditures		$	2,993	$	57		$	—	$	40		$	3,090
Goodwill		$	1,309	$	—		$	—	$	—		$	1,309

78

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

14.  Segment and Geographic Information (Continued)

		Oil and Gas		Marketing				All Other and
		Exploration		and				Intercompany
		and Production		Trading		Minerals		Eliminations			Total
millions
2003
Total Revenues		$	4,926	$	154	$	29	$	4		$	5,113
Depreciation, depletion and amortization			1,223		18		3		53			1,297
Impairments related to oil and gas properties			103		—		—		—			103
Other costs and expenses			1,102		114		2		296			1,514
	Total costs and expenses		2,428		132		5		349			2,914
Operating income (loss)		$	2,498	$	22	$	24	$	(345	)	$	2,199
Net properties and equipment		$	15,560	$	253	$	1,199	$	384		$	17,396
Capital expenditures		$	2,719	$	33	$	—	$	40		$	2,792
Goodwill		$	1,389	$	—	$	—	$	—		$	1,389

      The following table shows Anadarko’s revenues (based on the origin of the sales) and net properties and equipment by geographic area:

	2005		2004		2003
millions
Revenues
United States	$	4,573	$	4,131	$	3,521
Canada		913		955		867
Algeria		1,292		770		541
Other International		322		223		184
Total	$	7,100	$	6,079	$	5,113

	2005		2004
millions
Net Properties and Equipment
United States	$	13,518	$	11,819
Canada		2,777		2,425
Algeria		843		881
Other International		724		788
Total	$	17,862	$	15,913

15.  Restructuring Costs

      In July 2003, Anadarko announced a cost reduction plan to reduce overhead costs from the Company’s cost structure. This plan included a reduction in personnel and corporate expenses and was substantially completed in 2003. The related costs of $40 million were charged to general and administrative costs in 2003 as specific liabilities were incurred. Of this amount, $25 million is related to corporate costs and $15 million is related to oil and gas costs.

79

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

16.  Other Taxes

      Significant taxes, other than income taxes, are as follows:

	2005		2004		2003
Production and severance	$	219	$	163	$	154
Ad valorem		126		119		116
Payroll and other		31		30		24
Total	$	376	$	312	$	294

17.  Other (Income) Expense

      Other (income) expense consists of the following:

	2005			2004			2003
millions
Operating lease settlement	$	—		$	63		$	—
Firm transportation keep-whole contract valuation		(56	)		(1	)		(9	)
Interest income		(27	)		(16	)		(3	)
Foreign currency translation (gains) losses		—			2			(19	)
Other		2			16			3
Total	$	(81	)	$	64		$	(28	)

      The operating lease settlement in 2004 relates to the Corpus Christi West Plant Refinery (West Plant). See Note 21. Foreign currency transaction (gains) losses for the years ended December 31, 2005, 2004 and 2003, exclude (benefits) expenses of $(3) million, $(6) million and $8 million, respectively, related to the remeasurement of the Venezuelan deferred tax liability, which amounts are included in income tax expense.

18.  Income Taxes

      Income tax expense, including deferred amounts, is summarized as follows:

	2005		2004		2003
millions
Current
Federal	$	327	$	283	$	66
State		2		22		4
Foreign		529		281		147
Total		858		586		217
Deferred
Federal		363		175		380
State		64		35		28
Foreign		139		75		104
Total		566		285		512
Total	$	1,424	$	871	$	729

80

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

18.  Income Taxes (Continued)

      Total income taxes differed from the amounts computed by applying the statutory income tax rate to income before income taxes. The sources of these differences are as follows:

		2005			2004			2003
millions
Income Before Income Taxes
	Domestic	$	2,356		$	1,544		$	1,359
	Foreign		1,539			933			615
Total		$	3,895		$	2,477		$	1,974
Statutory tax rate			35	%		35	%		35	%
Tax computed at statutory rate		$	1,363		$	867		$	691
Adjustments resulting from:
	State income taxes (net of federal income tax benefit)		43			37			21
	Foreign taxes in excess of federal statutory tax rate		129			44			81
	Cross border financing		(51	)		(51	)		(51	)
	Effect of change in Canadian income tax rates		—			(15	)		(46	)
	Excess U.S. foreign tax credit generated in current year		(79	)		—			—
	Other — net		19			(11	)		33
Total income tax expense		$	1,424		$	871		$	729
Effective tax rate			37	%		35	%		37	%

      The effect of stock-based compensation expense for tax purposes in excess of amounts recognized for financial accounting purposes has been credited directly to stockholders’ equity in amounts of $53 million, $36 million and $1 million for 2005, 2004 and 2003, respectively.

      Tax effects related to restructuring of certain foreign operations in prior years have been recorded to other assets on the balance sheet and are being recognized in the income statement over the estimated life of the related properties under Accounting Research Bulletin (ARB) No. 51, “Consolidated Financial Statements.” During 2005, an ARB No. 51 liability of $17 million associated with a prior year restructuring of the Company’s Venezuelan operations was reversed to income.

      The Company is currently under examination by the Internal Revenue Service (IRS), various state and foreign taxing jurisdictions covering multiple tax years. Although the Company believes that it has adequately provided for income taxes and related interest which may become payable for years that are under examination, the resolution of pending tax issues cannot be predicted with certainty and differences may occur in the future.

      Certain subsidiaries of the Company are currently in administrative appeals with the IRS or under examination with various foreign jurisdictions for years prior to their acquisition by the Company. The Company determined in 2005 and 2004 that deferred tax liabilities related to pre-acquisition tax contingencies of approximately $101 million and $103 million, respectively, were no longer required due to completion of audits and administrative appeals, filing amended returns, reevaluation of contingencies and changes in the Company’s estimate of the ultimate tax basis of acquired assets and liabilities. Accordingly, these liabilities were reversed with an offsetting decrease to goodwill. Future events, including the conclusion of examinations and administrative appeals by taxing authorities and resolution of pre-acquisition contingencies, may result in additional adjustments to goodwill.

81

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

18.  Income Taxes (Continued)

      The tax effects of temporary differences that give rise to significant portions of the deferred assets (liabilities) at December 31, 2005 and 2004 are as follows:

	2005			2004
millions
Net operating loss carryforward	$	—		$	83
Other		9			17
Net current deferred tax assets		9			100
Oil and gas exploration and development costs		(38	)		—
Other		(6	)		—
Net current deferred tax liability		(44	)		—
Oil and gas exploration and development costs		(3,929	)		(3,888	)
Mineral operations		(443	)		(441	)
Other		(762	)		(515	)
Gross long-term deferred tax liabilities		(5,134	)		(4,844	)
Oil and gas exploration and development costs		71			87
Net operating loss carryforward		88			90
Foreign tax credit carryforward		83			17
Other		384			495
Gross long-term deferred tax assets		626			689
Less: valuation allowance on deferred tax assets not expected to be realized		(211	)		(259	)
Net long-term deferred tax assets		415			430
Net long-term deferred tax liabilities		(4,719	)		(4,414	)
Total deferred taxes	$	(4,754	)	$	(4,314	)

      Total deferred taxes at December 31, 2005 and 2004 include state deferred taxes of approximately $213 million and $172 million, respectively. Total deferred taxes as of December 31, 2005 and 2004 also include foreign deferred taxes of approximately $1,044 million and $906 million, respectively.

      As of December 31, 2004, the Company no longer meets the indefinite reinvestment criterion of Accounting Principles Board (APB) Opinion No. 23, “Accounting for Income Taxes — Special Areas,” for the unremitted earnings of foreign subsidiaries. The resulting deferred tax liabilities have been offset with foreign tax credits.

      The Jobs Act introduced a special one-time, 85% dividends received deduction on the repatriation of certain foreign earnings to a U.S. taxpayer provided certain criteria are met. 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.

      Tax carryforwards at December 31, 2005, which are available for utilization on future income tax returns, are as follows:

					Domestic		Foreign
	Domestic		Foreign		Expiration		Expiration
millions
Net operating loss — regular tax	$	—	$	6		—		2010
Net operating loss — state	$	1,437	$	—		2006-2025		—
Capital loss	$	—	$	113		—		indefinite
Foreign tax credit	$	83	$	—		2011-2015		—

82

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

19.  Commitments

LNG Facility Related Commitments   In 2005, the Company entered into precedent agreements with a third party in order to secure delivery of natural gas from a liquefied natural gas facility Anadarko is constructing in Nova Scotia, Canada, referred to as 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.

Leases  The Company has long-term drilling rig commitments that qualify as operating leases of $1,998 million. The Company also has various commitments under noncancelable operating lease agreements of $329 million for a production platform and equipment, buildings, facilities and aircraft. These operating leases expire at various dates through 2016. The majority of the operating lease agreements are expected to be renewed or replaced as they expire. The Company’s balance sheet does not include assets or liabilities related to these operating lease agreements since these agreements were structured as operating leases for accounting purposes. At December 31, 2005, future minimum lease payments under operating leases are as follows:

	Operating
	Leases
millions
2006	$	365
2007		653
2008		643
2009		515
2010		103
Later years		48
Total future minimum lease payments	$	2,327

      Total rental expense, net of sublease income, amounted to $46 million, $47 million and $31 million in 2005, 2004 and 2003, respectively. Total rental expense includes contingent rental expense related to processing fees of $7 million and $8 million in 2005 and 2004, respectively.

