Anadarko Petroleum 10-K 2006 FY Annual report

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, 2006

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. Yesx 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¨ Nox.

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. Yesx 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 x Accelerated filer¨ Non-accelerated filer¨.

Indicate by check mark whether the registrant is a shell company. Yes¨ Nox.

The aggregate market value of the Company’s common stock held by non-affiliates of the registrant on June 30, 2006 was $21.8 billion based on the closing price as reported on the New York Stock Exchange.

The number of shares outstanding of the Company’s common stock as of January 31, 2007 is shown below:

Title of Class	Number of Shares Outstanding
Common Stock, par value $0.10 per share	463,098,338

Part of Form 10-K	Documents Incorporated By Reference
Part II	Portions of the Anadarko Petroleum Corporation 2006 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 16, 2007 (to be filed with the Securities and Exchange Commission prior to April 30, 2007).

TABLE OF CONTENTS

			Page
PART I
	Item 1.	Business	2
		General	2
		Oil and Gas Properties and Activities	3
		Proved Reserves	3
		Sales Volumes and Prices	4
		Properties and Activities — United States	6
		Properties and Activities — Algeria	12
		Properties and Activities — Other International	13
		Drilling Programs	14
		Drilling Statistics	14
		Productive Wells	15
		Properties and Leases	16
		Gathering, Processing and Marketing Properties and Activities	16
		Minerals Properties and Activities	17
		Segment and Geographic Information	17
		Employees	17
		Regulatory Matters and Additional Factors Affecting Business	18
		Title to Properties	18
		Capital Spending	18
		Ratios of Earnings to Fixed Charges and Earnings to Combined Fixed Charges and Preferred Stock Dividends	18
	Item 1a.	Risk Factors	18
	Item 1b.	Unresolved Staff Comments	25
	Item 2.	Properties	26
	Item 3.	Legal Proceedings	26
	Item 4.	Submission of Matters to a Vote of Security Holders	26
		Executive Officers of the Registrant	27
PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	29
	Item 6.	Selected Financial Data	31
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
	Item 7a.	Quantitative and Qualitative Disclosures About Market Risk	59
	Item 8.	Financial Statements and Supplementary Data	60
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	127
	Item 9a.	Controls and Procedures	127
	Item 9b.	Other Information	127
PART III
	Item 10.	Directors, Executive Officers and Corporate Governance	127
	Item 11.	Executive Compensation	128
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	128
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	128
	Item 14.	Principal Accounting Fees and Services	128
PART IV
	Item 15.	Exhibits, Financial Statement Schedules	129

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PART I

Item 1.  Business

General

Anadarko Petroleum Corporation is among the largest independent oil and gas exploration and production companies in the world, with 3.01 billion barrels of oil equivalent (BOE) of proved reserves as of December 31, 2006. The Company’s major areas of operation are located onshore in the United States, the deepwater of the Gulf of Mexico and Algeria. Anadarko also has production in China, Venezuela and Qatar, a development project in Brazil 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 and processing systems. 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.

On August 10, 2006, Anadarko completed the acquisition of Kerr-McGee Corporation (Kerr-McGee) in an all-cash transaction totaling $16.5 billion plus the assumption of approximately $2.6 billion in debt. On August 23, 2006, Anadarko completed the acquisition of Western Gas Resources, Inc. (Western) in an all-cash transaction totaling $4.8 billion plus the assumption of $625 million in debt. Anadarko financed $22.5 billion for the acquisitions under a 364-day committed acquisition facility. As part of an asset realignment associated with the acquisitions, the Company sold its wholly-owned Canadian oil and gas subsidiary, Anadarko Canada Corporation, in November 2006 for approximately $4.3 billion. Net proceeds from this sale were used to reduce debt under the acquisition facility. At December 31, 2006, the Company had $11 billion remaining outstanding under the acquisition facility.

Anadarko has signed several additional separate and unrelated agreements with various companies for the divestiture of certain non-core properties in the Gulf of Mexico and onshore in the United States for a combined total of approximately $6.5 billion before income taxes. Certain of these agreements have closed and the remaining are expected to close in the first half of 2007.

The Company expects total after-tax proceeds from the Canadian sale and the other transactions mentioned above to be about $9 billion. The Company expects to divest certain other assets by the end of 2007, with expected incremental after-tax proceeds totaling between $2 billion and $6 billion. The proceeds from all of these transactions are being used to reduce indebtedness.

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 total oil and gas production and about 11% of Anadarko’s total 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.

Unless noted otherwise, the following information relates to Anadarko’s continuing operations and excludes the discontinued Canadian operations. For additional information, seeAcquisitions and Divestitures andOutlook under Item 7 of this Form 10-K.

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 or furnishing, on its internet site located at www.anadarko.com. The Company will also make available to any stockholder, without charge, copies of its Annual Report on Form 10-K as filed with the

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SEC. For copies of this, or any other filing, please contact: Anadarko Petroleum Corporation, Investor Relations Department, P.O. Box 1330, Houston, Texas 77251-1330 or call (832) 636-1216.

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

Oil and Gas Properties and Activities

Proved Reserves

As of December 31, 2006, Anadarko had proved reserves of 10.5 trillion cubic feet (Tcf) of natural gas and 1.3 billion barrels of crude oil, condensate and NGLs. Combined, these proved reserves are equivalent to 3.01 billion barrels of oil or 18.1 Tcf of gas. During 2006, the Company’s reserves increased 23% due to the acquisitions of Kerr-McGee and Western and successful exploration and development drilling onshore in the United States, partially offset by the disposition of Canadian properties, downward revisions primarily related to the K2 complex in the Gulf of Mexico and adjustments in Algeria, and a decrease in natural gas prices. The Company’s reserves have grown 20% over the past three years primarily due to acquisitions and successful exploration and development drilling in the United States, partially offset by the effect of the disposition of the Canadian and other non-core producing properties. As of December 31, 2006, Anadarko had proved developed reserves of 7.6 Tcf of natural gas and 719 million barrels (MMBbls) of crude oil, condensate and NGLs. Proved developed reserves comprise 66% of total proved reserves. In 2006, each of the legacy companies (Anadarko, Kerr-McGee and Western) used a different process to evaluate reserves and to provide for external review and validation. For the Anadarko legacy assets and the Kerr-McGee legacy assets, estimates of proved reserves and associated future net cash flows are made by the Company’s engineers. Netherland, Sewell & Associates, Inc. (NSAI), an independent worldwide petroleum consultant, provided an external review which varied for each legacy company. For the Western legacy assets, the reports of proved reserves estimates were prepared by NSAI. Additional information on procedures performed by NSAI are outlined in their reports which are attached as Exhibit 99 of this Form 10-K.