83

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

19.  Commitments (Continued)

Drilling Rig Commitments  During 2005, Anadarko entered into various agreements to secure the necessary drilling rigs to execute a portion of its drilling strategy over the next several years. As part of the plan, Anadarko, with two other producers, signed a four-year rig-share agreement under which a third party will build and own a new semi-submersible drilling rig with a target delivery date of mid-2008. Anadarko committed to 50% of the rig time at a cost of approximately $200 million over the contract term. The Company also executed a three-year contract for the Discoverer Spirit drillship and a contract for the Deepwater Millennium drillship of slightly more than four years. The Discoverer Spirit drillship contract begins in 2007 and the Deepwater Millennium drillship contract begins in 2006 for a combined commitment of $1.1 billion. In addition, the Company executed a three-year drilling contract to secure the Belford Dolphin drillship at a cost of $460 million over the contract period. It is anticipated the vessel will be released to Anadarko beginning in mid-2007. The Company also has multi-year contracts for drilling rigs onshore in the United States and Canada. The table of future minimum lease payments above includes approximately $2.0 billion for the Discoverer Spirit, Deepwater Millennium and Belford Dolphin drillships and certain contracts for onshore United States and Canada drilling rigs that qualify as operating leases. Lease payments for these drilling rig commitments, net of amounts billed to partners, will be capitalized as a component of oil and gas properties.

Production Platforms  During 2004, Anadarko and a group of energy companies (Atwater Valley Producers Group) executed agreements with a third party for the dedication, processing and gathering of natural gas and condensate production from several natural gas fields in the deepwater Gulf of Mexico. The third party will 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 of future minimum lease payments above does not include any amounts related to these agreements. The agreements do not contain any purchase options, purchase obligations or value guarantees.

      In 2002, the Company entered into an agreement under which a floating production platform for its Marco Polo discovery in the deepwater Gulf of Mexico was installed in 2004. The other party to the agreement constructed and owns the platform and production facilities that upon mechanical completion became operated by Anadarko. The agreement provides that Anadarko dedicate its production from Green Canyon Block 608 and 11 other Green Canyon blocks to the production facilities. The agreement requires a monthly demand charge of approximately $2 million for five years and a processing fee based upon production throughput. Anadarko’s commitment to begin payments for the monthly demand charges was incurred upon mechanical completion in 2004. The table of future minimum lease payments above includes amounts related to the monthly demand charge for this agreement. The agreement does not contain any purchase options, purchase obligations or value guarantees.

Buildings  The Company leases two corporate office buildings located in The Woodlands, Texas. The lease term is seven years and the monthly lease payments are based on the London interbank borrowing rate applied against the lease balance. The lease contains various covenants including covenants regarding the Company’s financial condition. Default under the lease, including violation of these covenants, could require the Company to purchase the facilities for a specified amount, which approximates the lessor’s original cost of $214 million. As of December 31, 2005, the Company was in compliance with these covenants.

      At the end of the lease term, the Company has an option to either purchase the facilities for the purchase option amount of the lease balance plus any outstanding lease payments or assist the lessor in the sale of the properties. The Company has provided a residual value guarantee for any deficiency of up to $187 million if the

84

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

19.  Commitments (Continued)

properties are sold for less than the lease balance. In addition, the Company is entitled to any proceeds from a sale of the properties in excess of the lease balance.

      The Company has a $5 million liability and corresponding prepaid rent asset as of December 31, 2005 related to its residual value guarantee on the corporate office buildings. If the Company determines that it is probable that the expected fair value of the property at the end of the lease term will be less than the lease balance, the liability will be adjusted accordingly. Currently, Management does not believe it is probable that the fair market value of the properties will be less than the lease balance at the end of the lease term.

Aircraft  The table of future minimum lease payments above includes the Company’s lease payment obligations of $44 million related to aircraft leases. One lease includes a residual value guarantee for any deficiency if the aircraft is sold for less than the sale option amount (approximately $11 million). In addition, the Company is entitled to any proceeds from a sale of the aircraft in excess of the sale option amount. No liability has been recorded related to this guarantee.

20.  Pension Plans, Other Postretirement Benefits and Employee Savings Plans

Pension Plans and Other Postretirement Benefits  The Company has defined benefit pension plans and supplemental pension plans that are noncontributory and a foreign contributory defined benefit pension plan. The Company also provides certain health care and life insurance benefits for retired employees. Health care benefits are funded by contributions from the Company and the retiree, with the retiree contributions adjusted according to the provisions of the Company’s health care plans. The Company’s retiree life insurance plan is noncontributory. The Company uses a December 31 measurement date for the majority of its plans.

      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.

85

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

20. Pension Plans, Other Postretirement Benefits and Employee Savings Plans (Continued)

      The following table sets forth the Company’s pension and other postretirement benefits changes in projected benefit obligation, fair value of plan assets, funded status and amounts recognized in the financial statements as of December 31, 2005 and 2004.

		Pension Benefits						Other Benefits
		2005			2004			2005			2004
millions
Change in projected benefit obligation
Benefit obligation at beginning of year		$	675		$	559		$	164		$	161
Service cost			36			24			15			11
Interest cost			38			32			9			9
Plan amendments			—			(2	)		—			—
Special termination benefits			—			1			—			—
Actuarial (gain) loss			61			130			6			(10	)
Foreign currency exchange rate change			(3	)		5			—			—
Benefit payments			(45	)		(74	)		(6	)		(7	)
Benefit obligation at end of year		$	762		$	675		$	188		$	164
Change in plan assets
Fair value of plan assets at beginning of year		$	475		$	375		$	—		$	—
Actual return on plan assets			38			54			—			—
Employer contributions			121			116			7			7
Foreign currency exchange rate change			(1	)		4			—			—
Benefit payments			(45	)		(74	)		(7	)		(7	)
Fair value of plan assets at end of year		$	588		$	475		$	—		$	—
Funded status of the plan		$	(174	)	$	(200	)	$	(188	)	$	(164	)
Unrecognized actuarial loss			314			271			47			44
Unrecognized prior service cost			6			7			1			—
Total recognized		$	146		$	78		$	(140	)	$	(120	)
Total recognized amounts in the balance sheet consist of:
	Prepaid benefit cost	$	170		$	32		$	—		$	—
	Accrued benefit liability		(49	)		(83	)		(140	)		(120	)
	Intangible asset		—			8			—			—
	Other comprehensive expense		25			121			—			—
Total recognized		$	146		$	78		$	(140	)	$	(120	)

      The accumulated benefit obligation for all defined benefit pension plans was $589 million and $534 million as of December 31, 2005 and 2004, respectively. The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were $57 million, $49 million and zero, respectively, as of December 31, 2005, and $648 million, $507 million and $427 million, respectively, as of December 31, 2004. The Company’s benefit obligation under the unfunded pension plans are secured by the Anadarko Petroleum Corporation Executives and Directors Benefits Trust. See Note 11.

86

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

20. Pension Plans, Other Postretirement Benefits and Employee Savings Plans (Continued)

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

	Pension Benefits									Other Benefits
	2005			2004			2003			2005		2004		2003
millions
Components of net periodic benefit cost
Service cost	$	36		$	24		$	22		$	15	$	11	$	7
Interest cost		38			32			34			9		9		9
Expected return on plan assets		(38	)		(33	)		(30	)		—		—		—
Settlements		—			—			17			—		—		—
Special termination benefits		—			1			3			—		—		—
Amortization values and deferrals		18			11			14			2		3		2
Net periodic benefit cost	$	54		$	35		$	60		$	26	$	23	$	18

      As a result of executive retirements in 2003, a settlement charge of $17 million was recorded to general and administrative expense in 2003. The increase (decrease) in the Company’s minimum liability included in other comprehensive income related to the pension plans was $(96) million, $31 million and $(29) million before income taxes for 2005, 2004 and 2003, respectively.

      Following are the weighted-average assumptions used by the Company in determining the pension and other postretirement benefit obligations as of December 31, 2005 and 2004:

	Pension						Other
	Benefits						Benefits
	2005			2004			2005			2004
percent
Discount rate		5.75	%		5.75	%		5.75	%		5.75	%
Rates of increase in compensation levels		5.0	%		5.0	%		5.0	%		5.0	%

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

      Following are the weighted-average assumptions used by the Company in determining the net periodic pension and other postretirement benefit cost for 2005 and 2004:

	Pension						Other
	Benefits						Benefits
	2005			2004			2005			2004
percent
Discount rate		5.75	%		6.25	%		5.75	%		6.25	%
Long-term rate of return on plan assets		8.0	%		8.0	%		n/a			n/a
Rates of increase in compensation levels		5.0	%		5.0	%		5.0	%		5.0	%

      The Company has adopted a balanced, diversified investment strategy, with the intent of maximizing returns without exposure to undue risk. Investments are typically made through investment managers across several investment categories (Domestic Large and Small Cap, International, Domestic Fixed Income, Real Estate and

87

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

20. Pension Plans, Other Postretirement Benefits and Employee Savings Plans (Continued)

Private Equity), with selective exposure to Growth/ Value investment styles. Performance for each investment is measured relative to the appropriate index benchmark for its category. Target asset allocation percentages by major category are 65% equity securities, 25% fixed income, 5% real estate and 5% private equity. Investment managers have full discretion as to investment decisions regarding all funds under their management to the extent permitted within investment guidelines. Certain investments are prohibited, including short sales, sales on margin, securities of companies in bankruptcy, investments in financial futures and commodities and currency exchanges.

      The Company’s pension plans as of December 31, 2005 and 2004 were comprised of assets by category as follows:

	2005			2004
percent
Assets
Equity securities		79	%		73	%
Fixed income		19			23
Other		2			4
Total		100	%		100	%

      There are no direct investments in Anadarko common stock included in plan assets; however, there may be indirect investments in Anadarko common stock through the plans’ mutual fund investments. The expected long-term rate of return on assets assumption was determined using the year-end 2005 pension investment balances by category and projected target asset allocations for 2006. The expected return for each of these categories was determined by using capital market projections provided by the Company’s external pension consultants, with consideration of actual five-year performance statistics for investments in place.

      The following benefit payments and federal Medicare Part D subsidy receipts, which reflect expected future service, as appropriate, are expected to be paid (received) as follows:

	Pension		Other		Federal
	Benefit		Benefit		Subsidy
	Payments		Payments		Receipts
millions
2006	$	40	$	8	$	(1	)
2007		36		8		(1	)
2008		40		9		(1	)
2009		43		10		(1	)
2010		49		11		(1	)
2011-2015		342		72		(6	)

      For year-end 2005 measurement purposes, an 11% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2005. The rate was assumed to decrease gradually to 5% in 2011 and later years. For year-end 2004 measurement purposes, a 12% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2004. The rate was assumed to decrease gradually to 5% in 2011 and later years. The assumed health care cost trend rate has a significant effect on the amounts reported for the health care plan. A 1% change in the assumed health care cost trend rate over the projected period would have the following effects:

	1% Increase		1% Decrease
millions
Effect on total of service and interest cost components	$	4	$	(3	)
Effect on other postretirement benefit obligation	$	20	$	(17	)

88

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

20. Pension Plans, Other Postretirement Benefits and Employee Savings Plans (Continued)

Employee Savings Plan  The Company has an employee savings plan (ESP), which is a defined contribution plan. The Company matches a portion of employees’ contributions. Participation in the ESP is voluntary and all regular employees of the Company are eligible to participate. The Company charged to expense plan contributions of $14 million, in each of the years 2005, 2004 and 2003. The contributions were funded through the Employee Stock Ownership Plan (ESOP) until mid-2005 when the shares of the ESOP were depleted. Contributions are currently funded in cash.

21.  Contingencies

General  Litigation charges of $64 million and $62 million were expensed during 2005 and 2004, respectively. There were no significant litigation charges in 2003. 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. On September 14, 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.

Other  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.

Lease Agreement  The Company, through one of its affiliates (formerly a subsidiary of Union Pacific Resources Group, Inc. or UPRG), is a party to a lease agreement for the West Plant, a refinery facility located in Corpus Christi, Texas. The initial term of the lease expired December 31, 2003, but Anadarko had renewal options extending through January 31, 2011 at fair market rental rates and the right to purchase the West Plant at a fair market sales value on January 31, 2011. In conjunction with UPRG exiting the refinery business in 1987, the West Plant was subleased to CITGO Petroleum Corporation (CITGO) under terms substantially the same as the Company’s lease, with sublease payments during any renewal period equal to the lesser of the fair market

89

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2005, 2004 and 2003

21.  Contingencies (Continued)

rental rates as determined in the Company’s lease or $5 million. Additionally, CITGO has the option under the sublease to purchase the West Plant from the Company on January 31, 2011 at a specified purchase price.

      For the renewal term, the fair market rental rates of the West Plant were to be determined by the appraisal process specified in the lease agreement. Prior to the completion of the fair market rental rate determination by the appraisers, Anadarko and the lessor agreed to rental rates for the period 2004 to 2011 and a maximum purchase price at the end of the lease term. Subsequent to this agreement, Anadarko also agreed to purchase the West Plant on January 31, 2011 at a price less than the previously stipulated maximum amount. Since the agreed upon rental rates exceeded the capped sublease payments from CITGO and the Company’s purchase price exceeded CITGO’s specified purchase price in 2011, the Company recorded a liability of $63 million in 2004. This amount represented the present value of the excess of the annual rental amounts payable to the lessor over the amounts under the sublease for 2004 to 2011 as well as the present value of the excess of the purchase price payable to the lessor in 2011 over CITGO’s specified purchase price.

Guarantees and Indemnifications  The Company has made a residual value guarantee in connection with an aircraft operating lease for any deficiency if the aircraft is sold for less than the maximum lessee risk amount of approximately $11 million. No liability has been recorded related to this guarantee.

      The Company is guarantor for specific financial obligations of a trona mining affiliate. The investment in this entity, which is not a consolidated subsidiary, is accounted for using the equity method. The Company has guaranteed a portion of amounts due under a revolving credit agreement, a term loan and various letters of credit used to secure industrial revenue bonds. The Company’s guarantees under the revolving credit agreement and the term loan expire in 2007 and 2010, respectively, coinciding with the maturity of those agreements. The Company’s guarantees under the letters of credit securing the industrial revenue bonds expire in 2006; however, these letters of credit and the related guarantees are expected to be extended or to continue until the maturity dates of the obligations which range from 2007 to 2018. The Company would be obligated to pay up to $15 million for the revolving credit agreement, $15 million for the term loan and $15 million for the industrial revenue bonds if the affiliate defaulted on these obligations. No liability has been recognized for these guarantees as of December 31, 2005.

90

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Oil and Gas Exploration and Production Activities

      The following is historical revenue and cost information relating to the Company’s oil and gas activities.

Costs Excluded

      Costs associated with unproved properties and major development projects of $1.3 billion and $1.6 billion as of December 31, 2005 and 2004, respectively, are excluded from amounts subject to amortization. The majority of the evaluation activities are expected to be completed within three to ten years.

Costs Excluded by Year Incurred

	Year Costs Incurred								Excluded
									Costs at
	Prior								Dec. 31,
	Years		2003		2004		2005		2005
millions
Property acquisition	$	581	$	40	$	90	$	230	$	941
Exploration		37		26		52		140		255
Capitalized interest		62		9		13		29		113
Total	$	680	$	75	$	155	$	399	$	1,309

Costs Excluded by Country

							Other
	U.S.		Canada		Algeria		International		Total
millions
Property acquisition	$	834	$	101	$	—	$	6	$	941
Exploration		142		3		5		105		255
Capitalized interest		91		7		—		15		113
Total	$	1,067	$	111	$	5	$	126	$	1,309

Changes in Costs Excluded by Country

										Other
	U.S.			Canada			Algeria			International			Total
millions
December 31, 2003	$	2,030		$	343		$	9		$	142		$	2,524
Additional costs incurred		410			51			8			50			519
Costs transferred to DD&A pool		(1,129	)		(229	)		(11	)		(44	)		(1,413	)
Impact of foreign currency exchange rate changes		—			12			—			—			12
December 31, 2004		1,311			177			6			148			1,642
Additional costs incurred		691			62			7			64			824
Costs transferred to DD&A pool		(935	)		(130	)		(8	)		(86	)		(1,159	)
Impact of foreign currency exchange rate changes		—			2			—			—			2
December 31, 2005	$	1,067		$	111		$	5		$	126		$	1,309

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SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Capitalized Costs Related to Oil and Gas Producing Activities

		2005		2004
millions
United States
Capitalized
	Unproved properties	$	1,067	$	1,311
	Proved properties		17,282		14,566
			18,349		15,877
Accumulated depreciation, depletion and amortization			6,627		5,845
Net capitalized costs			11,722		10,032
Canada
Capitalized
	Unproved properties		111		177
	Proved properties		5,148		4,457
			5,259		4,634
Accumulated depreciation, depletion and amortization			2,611		2,307
Net capitalized costs			2,648		2,327
Algeria
Capitalized
	Unproved properties		5		6
	Proved properties		1,262		1,199
			1,267		1,205
Accumulated depreciation, depletion and amortization			432		335
Net capitalized costs			835		870
Other International
Capitalized
	Unproved properties		126		148
	Proved properties		1,144		1,094
			1,270		1,242
Accumulated depreciation, depletion and amortization			547		454
Net capitalized costs			723		788
Total
Capitalized
	Unproved properties		1,309		1,642
	Proved properties		24,836		21,316
			26,145		22,958
Accumulated depreciation, depletion and amortization			10,217		8,941
Net capitalized costs		$	15,928	$	14,017

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SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Costs Incurred in Oil and Gas Producing Activities

		2005		2004			2003
millions
United States
Property acquisition
	Exploration	$	216	$	123		$	100
	Development		44		(1	)		203
Exploration			527		339			454
Development(1)			1,854		1,809			1,400
Total United States(2)			2,641		2,270			2,157
Canada
Property acquisition
	Exploration		40		20			24
	Development		1		4			—
Exploration			134		126			176
Development(1)			319		429			307
Total Canada(2)			494		579			507
Algeria
Exploration			12		20			17
Development(1)			45		40			62
Total Algeria(2)			57		60			79
Other International
Property acquisition
	Exploration		13		12			—
	Development		—		—			—
Exploration			49		28			66
Development(1)			60		70			77
Total Other International(2)		$	122	$	110		$	143

93

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Costs Incurred in Oil and Gas Producing Activities (Continued)

		2005		2004		2003
millions
Total
Property acquisition
	Exploration	$	269	$	155	$	124
	Development		45		3		203
Exploration			722		513		713
Development(1)			2,278		2,348		1,846
Total(2)		$	3,314	$	3,019	$	2,886

⁽¹⁾  Development costs incurred for the year include costs related to the prior year-end proved undeveloped reserves as follows:

	2005		2004		2003
millions
United States	$	367	$	861	$	507
Canada		76		138		92
Algeria		28		22		35
Other International		34		29		25
Total	$	505	$	1,050	$	659

⁽²⁾  The 2005, 2004 and 2003 total costs incurred include asset retirement costs and exclude actual asset retirement expenditures as follows. The 2003 total costs incurred exclude the initial asset retirement costs of $352 million as of January 1, 2003.

							Asset Retirement
	Asset Retirement						Expenditures
	Cost Included						Excluded
	2005		2004		2003		2005		2004		2003
millions
United States	$	29	$	46	$	164	$	25	$	24	$	15
Canada		8		5		15		4		2		5
Algeria		—		1		1		—		—		—
Other International		—		—		7		—		—		—
Total	$	37	$	52	$	187	$	29	$	26	$	20

94

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Results of Operations for Producing Activities

      The following schedule includes only the revenues from the production and sale of gas, oil, condensate and NGLs. Results of operations from gas, oil and NGLs marketing and gas gathering are excluded. The income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include DD&A allowances, after giving effect to permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas activities.