The Company’s estimates of proved reserves, proved developed reserves and proved undeveloped reserves at December 31, 2006, 2005 and 2004 and changes in proved reserves during the last three years are contained in theSupplemental Information on Oil and Gas Exploration and Production Activities — Unaudited (Supplemental Information)in the Anadarko Petroleum Corporation 2006 Consolidated Financial Statements (Consolidated Financial Statements) under Item 8 of this Form 10-K. Additional information with respect to NSAI’s participation, and the Company’s methods and procedures employed in the reserve estimation process, are also found in theSupplemental Information. 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 theSupplemental Informationin the Consolidated Financial Statements are the Company’s estimates of future net cash flows and discounted future net cash flows from proved reserves. SeeOperating ResultsandCritical Accounting Policies and Estimatesunder Item 7 of this Form 10-K for additional information on the Company’s proved reserves.

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Sales Volumes and Prices

The following table shows the Company’s annual sales volumes from continuing operations. 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.

	2006	2005	2004
United States
Natural gas (Bcf)	558	414	499
Oil and condensate (MMBbls)	39	24	32
Natural gas liquids (MMBbls)	15	13	16
Total (MMBOE)	147	106	131
Algeria
Oil and condensate (MMBbls)	23	24	22
Total (MMBOE)	23	24	22
Other International
Oil and condensate (MMBbls)	8	8	8
Total (MMBOE)	8	8	8
Total
Natural gas (Bcf)	558	414	499
Oil and condensate (MMBbls)	70	56	62
Natural gas liquids (MMBbls)	15	13	16
Total (MMBOE)	178	138	161

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The following table shows the Company’s annual average sales prices and average production costs from continuing operations. The impact on average sales prices from derivative instruments the Company utilizes to manage price risk related to the Company’s sales volumes is shown separately in the table. Natural gas sales, and oil and condensate sales for 2006 include net unrealized gains related to these derivatives of $579 million and $258 million, respectively. Unrealized gains (losses) related to derivatives were not material in 2005 or 2004. 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 inFinancial ResultsandGathering, Processing and Marketing Strategiesunder Item 7 of this Form 10-K. Additional detail of production costs is contained in theSupplemental Informationunder Item 8 of this Form 10-K. Information on major customers is contained inNote 15of theNotes to Consolidated Financial Statements under Item 8 of this Form 10-K.

	2006		2005			2004
United States
Sales price
Natural gas (per Mcf)	$	6.14	$	7.44		$	5.62
Gains (losses) on derivatives		1.36		(0.28	)		(0.44	)
Total price per Mcf	$	7.50	$	7.16		$	5.18
Oil and condensate (per barrel)		59.41		51.67			38.71
Gains (losses) on derivatives		9.18		(7.32	)		(7.06	)
Total price per barrel	$	68.59	$	44.35		$	31.65
Natural gas liquids (per barrel)		39.58		34.56			27.84
Total (per BOE)		50.77		42.29			30.83
Production cost (per BOE)	$	10.07	$	8.41		$	6.68
Algeria
Sales price
Oil and condensate (per barrel)	$	65.59	$	54.38		$	34.78
Production cost (per BOE)	$	7.75	$	2.88		$	2.94
Other International
Sales price
Oil and condensate (per barrel)	$	48.58	$	39.37		$	27.91
Production cost (per BOE)	$	9.38	$	8.40		$	7.93
Total
Sales price
Natural gas (per Mcf)	$	6.14	$	7.44		$	5.62
Gains (losses) on derivatives		1.36		(0.28	)		(0.44	)
Total price per Mcf	$	7.50	$	7.16		$	5.18
Oil and condensate (per barrel)		60.29		51.03			37.12
Gains (losses) on derivatives		5.15		(3.19	)		(4.84	)
Total price per barrel	$	65.44	$	47.84		$	32.28
Natural gas liquids (per barrel)		39.58		34.56			27.84
Total (per BOE)		52.61		44.19			31.23
Production cost (per BOE)	$	9.75	$	7.47		$	6.23

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Properties and Activities — United States

Overview  Anadarko’s active areas in the United States include the Lower 48 states, Alaska and the Gulf of Mexico. Reserves in the United States comprised 88% of Anadarko’s total proved reserves at year-end 2006. During 2006, the Company’s drilling efforts in the United States resulted in 1,238 gas wells, 250 oil wells and 12 dry holes. The accompanying maps illustrate 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.

The following table presents selected 2006 United States operating data by area.

	Sales Volumes			Producing Wells(1)
	Natural Gas (MMcf/d)	Oil and NGLs (MBbls/d)	Total (MBOE/d)		Drilling Statistics
					Wells Drilled(2)	Success Rate
Rockies:
Tight Gas
- Greater Natural Buttes	80	1	14	1,732	123	100.0%
- Wattenberg	81	7	20	3,930	63	100.0%
- Wamsutter	96	9	25	1,231	155	99.4%
- Pinedale and Jonah	34	—	6	449	71	100.0%
Coalbed Methane	123	—	21	7,174	541	100.0%
Enhanced Oil Recovery	25	16	20	1,571	180	100.0%
Other	85	3	17	2,953	13	92.3%
	524	36	123	19,040	1,146	99.8%
Southern Region:
Vernon	188	—	31	357	67	98.5%
Bossier	183	—	31	1,063	38	100.0%
Carthage	87	4	19	1,328	40	100.0%
Haley	113	—	19	3	25	96.0%
Ozona	50	1	9	44	55	100.0%
Austin Chalk	89	21	36	2,126	41	100.0%
South Texas/Other	177	26	55	9,073	62	95.2%
	887	52	200	13,994	328	98.5%
Total Onshore - Lower 48 States	1,411	88	323	33,034	1,474	99.5%
Alaska	—	22	22	55	10	90.0%
Gulf of Mexico
Marco Polo/K2	14	18	20	10	4	100.0%
Nansen	23	3	7	15	—
Boomvang	4	2	3	10	—
Gunnison	17	3	6	13	—
Red Hawk	23	—	4	2	—
Constitution/Ticonderoga	16	8	10	6	1	100.0%
Other	21	6	9	124	11	63.6%
	118	40	59	180	16	75.0%
Total United States	1,529	150	404	33,269	1,500	99.2%

⁽¹⁾ Gross number of wells in which Anadarko has an interest.

⁽²⁾ Includes 1,433 gross development wells with a 99.6% success rate and 67 gross exploration wells with a 91% success rate.