		2005		2004		2003
millions
United States
Net revenues from production
	Third-party sales of gas, oil, condensate and NGLs	$	1,688	$	1,621	$	2,044
	Gas and oil sold to consolidated affiliates		2,808		2,430		1,392
			4,496		4,051		3,436
Production costs
	Direct operating		309		390		349
	Transportation and cost of product		201		160		126
	Production related general and administrative expenses		36		28		31
	Other taxes		317		267		247
			863		845		753
Depreciation, depletion and amortization			833		896		827
			2,800		2,310		1,856
Income tax expense			980		825		643
Results of operations		$	1,820	$	1,485	$	1,213
DD&A rate per net equivalent barrel		$	7.84	$	6.82	$	6.15
Canada
Net revenues from production
	Third-party sales of gas, oil, condensate and NGLs	$	877	$	849	$	828
	Gas and oil sold to consolidated affiliates		36		96		30
			913		945		858
Production costs
	Direct operating		107		160		163
	Transportation and cost of product		16		26		22
	Production related general and administrative expenses		49		49		39
	Other taxes		19		21		18
			191		256		242
Depreciation, depletion and amortization			223		305		259
			499		384		357
Income tax expense			190		150		147
Results of operations		$	309	$	234	$	210
DD&A rate per net equivalent barrel		$	11.02	$	10.55	$	8.58

95

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Results of Operations for Producing Activities (Continued)

		2005		2004		2003
millions
Algeria
Net revenues from production
	Third-party sales of oil	$	455	$	203	$	170
	Oil sold to consolidated affiliates		837		567		371
			1,292		770		541
Production costs
	Direct operating		34		34		22
	Transportation and cost of product		23		22		18
	Production related general and administrative expenses		10		9		8
			67		65		48
Depreciation, depletion and amortization			97		91		70
			1,128		614		423
Income tax expense			429		233		161
Results of operations		$	699	$	381	$	262
DD&A rate per net equivalent barrel		$	4.08	$	4.11	$	3.68
Other International
Net revenues from production
	Third-party sales of gas, oil and condensate	$	208	$	146	$	124
	Oil sold to consolidated affiliates		113		79		60
			321		225		184
Production costs
	Direct operating		57		57		62
	Production related general and administrative expenses		4		5		5
	Other taxes		7		3		2
			68		65		69
Depreciation, depletion and amortization			109		75		67
Impairments related to oil and gas properties			78		72		103
			66		13		(55	)
Income tax expense (benefit)			36		7		(22	)
Results of operations		$	30	$	6	$	(33	)
DD&A rate per net equivalent barrel		$	13.33	$	9.31	$	8.44

96

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Results of Operations for Producing Activities (Continued)

		2005		2004		2003
millions
Total
Net revenues from production
	Third-party sales of gas, oil, condensate and NGLs	$	3,228	$	2,819	$	3,166
	Gas and oil sold to consolidated affiliates		3,794		3,172		1,853
			7,022		5,991		5,019
Production costs
	Direct operating		507		641		596
	Transportation and cost of product		240		208		166
	Production related general and administrative expenses		99		91		83
	Other taxes		343		291		267
			1,189		1,231		1,112
Depreciation, depletion and amortization			1,262		1,367		1,223
Impairments related to oil and gas properties			78		72		103
			4,493		3,321		2,581
Income tax expense			1,635		1,215		929
Results of operations		$	2,858	$	2,106	$	1,652
DD&A rate per net equivalent barrel		$	7.96	$	7.18	$	6.38

97

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Oil and Gas Reserves

      The following table shows internal estimates prepared by the Company’s engineers of proved reserves, proved developed reserves and proved undeveloped reserves (PUDs), net of royalty interests, of natural gas, crude oil, condensate and NGLs owned at year-end and changes in proved reserves during the last three years. Volumes for natural gas are in billions of cubic feet (Bcf) at a pressure base of 14.73 pounds per square inch and volumes for oil, condensate and NGLs are in millions of barrels (MMBbls). Total volumes are in millions of barrels of oil equivalent (MMBOE). For this computation, one barrel is the equivalent of six thousand cubic feet of gas. NGLs are included with oil and condensate reserves and the associated shrinkage has been deducted from the gas reserves.

      Algerian reserves are shown in accordance with each Production Sharing Agreement (PSA). The reserves include estimated quantities allocated to Anadarko for recovery of costs and Algerian taxes and Anadarko’s net equity share after recovery of such costs. Other international reserves are shown in accordance with the respective PSA or risk service contract and are calculated using the economic interest method.

      The Company’s reserves increased in 2005 primarily due to successful exploration and development drilling onshore North America and in the deepwaters of the Gulf of Mexico. The Company’s reserves decreased in 2004 primarily due to the divestiture of properties under the Company’s refocused strategy and current year production, offset in part by reserve additions related to exploration and development drilling in North America.

      Anadarko’s operations in Venezuela have been governed by an Operating Service Agreement (OSA) that was entered into with an affiliate of Petroleos de Venezuela, S.A. (PDVSA), the national oil company of Venezuela. Under the terms of the OSA, Anadarko earns a fee that is translated into barrels of oil based on current prices. This means that higher oil prices reduce the Company’s reported oil reserves and production volumes from that project; however, reserve and production fluctuations due to the economic interest calculation have no impact on the value of the project.

      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 in good faith for 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. For the year ended December 31, 2005, approximately 2% of the Company’s 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.

      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.

      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

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SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Oil and Gas Reserves (Continued)

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 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 enhanced oil recovery, arctic development, deepwater development and many international programs, may 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 table presents the Company’s PUDs vintage, geographic location and percentage of total proved reserves as of December 31, 2005:

																Percentage
										Other						of Total
	U.S.			Canada			Algeria			Int’l			Total			Proved Reserves
MMBOE
Year added
2005		263			22			10			—			295			12	%
2004		187			14			4			3			208			8	%
2003		166			8			11			6			191			8	%
2002		28			10			8			—			46			2	%
2001		49			4			34			7			94			4	%
Prior years		13			5			62			11			91			4	%
Total Proved Undeveloped Reserves		706			63			129			27			925			38	%
Total Proved Reserves		1,805			262			324			58			2,449
Percentage of Total Proved Reserves		39	%		24	%		40	%		47	%		38	%

      The following table compares the December 31, 2005 PUDs to the December 31, 2004 and 2003 PUDs by year added. It illustrates the Company’s effectiveness in converting PUDs to developed reserves.

							% Reduction			% Reduction
	2005		2004		2003		2004-2005			2003-2005
MMBOE
Year added
2005		295		—		—		n/a			n/a
2004		208		310		—		33	%		n/a
2003		191		221		328		14	%		42	%
2002		46		64		100		28	%		54	%
2001		94		132		184		29	%		49	%
Prior years		91		123		174		26	%		48	%
Total Proved Undeveloped Reserves		925		850		786

99

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Oil and Gas Reserves (Continued)

		Natural Gas												Oil, Condensate and NGLs
		(Bcf)												(MMBbls)
								Other															Other
		U.S.			Canada			Int’l			Total			U.S.			Canada			Algeria			Int’l			Total
Proved Reserves
December 31, 2002			5,693			1,343			144			7,180			578			64			372			117			1,131
Revisions of prior estimates
	Performance		(228	)		57			(1	)		(172	)		15			3			1			(1	)		18
	Price-related		31			—			1			32			(1	)		(1	)		2			1			1
Extensions, discoveries and other additions			982			221			—			1,203			55			4			5			—			64
Improved recovery			18			2			—			20			72			2			—			—			74
Purchases in place			115			48			—			163			27			—			—			—			27
Sales in place			(21	)		(38	)		—			(59	)		(4	)		—			—			—			(4	)
Production			(503	)		(140	)		—			(643	)		(51	)		(7	)		(19	)		(8	)		(85	)
December 31, 2003			6,087			1,493			144			7,724			691			65			361			109			1,226
Revisions of prior estimates
	Performance		(245	)		(36	)		9			(272	)		4			(5	)		—			(4	)		(5	)
	Price-related		(4	)		1			—			(3	)		(5	)		1			7			(5	)		(2	)
Extensions, discoveries and other additions			1,387			227			—			1,614			66			5			4			—			75
Improved recovery			—			(1	)		—			(1	)		42			(1	)		—			—			41
Purchases in place			10			3			—			13			1			—			—			—			1
Sales in place			(643	)		(267	)		—			(910	)		(119	)		(19	)		—			—			(138	)
Production			(499	)		(138	)		—			(637	)		(48	)		(6	)		(22	)		(9	)		(85	)
December 31, 2004			6,093			1,282			153			7,528			632			40			350			91			1,113
Revisions of prior estimates
	Performance		29			(35	)		—			(6	)		—			—			(20	)		(16	)		(36	)
	Price-related		28			1			—			29			3			1			14			(9	)		9
Extensions, discoveries and other additions			912			188			—			1,100			74			2			4			—			80
Improved recovery			—			—			—			—			45			—			—			—			45
Purchases in place			28			2			—			30			—			—			—			—			—
Sales in place			(98	)		(4	)		(153	)		(255	)		(9	)		—			—			—			(9	)
Production			(414	)		(102	)		—			(516	)		(37	)		(3	)		(24	)		(8	)		(72	)
December 31, 2005			6,578			1,332			—			7,910			708			40			324			58			1,130
Proved Developed Reserves
December 31, 2002			4,299			995			—			5,294			377			46			191			72			686
December 31, 2003			4,725			1,164			—			5,889			451			48			182			65			746
December 31, 2004			4,469			997			—			5,466			350			29			176			51			606
December 31, 2005			4,553			1,024			—			5,577			340			28			195			31			594
Proved Undeveloped Reserves
December 31, 2002			1,394			348			144			1,886			201			18			181			45			445
December 31, 2003			1,362			329			144			1,835			240			17			179			44			480
December 31, 2004			1,624			285			153			2,062			282			11			174			40			507
December 31, 2005			2,025			308			—			2,333			368			12			129			27			536

100

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Oil and Gas Reserves (Continued)