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	Undeveloped		Developed
	Leasehold		Leasehold		Fee Mineral		Producing
	Acreage (Net	)	Acreage	(Net)	Acreage	(Net)	Wells (Net	)
Onshore:
United States
Alabama	394		2,278		32,580		1
Alaska*	1,231,178		7,404		7,978		12
Arkansas*	2,214		4,689		376,215		3
California	257		243		2,675		1
Colorado*	327,068		485,418		2,898,585		3,634
Florida	--		--		5,364		--
Georgia	--		--		12,371		--
Idaho	--		--		846		--
Illinois	--		1,636		2,324		--
Indiana	--		469		13,634		--
Iowa	--		--		156		--
Kansas	315,323		324,695		29,641		47
Kentucky	--		1,384		19,115		--
Louisiana*	316,075		73,402		25,564		601
Maryland	--		--		235		--
Michigan	21		--		2		--
Minnesota	--		--		5		--
Mississippi*	157,321		1,002		65,011		1
Missouri	--		--		419		--
Montana	835,324		15,082		11		70
Nebraska	182,897		958		27,898		1,015
Nevada	--		--		433		--
New Mexico*	18,200		68,239		257		236
North Dakota*	59,529		84,150		--		109
Ohio	--		2,360		141		--
Oklahoma*	58,753		371,438		82,263		791
Oregon	--		--		741		--
Pennsylvania	255,350		25,456		733		--
South Carolina	--		--		2,734		--
South Dakota	184		--		--		--
Tennessee	--		--		894		--
Texas*	707,962		1,524,704		170,392		6,946
Utah*	81,573		208,134		690,322		1,561
Washington	37,191		--		2,524		--
West Virginia	330		--		2,449		--
Wisconsin	--		--		6		--
Wyoming*	833,610		661,182		4,163,603		5,906
Corporate Offices:
United States
The Woodlands, Texas
Denver, Colorado
* 2006 Drilling Activity Areas

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In late 2006, as part of the asset realignment associated with the 2006 acquisitions, Anadarko signed several separate and unrelated agreements for the sale of properties and announced intentions to divest certain other non-core assets. In November 2006, Anadarko reached an agreement to sell its interests in the Knotty Head and Big Foot oil discoveries, as well as the Big Foot North prospect in the Gulf of Mexico for $901 million. In December 2006, the Company reached an agreement to sell its Vernon and Ansley fields, located in Jackson Parish, Louisiana, for $1.6 billion. In January 2007, Anadarko signed two separate and unrelated agreements to sell its interests in the Williston basin, Elk basin and Gooseberry area of the Northern Rockies for a total of $810 million, as well as an agreement to divest control of Anadarko’s interests in 28 Permian basin oil fields in West Texas for $1 billion. Certain of these transactions have closed and the remaining transactions are expected to close in the first half of 2007.

In February 2007, Anadarko signed an agreement to sell its interests in certain natural gas properties in Oklahoma and Texas for $860 million. This agreement is expected to close during the second quarter of 2007. During February, Anadarko also closed on the sale of its Genghis Khan discovery in the deepwater Gulf of Mexico for $1.33 billion. Anadarko will use the net proceeds from all of these sales to further reduce debt under the acquisition facility.

Onshore — Lower 48 States  At the end of 2006, about 72% of the Company’s proved reserves were located onshore in the Lower 48 states with 38% in the Rockies. The Company’s 2007 capital budget for this area is about $2.0 billion with over 46% of the capital allocated to the Rockies in unconventional tight gas plays and coalbed methane (CBM) development.

Rocky Mountains  During 2006, Anadarko significantly increased its tight gas and CBM holdings in the Rocky Mountains area through the acquisitions of Kerr-McGee and Western. The acquisitions included tight gas plays in the Greater Natural Buttes, Wattenberg and the Pinedale Anticline and Jonah fields. The majority of the Company’s legacy activity in the Rocky Mountains area is associated with developing tight gas in the Wamsutter area, conventional reservoirs, CBM and enhanced oil recovery (EOR) projects.

The 2006 drilling program in the Greater Natural Buttes area in Uintah County, Utah was primarily focused on exploitation of the Wasatch and Mesa Verde formations. The Company operates approximately 1,180 wells in the Greater Natural Buttes field area and has an interest in over 550 non-operated wells.

The Wattenberg gas field is located in the DJ basin in northeast Colorado. The Company’s primary exploitation focus in this area includes activities such as deepenings, fracture stimulations, re-completions and infill drilling. The infill drilling program was accelerated in 2006 following the approval of down-spacing which created a significant increase in drill sites.

During 2006, Anadarko was active in the Wamsutter and Moxa Arch fields, both located on the Land Grant. The Land Grant provides the Company with the added benefit of royalty revenues upon the success of outside operators as they drill on Anadarko’s net revenue fee acreage. The Land Grant also provides the Company with a large captured area on which to explore. In 2007, Anadarko intends to participate in over 200 wells in this area.

The Company’s Pinedale and Jonah fields are located in the Green River basin of southwest Wyoming. These tight gas assets were obtained as part of the Western acquisition. The gas produced at Pinedale and Jonah is transported through Company owned gathering systems that deliver gas to an Anadarko processing facility, located on the Land Grant. Anadarko plans to continue an active drilling program in the area in 2007.

The Company’s CBM operation is located in Wyoming’s Powder River basin. During 2006, the Company increased its acreage position in the Powder River basin with the acquisition of Western. The challenge in developing Wyoming’s CBM is the handling of the large amounts of water associated with de-watering coal. Anadarko’s solution resulted in the construction of a pipeline to transport produced water from the CBM fields to Anadarko’s operated Salt Creek field for underground injection. Other CBM focus areas for the Company include Anadarko’s legacy Helper and Clawson fields in Utah and the Atlantic Rim field in Wyoming.

The Company’s EOR operations at Salt Creek, Monell and Sussex, located in Wyoming, continue to demonstrate year-over-year increases in oil response due to CO₂ injection.

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Southern Region  Anadarko’s properties in the southern region are located primarily in Texas, Louisiana and Oklahoma with focus on tight gas, fractured reservoirs and EOR.

Activities at the Company’s properties in east Texas are concentrated in the Bossier play with production and development activities in the Dowdy Ranch, Dew/Mimms Creek, Bald Prairie, Beargrass, Holly Branch and Marquez fields. Anadarko is encouraged with the results of its Cotton Valley infill drilling program in the Carthage area, with plans to increase activity in this play.

Anadarko’s central Texas activity continues to focus on horizontal drilling in the Austin Chalk formation of the Giddings and Brookeland fields. Much of the current activity involves extending the field boundaries and executing a low cost re-entry drilling program.

Operations in west Texas are concentrated on increasing production and reserves in the tight gas play of the Haley field. During 2006, the Company attained record production rates in the Haley field. Other areas of focus for the Company in west Texas include continued development of the Ozona field and waterflood projects in the Permian basin.

In south Texas, the Company had an active drilling program in Starr and Hidalgo counties during 2006. Drilling and completion activities focused primarily on tight gas plays in the Frost and Braulia East fields. The drilling program is expected to continue into 2007.

Alaska  Anadarko’s activity in Alaska is concentrated primarily on the North Slope. About 2% of the Company’s proved reserves at year-end 2006 were in Alaska. The Company’s capital budget is about $90 million for Alaska in 2007.