		Total
		(MMBOE)
											Other
		U.S.			Canada			Algeria			Int’l			Total
Proved Reserves
December 31, 2002			1,526			288			372			142			2,328
Revisions of prior estimates
	Performance		(24	)		12			1			(1	)		(12	)
	Price-related		5			(1	)		2			1			7
Extensions, discoveries and other additions			219			41			5			—			265
Improved recovery			75			2			—			—			77
Purchases in place			46			8			—			—			54
Sales in place			(8	)		(6	)		—			—			(14	)
Production			(135	)		(30	)		(19	)		(8	)		(192	)
December 31, 2003			1,704			314			361			134			2,513
Revisions of prior estimates
	Performance		(37	)		(11	)		—			(3	)		(51	)
	Price-related		(6	)		1			7			(5	)		(3	)
Extensions, discoveries and other additions			297			43			4			—			344
Improved recovery			42			(1	)		—			—			41
Purchases in place			3			1			—			—			4
Sales in place			(226	)		(64	)		—			—			(290	)
Production			(131	)		(29	)		(22	)		(9	)		(191	)
December 31, 2004			1,646			254			350			117			2,367
Revisions of prior estimates
	Performance		5			(6	)		(20	)		(16	)		(37	)
	Price-related		9			1			14			(10	)		14
Extensions, discoveries and other additions			226			34			4			—			264
Improved recovery			45			—			—			—			45
Purchases in place			5			—			—			—			5
Sales in place			(25	)		(1	)		—			(25	)		(51	)
Production			(106	)		(20	)		(24	)		(8	)		(158	)
December 31, 2005			1,805			262			324			58			2,449
Proved Developed Reserves
December 31, 2002			1,093			212			191			72			1,568
December 31, 2003			1,238			242			182			65			1,727
December 31, 2004			1,095			195			176			51			1,517
December 31, 2005			1,099			199			195			31			1,524
Proved Undeveloped Reserves
December 31, 2002			433			76			181			70			760
December 31, 2003			466			72			179			69			786
December 31, 2004			551			59			174			66			850
December 31, 2005			706			63			129			27			925

101

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Discounted Future Net Cash Flows

      Estimates of future net cash flows from proved reserves of gas, oil, condensate and NGLs were made in accordance with SFAS No. 69, “Disclosures about Oil and Gas Producing Activities.” The amounts were prepared by the Company’s engineers and are shown in the following table. The estimates are based on prices at year-end. Gas, oil, condensate and NGLs prices are escalated only for fixed and determinable amounts under provisions in some contracts. Estimated future cash inflows are reduced by estimated future development, production, abandonment and dismantlement costs based on year-end cost levels, assuming continuation of existing economic conditions, and by estimated future income tax expense. Income tax expense, both U.S. and foreign, is calculated by applying the existing statutory tax rates, including any known future changes, to the pretax net cash flows giving effect to any permanent differences and reduced by the applicable tax basis. The effect of tax credits is considered in determining the income tax expense.

      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 FASB). 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. Derivative instruments that qualify as cash flow hedges have not been included in the estimates of future net cash flows. As of December 31, 2005, the undiscounted and discounted amounts related to cash flow hedges that would have reduced future net cash flows were $40 million and $37 million, respectively, before income taxes.

      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. Significant changes in estimated reserve volumes or commodity prices could have a material effect on the Company’s consolidated financial statements.

      Under the full cost method of accounting, a noncash charge to earnings related to the carrying value of the Company’s oil and gas properties on a country-by-country basis may be required when prices are low. Whether the Company 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 to proved reserves during that quarter. If a noncash charge were required, it would reduce earnings for the period and result in lower DD&A expense in future periods.

          Expected future development costs over the next three years to develop PUDs as of December 31, 2005 are as follows:

	2006		2007		2008
millions
United States	$	1,499	$	1,277	$	427
Canada		190		238		228
Algeria		92		205		161
Other International		76		47		47
Total	$	1,857	$	1,767	$	863

102

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

	2005		2004		2003
millions
United States
Future cash inflows	$	87,304	$	54,908	$	51,346
Future production costs		17,262		12,303		11,529
Future development costs		5,231		3,718		2,796
Future income tax expenses		22,671		13,582		12,736
Future net cash flows		42,140		25,305		24,285
10% annual discount for estimated timing of cash flows		22,384		13,382		11,789
Standardized measure of discounted future net cash flows		19,756		11,923		12,496
Canada
Future cash inflows		12,679		7,564		9,602
Future production costs		2,847		1,969		2,548
Future development costs		1,076		648		637
Future income tax expenses		2,692		1,493		1,714
Future net cash flows		6,064		3,454		4,703
10% annual discount for estimated timing of cash flows		3,075		1,653		2,165
Standardized measure of discounted future net cash flows		2,989		1,801		2,538
Algeria
Future cash inflows		19,192		14,348		11,092
Future production costs		1,025		1,108		1,052
Future development costs		746		599		596
Future income tax expenses		6,445		4,611		3,417
Future net cash flows		10,976		8,030		6,027
10% annual discount for estimated timing of cash flows		5,238		3,915		3,036
Standardized measure of discounted future net cash flows		5,738		4,115		2,991
Other International
Future cash inflows		2,507		2,669		2,680
Future production costs		515		543		648
Future development costs		238		365		370
Future income tax expenses		607		560		434
Future net cash flows		1,147		1,201		1,228
10% annual discount for estimated timing of cash flows		338		391		470
Standardized measure of discounted future net cash flows		809		810		758
Total
Future cash inflows		121,682		79,489		74,720
Future production costs		21,649		15,923		15,777
Future development costs		7,291		5,330		4,399
Future income tax expenses		32,415		20,246		18,301
Future net cash flows		60,327		37,990		36,243
10% annual discount for estimated timing of cash flows		31,035		19,341		17,460
Standardized measure of discounted future net cash flows	$	29,292	$	18,649	$	18,783

103

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Changes in Standardized Measure of Discounted Future Net Cash Flows

Relating to Proved Oil and Gas Reserves

	2005			2004			2003
millions
United States
Beginning of year	$	11,923		$	12,496		$	8,597
Sales and transfers of oil and gas produced, net of production costs		(3,633	)		(3,206	)		(2,698	)
Net changes in prices and production costs		10,768			1,519			3,492
Changes in estimated future development costs		(255	)		(527	)		288
Extensions, discoveries, additions and improved recovery, less related costs		2,826			4,233			4,053
Development costs incurred during the period		874			818			524
Revisions of previous quantity estimates		(48	)		(707	)		(616	)
Purchases of minerals in place		73			28			501
Sales of minerals in place		(324	)		(4,118	)		(44	)
Accretion of discount		1,828			1,876			1,271
Net change in income taxes		(4,043	)		(89	)		(2,154	)
Other		(233	)		(400	)		(718	)
End of year		19,756			11,923			12,496
Canada
Beginning of year		1,801			2,538			1,746
Sales and transfers of oil and gas produced, net of production costs		(722	)		(689	)		(616	)
Net changes in prices and production costs		1,809			(75	)		320
Changes in estimated future development costs		(259	)		(84	)		(32	)
Extensions, discoveries, additions and improved recovery, less related costs		648			507			321
Development costs incurred during the period		76			158			152
Revisions of previous quantity estimates		(104	)		(124	)		136
Purchases of minerals in place		4			7			64
Sales of minerals in place		(8	)		(785	)		(50	)
Accretion of discount		241			329			257
Net change in income taxes		(478	)		143			68
Other		(19	)		(124	)		172
End of year		2,989			1,801			2,538
Algeria
Beginning of year		4,115			2,991			3,036
Sales and transfers of oil produced, net of production costs		(1,225	)		(705	)		(493	)
Net changes in prices and production costs		3,732			1,962			32
Changes in estimated future development costs		(235	)		(23	)		(139	)
Extensions, discoveries, additions and improved recovery, less related costs		120			73			59
Development costs incurred during the period		45			36			60
Revisions of previous quantity estimates		(465	)		(118	)		20
Accretion of discount		650			471			478
Net change in income taxes		(1,034	)		(663	)		29
Other		35			91			(91	)
End of year	$	5,738		$	4,115		$	2,991

104

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Changes in Standardized Measure of Discounted Future Net Cash Flows

Relating to Proved Oil and Gas Reserves (Continued)

	2005			2004			2003
millions
Other International
Beginning of year	$	810		$	758		$	731
Sales and transfers of oil and gas produced, net of production costs		(253	)		(160	)		(115	)
Net changes in prices and production costs		771			272			(59	)
Changes in estimated future development costs		14			(46	)		(5	)
Development costs incurred during the period		57			66			64
Revisions of previous quantity estimates		(688	)		(122	)		19
Sales of minerals in place		(51	)		—			—
Accretion of discount		118			103			105
Net change in income taxes		(75	)		(104	)		48
Other		106			43			(30	)
End of year		809			810			758
Total
Beginning of year		18,649			18,783			14,110
Sales and transfers of oil and gas produced, net of production costs		(5,833	)		(4,760	)		(3,922	)
Net changes in prices and production costs		17,080			3,678			3,785
Changes in estimated future development costs		(735	)		(680	)		112
Extensions, discoveries, additions and improved recovery, less related costs		3,594			4,813			4,433
Development costs incurred during the period		1,052			1,078			800
Revisions of previous quantity estimates		(1,305	)		(1,071	)		(441	)
Purchases of minerals in place		77			35			565
Sales of minerals in place		(383	)		(4,903	)		(94	)
Accretion of discount		2,837			2,779			2,111
Net change in income taxes		(5,630	)		(713	)		(2,009	)
Other		(111	)		(390	)		(667	)
End of year	$	29,292		$	18,649		$	18,783

105

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL QUARTERLY INFORMATION

(Unaudited)

Quarterly Financial Data

      The following table shows summary quarterly financial data for 2005 and 2004. Certain amounts for prior years have been reclassified to conform to the current presentation.