During 2006, activity at the Colville River Unit (Alpine, Fiord and Nanuq fields — 22% WI) on Alaska’s North Slope focused on development and achieving first production from the Nanuq and Fiord satellite fields. Anadarko and the operator are continuing to pursue the state, local and federal permits for three additional Alpine satellites. During 2006, Anadarko participated in a successful exploration well at Qannik (22% WI) within the Colville River area. The Qannik reservoir is also expected to become an Alpine satellite development. Project sanction is expected in early 2007 with first production by early 2009.

Anadarko also obtained, through the acquisition of Kerr-McGee, 20 leases covering approximately 41,000 acres off the coast of Alaska, northwest of Prudhoe Bay, and two leases onshore west of Kuparuk, covering approximately 5,000 acres.

Gulf of Mexico  At year-end 2006, about 13% of the Company’s proved reserves were located offshore in the deepwater of the Gulf of Mexico where Anadarko owns an average 63% working interest in 777 blocks and has access to an additional 27 blocks through participation agreements. Anadarko has budgeted about $1 billion for capital spending in the deepwater Gulf of Mexico for 2007, 30% of which relates to exploration.

During 2006, Anadarko significantly increased its holdings in the deepwater Gulf of Mexico through the acquisition of Kerr-McGee. Notable properties acquired in this area include interests in the Nansen, Boomvang, Gunnison, Red Hawk and Constitution/Ticonderoga fields as well as several additional discoveries in the eastern Gulf of Mexico. Including operations acquired with Kerr-McGee, the Company had nine exploration discovery wells in 2006 in the deepwater Gulf of Mexico where efforts focused on the lower Tertiary and the lower/middle Miocene formations. Combined, Anadarko holds interests in nine producing fields and is in the process of developing six additional fields.

Marco Polo/K2 complex  Anadarko operates, and a third party owns, the platform and production facilities for the Marco Polo deepwater development project. During 2006, an agreement was reached with partners to unitize the K2 and K2 North fields (65% WI) with Anadarko as operator. These fields are tied back subsea to the Marco Polo platform where four wells were completed during 2006. During 2007, the Company plans to drill additional wells in the area.

Nansen field (50% WI)  The Nansen field began production in 2002. The Nansen field was developed with a truss spar in 3,700 feet of water. During 2006, the Company completed a multi-well satellite drilling program in the Northwest Nansen field area with four discoveries and development of a tie-back to the Nansen spar commenced. The Company expects to begin production from this area by late 2007.

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Boomvang field,  East Breaks Blocks 641, 642, 643, 686 and 688 (30% WI), Block 598 (100% WI), and Block 599 (33% WI) The Boomvang field also began production in 2002. The Boomvang field was developed with a truss spar in 3,450 feet of water. During 2006, the Company installed a subsea tie-back of a 2005 discovery with first production expected in the first quarter of 2007. During 2007, the Company plans to drill two additional satellite prospects.

Gunnison field (50% WI)  The Gunnison field has been producing since December 2003 and incorporates a truss spar in 3,100 feet of water. During 2006, the Dawson Deep discovery began production as a subsea tie-back to the Gunnison spar.

Red Hawk field (50% WI)  The Red Hawk field, located in approximately 5,300 feet of water, began production in 2004 utilizing the world’s first cell spar designed for developing smaller reservoirs in deepwater basins. During 2006, the Company began a compression project which is expected to extend the life of the field.

Constitution/Ticonderoga fields  The Constitution field (100% WI) began production in 2006 utilizing a truss spar located in approximately 5,000 feet of water. The Ticonderoga field (50% WI) also began production in 2006 as a subsea tie-back to the Constitution spar. During 2007, the Company plans to bring two wells on production and an additional well is expected to be drilled.

Independence Hub  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 eight field discoveries operated by Anadarko. These discoveries include interests in the Merganser, Vortex and San Jacinto fields which were acquired with Kerr-McGee during 2006. The initial production will be from fifteen wells, fourteen of which Anadarko has an interest. Nine wells were completed during 2006 and the remaining five wells will be completed during 2007. The Company anticipates first production from the Independence Hub in the second half of 2007.

Other  The acquisition of Kerr-McGee also included interests in the Neptune field (50% WI), Conger field (25% WI), Baldpate field (50% WI), Blind Faith field (37.5% WI) and Pompano field (25% WI). Anadarko also 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 and the developing lower tertiary play near the 2006 Kaskida discovery. During 2006, the Company delineated three discoveries: Tonga, Big Foot and Knotty Head, as well as had five additional discoveries; Kaskida, Power Play, Claymore, Caesar and Mission Deep. Anadarko also participated in five unsuccessful wells. The Company expects to participate in approximately four exploration wells and five delineation wells in the region in 2007.

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								Producing
				Undeveloped		Developed		Wells
				(Net	)	(Net	)	(Net	)
Offshore Acreage:
	Gulf of Mexico
		Western	*	1,386,142		63,911		26
		Central	*	979,690		45,646		34
		Eastern	*	265,536		1,152		--
	California			2,785		908		3
	APC fields:
		Nansen
		Boomvang
		Gunnison
		Baldpate/ Conger
		Red Hawk
		Constitution/ Ticonderoga
		K2 & K2N
		Marco Polo
		Independence Hub
		Blind Faith
		Pompano
		Neptune
* 2006 Drilling Activity
Production Blocks Exploratory Blocks 2006 Lease Acquisitions APC Fields

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Properties and Activities — Algeria

Overview  Anadarko is engaged in exploration, development and production activities in Algeria’s Sahara Desert. At the end of 2006, about 10% of the Company’s proved reserves were located in Algeria where a total of eight fields discovered by the Company were on production. In 2006, net sales volumes from the Company’s properties in Algeria represented 13% of the Company’s total sales volumes. In 2006, Anadarko participated in 14 wells with a success rate of 86%. In addition, the Company participated in nine injection or service wells during the year. The Company’s 2007 capital budget for Algeria is expected to be about $190 million and the budget provides for drilling about 25 development and service wells and four exploration wells.

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 has an exploration license, under separate PSA, for 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.

As of August 2006, Anadarko became subject to a new Algerian exceptional profits tax. For additional information seeRisk Factors under Item 1a andOther Developments under Item 7 of this Form 10-K.

Production and Development  On Block 404, production from the HBNS field averaged 119 MBbls/d of oil (gross) and production from five of the satellite fields averaged 42 MBbls/d of oil (gross) in 2006. Production from the HBN field, which extends from Block 404 into Block 403 and is unitized with other companies, averaged 73 MBbls/d of oil (gross) in 2006. 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 235 MBbls/d of oil (gross) in 2006. Anadarko has several fields farther south on Block 208. Development of the Block 208 fields, including the design of a new production facility, is progressing. Initial production from Block 208 is targeted for late 2010.

Exploration  During 2006, Anadarko had a satellite discovery at the BBKS-1 and one unsuccessful exploration well. Two wells were drilled to appraise the BBKS discovery with one encountering hydrocarbon bearing sands and the other being plugged and abandoned. During 2007, the Company expects to further test and delineate the BBKS discovery as well as participate in two exploration wells.