	First		Second		Third		Fourth
millions except per share amounts	Quarter		Quarter		Quarter		Quarter
2005
Revenues	$	1,526	$	1,592	$	1,737	$	2,245
Operating income - pretax		815		846		983		1,371
Net income before cumulative effect of change in accounting principle	$	491	$	507	$	598	$	875
Net income available to common stockholders before cumulative effect of change in accounting principle	$	490	$	506	$	596	$	874
Net income available to common stockholders	$	490	$	506	$	596	$	874
EPS - before cumulative effect of change in accounting principle - basic	$	2.07	$	2.14	$	2.53	$	3.77
EPS - before cumulative effect of change in accounting principle - diluted	$	2.05	$	2.12	$	2.51	$	3.73
EPS - basic	$	2.07	$	2.14	$	2.53	$	3.77
EPS - diluted	$	2.05	$	2.12	$	2.51	$	3.73
Average number common shares outstanding - basic		237		236		235		232
Average number common shares outstanding - diluted		239		238		238		234
2004
Revenues	$	1,465	$	1,441	$	1,557	$	1,616
Operating income - pretax		733		685		742		733
Net income before cumulative effect of change in accounting principle	$	393	$	406	$	401	$	406
Net income available to common stockholders before cumulative effect of change in accounting principle	$	392	$	405	$	399	$	405
Net income available to common stockholders	$	392	$	405	$	399	$	405
EPS - before cumulative effect of change in accounting principle - basic	$	1.56	$	1.60	$	1.59	$	1.66
EPS - before cumulative effect of change in accounting principle - diluted	$	1.55	$	1.59	$	1.58	$	1.64
EPS - basic	$	1.56	$	1.60	$	1.59	$	1.66
EPS - diluted	$	1.55	$	1.59	$	1.58	$	1.64
Average number common shares outstanding - basic		252		252		250		244
Average number common shares outstanding - diluted		254		254		253		246

106

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

      None.

Item 9a. Controls and Procedures

Evaluation of disclosure controls and procedures

      Anadarko’s Chief Executive Officer and Chief Financial Officer performed an evaluation of the Company’s disclosure controls and procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act is accumulated and communicated to the issuer’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective as of December 31, 2005.

Management’s Annual Report on Internal Control Over Financial Reporting

      See Management’s Assessment of Internal Control Over Financial Reporting under Item 8 of this Form 10-K.

Attestation Report of the Registered Public Accounting Firm

      See Report of Independent Registered Public Accounting Firm under Item 8 of this Form 10-K.

Changes in Internal Control over Financial Reporting

      There were no changes in Anadarko’s internal control over financial reporting during the fourth quarter of 2005 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 9b. Other Information

      None.

107

PART III

Item 10. Directors and Executive Officers of the Registrant

      See Anadarko Board of Directors, Committees of the Board and Section 16(a) Beneficial Ownership Reporting Compliance in the Anadarko Petroleum Corporation Proxy Statement (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) which is incorporated herein by reference.

      See list of Executive Officers of the Registrant under Item 4 of this Form 10-K.

      The Company’s Code of Business Conduct and Ethics and the Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer (Code of Ethics) can be found on the Company’s internet website located at www.anadarko.com. If the Company amends the Code of Ethics or grants a waiver, including an implicit waiver, from the Code of Ethics, the Company intends to disclose the information on its internet website. The waiver information will remain on the website for at least 12 months after the initial disclosure of such waiver.

Item 11. Executive Compensation

      See Board of Directors, Executive Compensation and Transactions with Management and Others in the Proxy Statement, which is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

      See Stock Ownership in the Proxy Statement, which is incorporated herein by reference.

Equity Compensation Plan Table The following table sets forth information with respect to the equity compensation plans available to directors, officers and employees of the Company as of December 31, 2005:

					(c)
					Number of securities
	(a)		(b)		remaining available
	Number of securities		Weighted-average		for future issuance
	to be issued upon		exercise price of		under equity
	exercise of		outstanding		compensation plans
	outstanding options,		options, warrants		(excluding securities
Plan category	warrants and rights		and rights		reflected in column(a))
Equity compensation plans approved by security holders		4,787,182	$	51.14		8,194,423
Equity compensation plans not approved by security holders		—		—		—
Total		4,787,182	$	51.14		8,194,423

Item 13. Certain Relationships and Related Transactions

      See Board of Directors and Transactions with Management and Others in the Proxy Statement, which is incorporated herein by reference.

Item 14. Principal Accounting Fees and Services

      See Independent Auditor in the Proxy Statement, which is incorporated herein by reference.

108

PART IV

Item 15.     Exhibits, Financial Statement Schedules

      (a) Exhibits The following documents are filed as a part of this report or incorporated by reference:

(1)	The consolidated financial statements of Anadarko Petroleum Corporation are listed on the Index to this report, page 50.
(2)	Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

Exhibit			Originally Filed	File
Number		Description	as Exhibit	Number
3(a)		Restated Certificate of Incorporation of Anadarko Petroleum Corporation, dated August 28, 1986	4(a) to Form S-3 dated May 9, 2001		333-60496
(b)		By-laws of Anadarko Petroleum Corporation, as amended	3(b) to Form 10-Q for quarter ended September 30, 2004		1-8968
(c)		Certificate of Amendment of Anadarko’s Restated Certificate of Incorporation	4.1 to Form 8-K dated July 28, 2000		1-8968
4(a)		Certificate of Designation of 5.46% Cumulative Preferred Stock, Series B	4(a) to Form 8-K dated May 6, 1998		1-8968
(b)		Rights Agreement, dated as of October 29, 1998, between Anadarko Petroleum Corporation and The Chase Manhattan Bank	4.1 to Form 8-A dated October 30, 1998		1-8968
(c)		Amendment No. 1 to Rights Agreement, dated as of April 2, 2000 between Anadarko and the Rights Agent	2.4 to Form 8-K dated April 2, 2000		1-8968
10(a)	(i)	Precedent Agreement between Maritimes & Northeast Pipeline, LLC and Anadarko LNG Marketing LLC	10.1 to Form 8-K dated July 6, 2005		1-8968
	(ii)	Anadarko Guaranty of Anadarko LNG Marketing LLC’s obligations under the Service Agreement	10.2 to Form 8-K dated July 6, 2005		1-8968
	(iii)	Anadarko Guaranty of Anadarko LNG Marketing LLC’s obligations under the Precedent Agreement	10.3 to Form 8-K dated July 6, 2005		1-8968
	(iv)	Precedent Agreement between Maritimes & Northeast Pipeline Limited Partnership and Anadarko Canada LNG Marketing, Corp.	10.4 to Form 8-K dated July 6, 2005		1-8968
	(v)	Anadarko Guarantee of Anadarko Canada LNG Marketing, Corp.’s obligations under the Service Agreement	10.5 to Form 8-K dated July 6, 2005		1-8968
	(vi)	Anadarko Guarantee of Anadarko Canada LNG Marketing, Corp.’s obligations under the Precedent Agreement	10.6 to Form 8-K dated July 6, 2005		1-8968
	(vii)	Form of Service Agreement for Rate Schedule MN365	10.7 to Form 8-K dated July 6, 2005		1-8968
	(viii)	Service Agreement for Toll Schedule MN365	10.8 to Form 8-K dated July 6, 2005		1-8968
	(ix)	Base Rate Agreement	10.9 to Form 8-K dated July 6, 2005		1-8968

109

Exhibit			Originally Filed	File
Number		Description	as Exhibit	Number
Director and Executive Compensation Plans and Arrangements
10(b)	(i)	Anadarko Petroleum Corporation 1988 Stock Option Plan for Non-Employee Directors	19(b) to Form 10-Q for quarter ended September 30, 1988		1-8968
	(ii)	Anadarko Petroleum Corporation Amended and Restated 1988 Stock Option Plan for Non-Employee Directors	Attachment A to DEF 14A filed March 16, 1994		1-8968
	(iii)	Amendment to Anadarko Petroleum Corporation 1988 Stock Option Plan for Non-Employee Directors	10(b)(vii) to Form 10-K for year ended December 31, 1997		1-8968
	(iv)	Second Amendment to Anadarko Petroleum Corporation 1988 Stock Option Plan for Non-Employee Directors	10(b)(viii) to Form 10-K for year ended December 31, 1997		1-8968
	(v)	Third Amendment to 1988 Stock Option Plan for Non-Employee Directors	10(b)(v) to Form 10-K for year ended December 31, 2003		1-8968
	(vi)	1998 Director Stock Plan of Anadarko Petroleum Corporation, effective January 30, 1998	Appendix A to DEF 14A filed March 16, 1998		1-8968
	(vii)	Form of Anadarko Petroleum Corporation 1998 Director Stock Plan Stock Option Agreement	10.1 to Form 8-K dated November 17, 2005		1-8968
	(viii)	1993 Stock Incentive Plan	10(b)(xii) to Form 10-K for year ended December 31, 1993		1-8968
	(ix)	First Amendment to Anadarko Petroleum Corporation 1993 Stock Incentive Plans	Appendix A to DEF 14A filed March 12, 1997		1-8968
	(x)	Second Amendment to Anadarko Petroleum Corporation 1993 Stock Incentive Plans	10(b)(xv) to Form 10-K for year ended December 31, 1997		1-8968
	(xi)	Anadarko Petroleum Corporation 1993 Stock Incentive Plan Stock Option Agreement	10(a) to Form 10-Q for quarter ended March 31, 1996		1-8968
	(xii)	Form of Anadarko Petroleum Corporation 1993 Stock Incentive Plan Stock Option Agreement	10(b)(xvii) to Form 10-K for year ended December 31, 1997		1-8968
	(xiii)	Form of Anadarko Petroleum Corporation 1993 Stock Incentive Plan Restricted Stock Agreement	10(b)(xviii) to Form 10-K for year ended December 31, 1997		1-8968
	(xiv)	Anadarko Petroleum Corporation Amended and Restated 1999 Stock Incentive Plan	Appendix A to DEF 14A filed March 18, 2005		1-8968
	(xv)	Form of Anadarko Petroleum Corporation Executive 1999 Stock Incentive Plan Stock Option Agreement	10.2 to Form 8-K dated November 17, 2005		1-8968
	(xvi)	Form of Anadarko Petroleum Corporation Non- Executive 1999 Stock Incentive Plan Stock Option Agreement	10.3 to Form 8-K dated November 17, 2005		1-8968
	(xvii)	Form of Stock Option Agreement — 1999 Stock Incentive Plan (UK Nationals)	10.4 to Form 8-K dated November 17, 2005		1-8968

110

Exhibit			Originally Filed	File
Number		Description	as Exhibit	Number
10(b)	(xviii)	Form of Stock Option Agreement — 1999 Stock Incentive Plan (Canadian Nationals)	10.5 to Form 8-K dated November 17, 2005		1-8968
	(xix)	Form of Anadarko Petroleum Corporation 1999 Stock Incentive Plan Restricted Stock Agreement	10(b)(xxiv) to Form 10-K for year ended December 31, 1999		1-8968
	(xx)	Anadarko Petroleum Corporation 1999 Stock Incentive Plan Performance Share Agreement	10(b) to Form 10-Q for quarter ended March 31, 2004		1-8968
	(xxi)	Anadarko Petroleum Corporation 1999 Stock Incentive Plan Performance Unit Agreement	10.1 to Form 8-K dated December 14, 2004		1-8968
	(xxii)	Form of Anadarko Petroleum Corporation 1999 Stock Incentive Plan Performance Unit Agreement	10.1 to Form 8-K dated December 9, 2005		1-8968
	(xxiii)	The Approved UK Sub-Plan of the Anadarko Petroleum Corporation 1999 Stock Incentive Plan	10(b)(xxiv) to Form 10-K for year ended December 31, 2003		1-8968
	(xxiv)	Annual Incentive Bonus Plan, as amended January 1, 2004	Appendix C to DEF 14A filed March 12, 2004		1-8968
	(xxv)	Key Employee Change of Control Contract	10(b)(xxii) to Form 10-K for year ended December 31, 1997		1-8968
	(xxvi)	First Amendment to Anadarko Petroleum Corporation Key Employee Change of Control Contract	10(b) to Form 10-Q for quarter ended September 30, 2000		1-8968
	(xvii)	Form of Amendment to Anadarko Petroleum Corporation Key Employee Change of Control Contract	10(b)(ii) to Form 10-Q for quarter ended June 30, 2003		1-8968
	(xxviii)	Key Employee Change of Control Contract — James T. Hackett	10(b)(xxxi) to Form 10-K for year ended December 31, 2003		1-8968
	(xxix)	Employment Agreement — James T. Hackett	10(b)(xxxii) to Form 10-K for year ended December 31, 2003		1-8968
	(xxx)	Letter Agreement regarding Post-Retirement Benefits, dated February 16, 2004 — Robert J. Allison, Jr.	10(b)(xxxiv) to Form 10-K for year ended December 31, 2003		1-8968
	(xxxi)	Anadarko Retirement Restoration Plan, effective January 1, 1995	10(b)(xix) to Form 10-K for year ended December 31, 1995		1-8968
	(xxxii)	Anadarko Savings Restoration Plan, effective January 1, 1995	10(b)(xx) to Form 10-K for year ended December 31, 1995		1-8968
*	(xxxiii)	First Amendment to Anadarko Retirement Restoration Plan, effective July 31, 2003
	(xxxiv)	Amendment to Amended and Restated Anadarko Savings Restoration Plan, effective January 29, 1998	10(b)(xxxi) to Form 10-K for year ended December 31, 1997		1-8968
*	(xxxv)	Amendment to Amended and Restated Anadarko Savings Restoration Plan, effective January 1, 2005

111

Exhibit			Originally Filed	File
Number		Description	as Exhibit	Number
10(b)	(xxxvi)	Anadarko Petroleum Corporation Estate Enhancement Program	10(b)(xxxiv) to Form 10-K for year ended December 31, 1998		1-8968
	(xxxvii)	Estate Enhancement Program Agreement between Anadarko Petroleum Corporation and Eligible Executives	10(b)(xxxv) to Form 10-K for year ended December 31, 1998		1-8968
	(xxxviii)	Estate Enhancement Program Agreements effective November 29, 2000	10(b)(xxxxii) to Form 10-K for year ended December 31, 2000		1-8968
	(xxxix)	Anadarko Petroleum Corporation Management Life Insurance Plan, restated November 1, 2002	10(b)(xxxii) to Form 10-K for year ended December 31, 2002		1-8968
	(xl)	First Amendment to Anadarko Petroleum Corporation Management Life Insurance Plan, effective June 30, 2003	10(b)(xliii) to Form 10-K for year ended December 31, 2003		1-8968
	(xli)	Management Disability Plan — Plan Summary	10(b)(xxxiii) to Form 10-K for year ended December 31, 2002		1-8968
	(xlii)	Termination Agreement and Release of All Claims — John N. Seitz	10(b)(i) to Form 10-Q for quarter ended June 30, 2003		1-8968
	(xliii)	Anadarko Petroleum Corporation Officer Severance Plan	10(b)(iv) to Form 10-Q for quarter ended September 30, 2003		1-8968
	(xliv)	Form of Termination Agreement and Release of All Claims Under Officer Severance Plan	10(b)(v) to Form 10-Q for quarter ended September 30, 2003		1-8968
	(xlv)	Letter of Agreement for Medical/Dental Benefits — John N. Seitz	10(b)(xlviii) to Form 10-K for year ended December 31, 2003		1-8968
	(xlvi)	Anadarko Petroleum Corporation Deferred Compensation Plan effective January 1, 2005	10(b)(ii) to Form 10-Q for quarter ended September 30, 2004		1-8968
	(xlvii)	Director and Officer Indemnification Agreement	10 to Form 8-K dated September 3, 2004		1-8968
	(xlviii)	Summary of Director Compensation	10.1 to Form 8-K dated May 17, 2005		1-8968
	(xlix)	Summary of Material Terms of Employment — R. A. Walker	10.1 to Form 8-K dated August 11, 2005		1-8968
*12		Computation of Ratios of Earnings to Fixed Charges and Earnings to Combined Fixed Charges and Preferred Stock Dividends
*13		Portions of the Anadarko Petroleum Corporation 2005 Annual Report to Stockholders
*21		List of Significant Subsidiaries
*23.1		Consent of KPMG LLP

112

Exhibit		Originally Filed	File
Number	Description	as Exhibit	Number
*23.2	Consent of Netherland, Sewell & Associates, Inc.
*24	Power of Attorney
*31.1	Rule 13a-14(a)/15d-14(a) Certification — Chief Executive Officer
*31.2	Rule 13a-14(a)/15d-14(a) Certification — Chief Financial Officer
*32	Section 1350 Certifications
*99.1	2005 Report of Netherland, Sewell & Associates, Inc.

The total amount of securities of the registrant authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10% of the total assets of the registrant and its subsidiaries on a consolidated basis. The registrant agrees, upon request of the Securities and Exchange Commission, to furnish copies of any or all of such instruments to the Securities and Exchange Commission.

      (b) Financial Statement Schedules Financial statement schedules have been omitted because they are not required, not applicable or the information is included in the Company’s consolidated financial statements.

113

SIGNATURES

      Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

ANADARKO PETROLEUM CORPORATION

March 2, 2006

By:  /s/ R. A. WALKER

(R. A. Walker, Senior Vice

President, Finance and Chief Financial Officer)

      Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on February 24, 2006.

	Name and Signature
		Title
(i)	Principal executive officer:*
	JAMES T. HACKETT (James T. Hackett)	Chairman of the Board, President and Chief Executive Officer
(ii)	Principal financial officer:
	/s/ R. A. WALKER (R. A. Walker)	Senior Vice President, Finance and Chief Financial Officer
(iii)	Principal accounting officer:
	/s/ DIANE L. DICKEY (Diane L. Dickey)	Vice President, Controller and Chief Accounting Officer
(iv)	Directors:*
	CONRAD P. ALBERT ROBERT J. ALLISON, JR. LARRY BARCUS JAMES L. BRYAN JOHN R. BUTLER, JR. H. PAULETT EBERHART JOHN R. GORDON JAMES T. HACKETT JOHN W. PODUSKA, SR., PH.D.
* Signed on behalf of each of these persons and on his own behalf:
By	/s/ R. A. WALKER (R. A. Walker, Attorney-in-Fact)

114

Index to Exhibits

Exhibit			Originally Filed	File
Number		Description	as Exhibit	Number
3(a)		Restated Certificate of Incorporation of Anadarko Petroleum Corporation, dated August 28, 1986	4(a) to Form S-3 dated May 9, 2001		333-60496
(b)		By-laws of Anadarko Petroleum Corporation, as amended	3(b) to Form 10-Q for quarter ended September 30, 2004		1-8968
(c)		Certificate of Amendment of Anadarko’s Restated Certificate of Incorporation	4.1 to Form 8-K dated July 28, 2000		1-8968
4(a)		Certificate of Designation of 5.46% Cumulative Preferred Stock, Series B	4(a) to Form 8-K dated May 6, 1998		1-8968
(b)		Rights Agreement, dated as of October 29, 1998, between Anadarko Petroleum Corporation and The Chase Manhattan Bank	4.1 to Form 8-A dated October 30, 1998		1-8968
(c)		Amendment No. 1 to Rights Agreement, dated as of April 2, 2000 between Anadarko and the Rights Agent	2.4 to Form 8-K dated April 2, 2000		1-8968
10(a)	(i)	Precedent Agreement between Maritimes & Northeast Pipeline, LLC and Anadarko LNG Marketing LLC	10.1 to Form 8-K dated July 6, 2005		1-8968
	(ii)	Anadarko Guaranty of Anadarko LNG Marketing LLC’s obligations under the Service Agreement	10.2 to Form 8-K dated July 6, 2005		1-8968
	(iii)	Anadarko Guaranty of Anadarko LNG Marketing LLC’s obligations under the Precedent Agreement	10.3 to Form 8-K dated July 6, 2005		1-8968
	(iv)	Precedent Agreement between Maritimes & Northeast Pipeline Limited Partnership and Anadarko Canada LNG Marketing, Corp.	10.4 to Form 8-K dated July 6, 2005		1-8968
	(v)	Anadarko Guarantee of Anadarko Canada LNG Marketing, Corp.’s obligations under the Service Agreement	10.5 to Form 8-K dated July 6, 2005		1-8968
	(vi)	Anadarko Guarantee of Anadarko Canada LNG Marketing, Corp.’s obligations under the Precedent Agreement	10.6 to Form 8-K dated July 6, 2005		1-8968
	(vii)	Form of Service Agreement for Rate Schedule MN365	10.7 to Form 8-K dated July 6, 2005		1-8968
	(viii)	Service Agreement for Toll Schedule MN365	10.8 to Form 8-K dated July 6, 2005		1-8968
	(ix)	Base Rate Agreement	10.9 to Form 8-K dated July 6, 2005		1-8968