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Properties and Activities — Other International

Overview  The Company’s other international oil and gas production and or development operations are located primarily in China, Venezuela, Qatar and Brazil. The Company has exploration acreage in Brazil, China, Indonesia, Trinidad, Qatar and other selected areas. About 2% of the Company’s total proved reserves were located in these other international locations at year-end 2006. During 2006, net sales volumes from the Company’s other international properties accounted for 4% of the Company’s total volumes. In 2007, the Company’s capital budget is expected to be about $390 million for these other international projects and provides for drilling about 17 development and 17 exploration wells.

China  The Company’s interests in China were acquired with the Kerr-McGee acquisition in 2006. Anadarko’s development and production project in China straddles Block 04/36 and 05/36 in Bohai Bay in approximately 75 feet of water. The project consists of a gathering platform and two smaller unmanned satellite platforms, which are tied back to a floating production, storage and offloading vessel. During 2007, the Company plans to continue development drilling in the area. At the end of 2006, net production from China was approximately 17 MBbls/d of oil.

The Company also has exploration projects (100% WI in exploration phase) underway at Bohai Bay Blocks 09/18 and 09/06 and South China Sea Block 43/11. During 2006, Anadarko participated in three exploration wells with one discovery. During 2007, the Company plans to drill two exploration wells in Bohai Bay.

Venezuela  The Company’s operations in Venezuela are located in the Oritupano-Leona contract area. As a result of contract and structural changes imposed by the government of Venezuela, Anadarko’s interest in its Venezuela oil and gas properties was converted from the operating service agreement, under which Anadarko’s interest was previously consolidated in results of operations, to an 18% equity interest in a new operating company, Empresa Mixta Petroritupano. The conversion was completed in the fourth quarter of 2006. With respect to this investment, Anadarko is currently analyzing its options, including a possible sale. For additional information seeOther 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 2006. 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 (EPSA) covering Blocks 12 and 13. Production from the Al Rayyan field, located on Block 12, totaled 2.2 MMBbls of oil (net) in 2006. The Company also has an exploration program under EPSAs covering Block 4 (60% interest) and Block 11 (49% interest). With respect to the producing assets, Anadarko is currently analyzing its options, including a possible sale.

Brazil  The majority of Anadarko’s interests in Brazil were acquired with the Kerr-McGee acquisition in 2006. Anadarko now holds interests in more than one million gross undeveloped acres in Brazil. The Company holds a 50% interest in the Peregrino field located in the Campos basin. Anadarko expects development of the field to be sanctioned in 2007 with first production in 2010. In 2007, the Company plans to drill an appraisal well and acquire 3-D seismic.

Anadarko also holds exploration interests in several blocks located offshore in the Campos and Espírito Santo basins. Work obligations for the contract areas include the acquisition of 3-D seismic and a drilling commitment, with six wells still remaining. In 2007, Anadarko expects to acquire seismic and participate in one exploration well.

Trinidad  The Company has a program underway offshore Trinidad on Blocks 3a (25% interest) and 3b (34.5% interest). In 2006, the Company had a discovery on Block 3a that tested 5 MBbls/d in 180 feet of water. Appraisal drilling is underway to help determine commerciality of the discovery. During 2007, the Company expects to drill about three exploration wells on its Trinidad blocks.

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Indonesia  Anadarko has a participating interest in approximately 5.1 million exploration acres in Indonesia through a combination of several operated and non-operated Production Sharing Contracts (PSC). Anadarko also has entered into an outside-operated agreement, under which the Company has access to an additional 7.4 million acres with an $80 million exploration commitment. In addition, the Company is operator of a PSC for the North East Madura III Block offshore Indonesia. During 2006, Anadarko exchanged an interest in this block (retaining a 60% interest) for varying interests in five blocks located in the Tarakan basin and Makassar Straits of Indonesia. Anadarko also acquired and operates a PSC located in south Sumatra. Anadarko participated in five unsuccessful exploration wells in Indonesia in 2006. During 2007, Anadarko plans to participate in up to nine exploration wells.

Mozambique  In 2006, Anadarko signed an Exploration and Production Concession for the 2.64 million acre Offshore Area 1, located in northeast Mozambique in the Rovuma basin. The agreement has a five-year initial exploration term with a commitment to acquire new seismic and drill seven wells. Anadarko will operate the block, initially with a 100% interest.

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

Drilling Programs

The Company’s 2006 drilling program, related to continuing operations, focused on known oil and gas areas in the United States (Lower 48, Alaska and Gulf of Mexico) and Algeria. Exploration activity consisted of 76 wells, including 62 wells in the Lower 48, 5 wells offshore in the Gulf of Mexico, 4 wells in Algeria and 5 wells in other international locations. Development activity consisted of 1,461 wells, which included 1,412 wells in the Lower 48, 10 wells in Alaska, 11 wells offshore in the Gulf of Mexico, 10 wells in Algeria and 18 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
2006
United States	37.4	2.3	39.7	831.9	2.2	834.1	873.8
Algeria	0.8	0.8	1.6	1.8	—	1.8	3.4
Other International	—	2.6	2.6	3.5	—	3.5	6.1
Total	38.2	5.7	43.9	837.2	2.2	839.4	883.3
2005
United States	10.8	3.2	14.0	376.0	1.0	377.0	391.0
Algeria	0.5	0.3	0.8	2.9	0.2	3.1	3.9
Other International	0.5	—	0.5	5.4	—	5.4	5.9
Total	11.8	3.5	15.3	384.3	1.2	385.5	400.8
2004
United States	25.2	9.4	34.6	484.2	4.7	488.9	523.5
Algeria	1.1	1.5	2.6	2.1	—	2.1	4.7
Other International	—	—	—	8.1	—	8.1	8.1
Total	26.3	10.9	37.2	494.4	4.7	499.1	536.3

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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, 2006:

	Wells in the process of drilling or in active completion		Wells suspended or waiting on completion
	Exploration	Development	Exploration	Development
United States
Gross	11	107	30	256
Net	7.4	52.0	12.3	141.0
Algeria
Gross	—	2	2	5
Net	—	0.2	0.9	0.3
Other International
Gross	1	2	1	2
Net	0.3	0.6	0.3	0.7
Total
Gross	12	111	33	263
Net	7.7	52.8	13.5	142.0

Productive Wells

As of December 31, 2006, the Company had an ownership interest in productive wells as follows:

	Oil Wells*	Gas Wells*
United States
Gross	8,655	24,614
Net	6,366.6	14,630.0
Algeria
Gross	161	—
Net	32.3	—
Other International
Gross	365	—
Net	91.8	—
Total
Gross	9,181	24,614
Net	6,490.7	14,630.0
__________ *  Includes wells containing multiple completions as follows:
Gross	1,495	2,604
Net	1,468.4	2,441.3

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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, 2006:

	Developed Lease		Undeveloped Lease		Fee Minerals		Total
thousands	Gross	Net	Gross	Net	Gross	Net	Gross	Net
United States
Onshore — Lower 48	6,039	3,857	6,129	4,190	10,040	8,630	22,208	16,677
Offshore	284	112	4,162	2,634	—	—	4,446	2,746
Alaska	35	7	3,826	1,249	16	8	3,877	1,264
Total	6,358	3,976	14,117	8,073	10,056	8,638	30,531	20,687
Algeria*	225	55	2,640	778	—	—	2,865	833
Other International	81	39	28,861	13,932	—	—	28,942	13,971

* 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.

Gathering, Processing and Marketing Properties and Activities

Overview  Anadarko supports and seeks to enhance the value of its oil and gas operations through its gathering, processing and marketing (GPM) activities. These activities provide for the gathering, processing, transportation and ultimate sale of the Company’s production. In addition, the GPM function provides services for third-party customers.

Gathering and Processing  Anadarko invests in gathering and processing facilities (midstream) to complement its oil and gas operations in regions where the Company has significant production. The Company is better able to manage both the value received for, and cost of, gathering, treating and processing natural gas through its ownership and operation of these facilities. In addition, Anadarko’s midstream business provides gathering, treating and processing services for third-party customers, including major and independent producers. Anadarko generates revenues in its gathering and processing activities through various fee structures that include fixed-rate, percent of proceeds, or keep-whole agreements. The Company also processes gas at various third-party plants. During 2007, the Company’s capital budget for midstream operations is expected to be about $500 million.

In 2006, Anadarko significantly increased the size and scope of its midstream business through the acquisitions of Western and Kerr-McGee. With these acquisitions, Anadarko has systems in eight states (Wyoming, Colorado, Utah, New Mexico, Kansas, Oklahoma, Texas and Louisiana) located in major onshore producing basins. The following table provides key statistics for Company-owned gathering and processing facilities.

	Number of Gathering and Processing Facilities	Miles of Gathering Systems	Total Horsepower	2006 Average Throughput (MMcf/d)
Legacy Anadarko	17	3,575	212,294	1,051
Acquired with Kerr-McGee	2	2,394	124,054	568
Acquired with Western	16	12,178	661,588	1,480
Total	35	18,147	997,936	3,099

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Marketing  The Company’s marketing department actively manages the sales of its natural gas, crude oil and NGLs. In marketing its production, the Company attempts to maximize realized prices while managing credit risk 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 helps enable the Company to maximize prices received for the Company’s production.

The Company sells natural gas under a variety of contracts. The Company has the marketing capability to move large volumes of gas into and out of the daily gas market to 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.

In 2006, the Company also engaged in sales of greenhouse gas emission reduction credits (ERCs) derived from CO₂injection operations in Wyoming. The Company expects additional sales of ERCs in the future.

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, seeNote 10 — Sale of Future Hard Minerals Royalty Revenuesof theNotes to Consolidated Financial Statementsunder Item 8 of this Form 10-K.

Segment and Geographic Information

Information on operations by segment and geographic location is contained inNote 16of theNotes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Employees

As of December 31, 2006, the Company had approximately 5,200 employees. Anadarko considers its relations with its employees to be satisfactory. The Company has had no significant work stoppages or strikes associated with its employees.

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Regulatory Matters and Additional Factors Affecting Business

SeeRisk Factorsunder 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 legal counsel for the Company, are not so material as to detract substantially from the use of such properties.

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

Capital Spending

SeeCapital Resources and Liquidityunder Item 7 of this Form 10-K.

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

	2006	2005	2004
Ratio of earnings to fixed charges	6.37	12.99	5.66
Ratio of earnings to combined fixed charges and preferred stock dividends	6.32	12.63	5.56

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

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,

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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, NGLs and other products or services, the price of oil, natural gas, NGLs and other products or services, the weather, inflation, the availability of goods and services, drilling risks, future processing volumes and pipeline throughput, general economic conditions, either internationally or nationally or in the jurisdictions in which the Company or its subsidiaries are doing business, legislative or regulatory changes, including changes in environmental regulation, environmental risks and liability under federal, state and foreign environmental laws and regulations, potential environmental obligations arising from Kerr-McGee’s former chemical business, the securities or capital markets, the ability to successfully integrate the operations of the Company, Kerr-McGee and Western, our ability to repay the debt issued for the acquisition of Kerr-McGee and Western, the outcome of proceedings related to the Algerian exceptional profits tax, and other factors discussed below and elsewhere in this Form 10-K and in the Company’s public filings, press releases and discussions with Company management. Anadarko undertakes no obligation to publicly update or revise any forward looking statements.

We may not be able to successfully integrate Kerr-McGee’s and Western’s operations with our operations.

Integration of the three previously independent companies is a complex, time consuming and costly process. Failure to timely and successfully integrate these companies may have a material adverse effect on the combined company’s business, financial condition and result of operations. The difficulties of combining the companies present challenges to our management, including:

• operating a significantly larger combined company;

• integrating personnel with diverse backgrounds and organizational cultures;

• experiencing operational interruptions or the loss of key employees, customers or suppliers; and

• consolidating other corporate and administrative functions.

The combined company is also exposed to risks that are commonly associated with transactions similar to the mergers, such as unanticipated liabilities and costs, some of which may be material, and diversion of management’s attention. As a result, the anticipated benefits of the mergers may not be fully realized, if at all.

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

We incurred approximately $24.9 billion in debt (including debt assumed) to consummate the Kerr-McGee and Western mergers. Our total debt was about $23.0 billion as of December 31, 2006. We also have various commitments for operating leases, drilling contracts and transportation and purchase obligations for services and products. Our financial commitments could have important consequences to you. For example, it could:

• increase our vulnerability to general adverse economic and industry conditions;

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

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

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

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A downgrade in our credit rating could negatively impact our cost of capital.

Standard and Poor’s (S&P) and Moody’s Investor Services (Moody’s) rate our debt at “BBB-” with a stable outlook and “Baa3” with a negative outlook, respectively. Although we are not aware of any current plans of S&P or Moody’s to lower their respective ratings on our debt, we cannot be assured that such credit ratings will not be downgraded. Although we do not have any rating downgrade triggers that would accelerate the maturity dates of outstanding debt, a downgrade in our credit ratings could negatively impact our cost of capital or our ability to effectively execute aspects of our strategy.

Failure to close our pending or planned asset divestitures could hinder our ability to reduce our debt.

Total debt at December 31, 2006, includes $11 billion outstanding under our 364-day acquisition facility that is due in August 2007. We intend to repay the majority of the remaining balance with proceeds from announced or targeted divestitures, free cash provided by operations and possible securities issuances. An unexpected delay or inability to complete pending or planned asset divestitures could have a material adverse effect on Anadarko’s ability to reduce its debt, which could negatively impact Anadarko’s stock price, credit rating and financial condition. For more information, seeOutlook under Item 7 of this Form 10-K.