Exhibit			Originally Filed	File
Number		Description	as Exhibit	Number
Director and Executive Compensation Plans and Arrangements
10(b)	(i)	Anadarko Petroleum Corporation 1988 Stock Option Plan for Non-Employee Directors	19(b) to Form 10-Q for quarter ended September 30, 1988		1-8968
	(ii)	Anadarko Petroleum Corporation Amended and Restated 1988 Stock Option Plan for Non-Employee Directors	Attachment A to DEF 14A filed March 16, 1994		1-8968
	(iii)	Amendment to Anadarko Petroleum Corporation 1988 Stock Option Plan for Non-Employee Directors	10(b)(vii) to Form 10-K for year ended December 31, 1997		1-8968
	(iv)	Second Amendment to Anadarko Petroleum Corporation 1988 Stock Option Plan for Non-Employee Directors	10(b)(viii) to Form 10-K for year ended December 31, 1997		1-8968
	(v)	Third Amendment to 1988 Stock Option Plan for Non-Employee Directors	10(b)(v) to Form 10-K for year ended December 31, 2003		1-8968
	(vi)	1998 Director Stock Plan of Anadarko Petroleum Corporation, effective January 30, 1998	Appendix A to DEF 14A filed March 16, 1998		1-8968
	(vii)	Form of Anadarko Petroleum Corporation 1998 Director Stock Plan Stock Option Agreement	10.1 to Form 8-K dated November 17, 2005		1-8968
	(viii)	1993 Stock Incentive Plan	10(b)(xii) to Form 10-K for year ended December 31, 1993		1-8968
	(ix)	First Amendment to Anadarko Petroleum Corporation 1993 Stock Incentive Plans	Appendix A to DEF 14A filed March 12, 1997		1-8968
	(x)	Second Amendment to Anadarko Petroleum Corporation 1993 Stock Incentive Plans	10(b)(xv) to Form 10-K for year ended December 31, 1997		1-8968
	(xi)	Anadarko Petroleum Corporation 1993 Stock Incentive Plan Stock Option Agreement	10(a) to Form 10-Q for quarter ended March 31, 1996		1-8968
	(xii)	Form of Anadarko Petroleum Corporation 1993 Stock Incentive Plan Stock Option Agreement	10(b)(xvii) to Form 10-K for year ended December 31, 1997		1-8968
	(xiii)	Form of Anadarko Petroleum Corporation 1993 Stock Incentive Plan Restricted Stock Agreement	10(b)(xviii) to Form 10-K for year ended December 31, 1997		1-8968
	(xiv)	Anadarko Petroleum Corporation Amended and Restated 1999 Stock Incentive Plan	Appendix A to DEF 14A filed March 18, 2005		1-8968
	(xv)	Form of Anadarko Petroleum Corporation Executive 1999 Stock Incentive Plan Stock Option Agreement	10.2 to Form 8-K dated November 17, 2005		1-8968
	(xvi)	Form of Anadarko Petroleum Corporation Non- Executive 1999 Stock Incentive Plan Stock Option Agreement	10.3 to Form 8-K dated November 17, 2005		1-8968
	(xvii)	Form of Stock Option Agreement — 1999 Stock Incentive Plan (UK Nationals)	10.4 to Form 8-K dated November 17, 2005		1-8968

Exhibit			Originally Filed	File
Number		Description	as Exhibit	Number
10(b)	(xviii)	Form of Stock Option Agreement — 1999 Stock Incentive Plan (Canadian Nationals)	10.5 to Form 8-K dated November 17, 2005		1-8968
	(xix)	Form of Anadarko Petroleum Corporation 1999 Stock Incentive Plan Restricted Stock Agreement	10(b)(xxiv) to Form 10-K for year ended December 31, 1999		1-8968
	(xx)	Anadarko Petroleum Corporation 1999 Stock Incentive Plan Performance Share Agreement	10(b) to Form 10-Q for quarter ended March 31, 2004		1-8968
	(xxi)	Anadarko Petroleum Corporation 1999 Stock Incentive Plan Performance Unit Agreement	10.1 to Form 8-K dated December 14, 2004		1-8968
	(xxii)	Form of Anadarko Petroleum Corporation 1999 Stock Incentive Plan Performance Unit Agreement	10.1 to Form 8-K dated December 9, 2005		1-8968
	(xxiii)	The Approved UK Sub-Plan of the Anadarko Petroleum Corporation 1999 Stock Incentive Plan	10(b)(xxiv) to Form 10-K for year ended December 31, 2003		1-8968
	(xxiv)	Annual Incentive Bonus Plan, as amended January 1, 2004	Appendix C to DEF 14A filed March 12, 2004		1-8968
	(xxv)	Key Employee Change of Control Contract	10(b)(xxii) to Form 10-K for year ended December 31, 1997		1-8968
	(xxvi)	First Amendment to Anadarko Petroleum Corporation Key Employee Change of Control Contract	10(b) to Form 10-Q for quarter ended September 30, 2000		1-8968
	(xvii)	Form of Amendment to Anadarko Petroleum Corporation Key Employee Change of Control Contract	10(b)(ii) to Form 10-Q for quarter ended June 30, 2003		1-8968
	(xxviii)	Key Employee Change of Control Contract — James T. Hackett	10(b)(xxxi) to Form 10-K for year ended December 31, 2003		1-8968
	(xxix)	Employment Agreement — James T. Hackett	10(b)(xxxii) to Form 10-K for year ended December 31, 2003		1-8968
	(xxx)	Letter Agreement regarding Post-Retirement Benefits, dated February 16, 2004 — Robert J. Allison, Jr.	10(b)(xxxiv) to Form 10-K for year ended December 31, 2003		1-8968
	(xxxi)	Anadarko Retirement Restoration Plan, effective January 1, 1995	10(b)(xix) to Form 10-K for year ended December 31, 1995		1-8968
	(xxxii)	Anadarko Savings Restoration Plan, effective January 1, 1995	10(b)(xx) to Form 10-K for year ended December 31, 1995		1-8968
*	(xxxiii)	First Amendment to Anadarko Retirement Restoration Plan, effective July 31, 2003
	(xxxiv)	Amendment to Amended and Restated Anadarko Savings Restoration Plan, effective January 29, 1998	10(b)(xxxi) to Form 10-K for year ended December 31, 1997		1-8968
*	(xxxv)	Amendment to Amended and Restated Anadarko Savings Restoration Plan, effective January 1, 2005

Exhibit			Originally Filed	File
Number		Description	as Exhibit	Number
10(b)	(xxxvi)	Anadarko Petroleum Corporation Estate Enhancement Program	10(b)(xxxiv) to Form 10-K for year ended December 31, 1998		1-8968
	(xxxvii)	Estate Enhancement Program Agreement between Anadarko Petroleum Corporation and Eligible Executives	10(b)(xxxv) to Form 10-K for year ended December 31, 1998		1-8968
	(xxxviii)	Estate Enhancement Program Agreements effective November 29, 2000	10(b)(xxxxii) to Form 10-K for year ended December 31, 2000		1-8968
	(xxxix)	Anadarko Petroleum Corporation Management Life Insurance Plan, restated November 1, 2002	10(b)(xxxii) to Form 10-K for year ended December 31, 2002		1-8968
	(xl)	First Amendment to Anadarko Petroleum Corporation Management Life Insurance Plan, effective June 30, 2003	10(b)(xliii) to Form 10-K for year ended December 31, 2003		1-8968
	(xli)	Management Disability Plan — Plan Summary	10(b)(xxxiii) to Form 10-K for year ended December 31, 2002		1-8968
	(xlii)	Termination Agreement and Release of All Claims — John N. Seitz	10(b)(i) to Form 10-Q for quarter ended June 30, 2003		1-8968
	(xliii)	Anadarko Petroleum Corporation Officer Severance Plan	10(b)(iv) to Form 10-Q for quarter ended September 30, 2003		1-8968
	(xliv)	Form of Termination Agreement and Release of All Claims Under Officer Severance Plan	10(b)(v) to Form 10-Q for quarter ended September 30, 2003		1-8968
	(xlv)	Letter of Agreement for Medical/Dental Benefits — John N. Seitz	10(b)(xlviii) to Form 10-K for year ended December 31, 2003		1-8968
	(xlvi)	Anadarko Petroleum Corporation Deferred Compensation Plan effective January 1, 2005	10(b)(ii) to Form 10-Q for quarter ended September 30, 2004		1-8968
	(xlvii)	Director and Officer Indemnification Agreement	10 to Form 8-K dated September 3, 2004		1-8968
	(xlviii)	Summary of Director Compensation	10.1 to Form 8-K dated May 17, 2005		1-8968
	(xlix)	Summary of Material Terms of Employment — R. A. Walker	10.1 to Form 8-K dated August 11, 2005		1-8968
*12		Computation of Ratios of Earnings to Fixed Charges and Earnings to Combined Fixed Charges and Preferred Stock Dividends
*13		Portions of the Anadarko Petroleum Corporation 2005 Annual Report to Stockholders
*21		List of Significant Subsidiaries
*23.1		Consent of KPMG LLP

Exhibit		Originally Filed	File
Number	Description	as Exhibit	Number
*23.2	Consent of Netherland, Sewell & Associates, Inc.
*24	Power of Attorney
*31.1	Rule 13a-14(a)/15d-14(a) Certification — Chief Executive Officer
*31.2	Rule 13a-14(a)/15d-14(a) Certification — Chief Financial Officer
*32	Section 1350 Certifications
*99.1	2005 Report of Netherland, Sewell & Associates, Inc.