We may incur substantial costs to comply with environmental requirements, including costs arising from Kerr-McGee’s former chemical business.

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

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 volatile trading patterns in the commodity futures markets. In addition, in OPEC countries in which we have production such as Algeria 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. See Note 1 — Summary of Significant Accounting Policiesunder Item 8 for additional information on the ceiling test.

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

As a result of mergers and acquisitions, at December 31, 2006 we had approximately $4.3 billion of goodwill on our balance sheet. Goodwill is not amortized, but instead must be tested at least annually for

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impairment by applying a fair-value-based test. Goodwill is deemed impaired to the extent that its carrying amount exceeds the fair value of the reporting unit. Although our latest tests indicate that no goodwill impairment is currently required, future deterioration in market conditions could lead to goodwill impairments that could have a substantial negative effect on our profitability.

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

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

• the amounts and types of substances and materials that may be released 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, seeLegal Proceedingsunder 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, gathering, processing and transportation 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 compensation insurance. However, we are not fully insured against all risks in all aspects of our business, such as political risk, business interruption risk and risk of major terrorist attacks. The occurrence of a significant event against which we are not fully insured could have a material adverse effect on our financial position.

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.

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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;

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

• currency restrictions and exchange rate fluctuations.

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

Realization of any of these factors could materially adversely affect our financial position.

We may be subject to increased tax payment obligations in connection with our operations in Algeria. Such increases could impact results of operations, cash flows and proved reserves.

In July 2006, the Algerian parliament approved legislation establishing an exceptional profits tax on foreign companies’ Algerian oil and gas production. In December 2006, implementing regulations regarding this legislation were issued and Sonatrach notified us as to the applicable regulatory provisions. The regulations provide for an exceptional profits tax imposed on gross production at rates of taxation ranging from 5% to 50% based on average daily production volumes for each calendar month. Uncertainty exists as to whether the exceptional profits tax will apply to the full value of our production or only to the value of our production in excess of $30 per barrel.

In the fourth quarter of 2006, we recorded a $103 million liability for the exceptional profits tax based on the assumption that the tax applies only to production value in excess of $30 per barrel. If the exceptional profits tax is applied to the full value of production, we estimate the 2006 liability for exceptional profits tax would be $190 million.

We currently have 111 million barrels of proved undeveloped reserves in Algeria, the economics of which are sensitive to the exceptional profits tax. We are reviewing whether these reserves remain economic under existing development plans if the exceptional profits tax is applied to the entire production value.

We are not yet in a position to confirm the probable interpretation of the law, but are continuing to monitor further guidance to determine the law’s ultimate application. For additional information seeOther Developments under Item 7 if this Form 10-K.

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,

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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.

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

To the extent that we engage in price risk management activities to endeavor to protect ourselves from commodity price declines, the Company will be prevented from realizing the full benefits of price increases above the levels of the derivative instruments used to manage price risk. 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.

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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.

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.

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

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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.

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 Anadarko, 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 may be beneficial to our stockholders, including provisions governing the classification, nomination and removal of directors, prohibiting stockholder action by written consent and regulating the ability of our stockholders to bring matters for action before annual stockholder meetings, and the authorization given to our Board of Directors to issue and set the terms of preferred stock.

In addition, 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 imposes 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.

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Item 2.  Properties

Information on Properties is contained in Item 1 of this Form 10-K and inNote 20 — Commitmentsof theNotes to Consolidated Financial Statementsunder Item 8 of this Form 10-K.

Item 3.  Legal Proceedings

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

Environmental Matters  In June 2005 and November 2005, Kerr-McGee Oil and Gas Onshore LP received Notices of Violation from the Colorado Department of Public Health and Environment alleging that allowable air emissions under the Clean Air Act were exceeded with respect to certain production operations in Colorado. Kerr-McGee Oil and Gas Onshore LP also received a letter from the Department of Justice in November 2005 alleging violations of certain air quality and permitting regulations at the Cottonwood and Ouray compressor stations in Uintah County, Utah, which were operated by Westport Oil and Gas Company L.P. prior to Westport’s merger with Kerr-McGee. The Department of Justice later alleged that certain air quality regulations were also violated at the Bridge compressor station in Uintah County. The Company has reached a tentative settlement with the state and federal agencies to resolve all of the air issues by agreeing to pay a monetary penalty of $200,000 and by performing a Supplemental Environmental Project valued at $100,000. The settlement will also require the Company to perform certain air emission control measures requiring capital expenditures of approximately $15 million pursuant to a time schedule that is being negotiated.

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

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 2006.

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Executive Officers of the Registrant

Name	Age at End of 2007	Position
James T. Hackett	53	Chairman of the Board, President and Chief Executive Officer
Karl F. Kurz	46	Chief Operating Officer
Robert P. Daniels	48	Senior Vice President, Worldwide Exploration
Charles A. Meloy	47	Senior Vice President, Worldwide Operations
Robert K. Reeves	50	Senior Vice President, General Counsel and Chief Administrative Officer
R. A. Walker	50	Senior Vice President, Finance and Chief Financial Officer
Bruce W. Busmire	50	Vice President, Chief Accounting Officer
Mario M. Coll, III	45	Vice President, Information Technology Services and Chief Information Officer
Robert G. Gwin	44	Vice President, Finance and Treasurer
Preston Johnson, Jr.	52	Vice President, Human Resources
Gregory M. Pensabene	57	Vice President, Government Relations
Albert L. Richey	58	Vice President, Corporate Development
Charlene A. Ripley	43	Vice President

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. Kurz was named Chief Operating Officer in December 2006. Prior to this position, he served as Senior Vice President, Marketing and General Manager, U.S. Onshore since 2005, Vice President, Marketing since 2003 and Manager, Energy Marketing since 2001. He previously worked in Anadarko’s marketing department since 2000.

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

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

Mr. Reeves was named Senior Vice President, General Counsel and Chief Administrative Officer in February 2007. He had previously served as Senior Vice President, Corporate Affairs & Law and Chief Governance Officer since 2004. Prior to joining Anadarko, he served as Executive Vice President, Administration and General Counsel of North Sea New Ventures from 2003 to 2004, and as Executive Vice President, General Counsel and Secretary of Ocean Energy, Inc. and its predecessor companies from 1997 to 2003.

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.

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Mr. Busmire was named Vice President, Chief Accounting Officer in 2006. Prior to joining Anadarko, he served as Senior Vice President, Chief Financial Officer, Treasurer and Controller of Noble Corporation since 2005 and was a Managing Director of Pickering Energy Partners, Inc. since 2004. Prior to this position, he served as Vice President of Investor Relations at Ocean Energy, Inc. since 2000. Prior to this position, Mr. Busmire served as Controller of Altura Energy since 1997.

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 since 2003 and Vice President, Operational Planning and Chief Information Officer for Ocean Energy, Inc. and its predecessor companies since 1997.

Mr. Gwin was named Vice President, Finance and 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 position, Mr. Gwin worked for Prudential Financial in a variety of merchant banking positions.

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.

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 in February 2007. She 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.

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 16, 2007, 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 inCorporate Informationin the Anadarko Petroleum Corporation 2006 Annual Report (Annual Report) which is incorporated herein by reference.

As of January 31, 2007, there were approximately 17,500 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, 2006:

millions	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2006	$	41	$	42	$	42	$	42
2005	$	43	$	43	$	42	$	42

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, seeDividendsunder Item 7 andNote 13 – Common Stock under Item 8 of this Form 10-K.

Common Stock Repurchase Table  The following table sets forth information with respect to repurchases by the Company of its shares of common stock during the fourth quarter of 2006.

Period	Total number of shares purchased(1)	Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs	Approximate dollar value of shares that may yet be purchased under the plans or programs(2)
October 1-31	195,957	$	46.03	—
November 1-30	104,999	$	47.52	—
December 1-31	93,701	$	46.87	—
Fourth Quarter 2006	394,657	$	46.63	—	$	636,000,000

⁽¹⁾ During the fourth quarter of 2006, no shares were purchased under the Company’s share repurchase programs. During the fourth quarter of 2006, the 394,657 shares purchased were related to stock received by the Company for the payment of withholding taxes due on shares issued under employee stock plans.

⁽²⁾ In November 2005, the Company announced a 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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Performance Graph

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

The following graph compares the cumulative 5-year total return to shareholders on Anadarko’s common stock relative to the cumulative total returns of the S & P 500 index and a customized peer group of twelve companies. The companies included in the customized peer group are: Apache Corp., Chesapeake Energy Corp., Chevron Corp., ConocoPhillips, Devon Energy Corp., EnCana Corp., EOG Resources Inc, Hess Corp., Marathon Oil Corp., Noble Energy Inc, Occidental Petroleum Corp. and Pioneer Natural Resources Company. An investment of $100 (with reinvestment of all dividends) is assumed to have been made in the Company’s common stock, in the index and in the peer group on December 31, 2001 and its relative performance is tracked through December 31, 2006.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN AMONG

ANADARKO PETROLEUM CORPORATION, THE S & P 500 INDEX

AND A PEER GROUP

Fiscal Year Ended December 31		2001		2002		2003		2004		2005		2006
Anadarko Petroleum Corporation	$	100.00	$	84.82	$	91.20	$	116.98	$	172.46	$	159.63
S & P 500		100.00		77.90		100.24		111.15		116.61		135.03
Peer Group		100.00		86.88		115.55		151.38		205.38		248.38

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Item 6. Selected Financial Data

	Summary Financial Information*
dollars in millions, except per share amounts	2006			2005		2004		2003		2002
Revenues	$	10,187		$	6,187	$	5,124	$	4,246	$	3,184
Operating Income		4,887			3,535		2,517		1,830		1,204
Income from Continuing Operations		2,796			2,073		1,301		892		642
Income from Discontinued Operations, net of taxes		2,058			398		305		353		189
Net Income Available to Common Stockholders before Change in Accounting Principle		4,851			2,466		1,601		1,240		825
Net Income Available to Common Stockholders		4,851			2,466		1,601		1,287		825
Per Common Share:
Income from Continuing Operations — Basic	$	6.06		$	4.40	$	2.60	$	1.78	$	1.28
Income from Continuing Operations — Diluted	$	6.02		$	4.36	$	2.58	$	1.76	$	1.24
Income from Discontinued Operations — Basic	$	4.47		$	0.85	$	0.61	$	0.71	$	0.38
Income from Discontinued Operations — Diluted	$	4.44		$	0.84	$	0.60	$	0.70	$	0.36
Net Income Available to Common Stockholders — Basic	$	10.54		$	5.24	$	3.21	$	2.58	$	1.66
Net Income Available to Common Stockholders — Diluted	$	10.46		$	5.19	$	3.18	$	2.55	$	1.61
Dividends	$	0.36		$	0.36	$	0.28	$	0.22	$	0.162
Average Number of Common Shares Outstanding — Basic		460			470		499		499		497
Average Number of Common Shares Outstanding — Diluted		464			475		503		507		519
Cash Provided by Continuing Operating Activities	$	5,034		$	3,502	$	2,743	$	2,426	$	1,796
Cash Provided by (used in) Discontinued Operating Activities		(139	)		644		464		617		400
Net Cash Provided by Operating Activities		4,895			4,146		3,207		3,043		2,196
Capital Expenditures	$	4,594		$	2,943	$	2,510	$	2,289	$	1,980
Total Debt	$	22,991		$	3,627	$	3,790	$	4,959	$	5,334
Stockholders’ Equity		14,913			11,051		9,285		8,599		6,972
Total Assets	$	58,844		$	22,588	$	20,192	$	20,546	$	18,248
Annual Sales Volumes:
Continuing Operations
Gas (Bcf)		558			414		499		503		507
Oil and Condensate (MMBbls)		70			56		62		61		63
Natural Gas Liquids (MMBbls)		15			13		16		16		14
Total (MMBOE)**		178			138		161		162		162
Discontinued Operations (MMBOE)		17			20		29		30		35
Total (MMBOE)**		195			158		190		192		197
Average Daily Sales Volumes:
Continuing Operations
Gas(MMcf/d)		1,529			1,136		1,363		1,379		1,390
Oil and Condensate (MBbls/d)		193			155		171		167		172
Natural Gas Liquids (MBbls/d)		42			36		43		45		39
Total (MBOE/d)		489			379		441		442		442
Discontinued Operations (MBOE/d)		45			55		79		83		97
Total (MBOE/d)		534			434		520		525		539
Reserves:
Continuing Operations
Oil Reserves (MMBbls)		1,264			1,090		1,073		1,161		1,067
Gas Reserves (Tcf)		10.5			6.6		6.2		6.2		5.8
Total Reserves (MMBOE)		3,011			2,187		2,113		2,199		2,040
Discontinued Operations (MMBOE)		—			262		254		314		288
Total Reserves (MMBOE)		3,011			2,449		2,367		2,513		2,328
Number of Employees		5,200			3,300		3,300		3,500		3,800

  * Consolidated for Anadarko Petroleum Corporation and its subsidiaries. Certain amounts for prior years have been reclassified to conform to the current presentation. Factors that materially effect the comparability of this information are disclosed inManagement’s Discussion and Analysis under Item 7 of this Form 10-K.

** 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, gathering, processing and marketing of natural gas, crude oil, condensate and NGLs. The Company’s major areas of operations are located in the United States and Algeria. The Company also has activity in China, Brazil, 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.

On August 10, 2006, Anadarko completed the acquisition of Kerr-McGee in an all-cash transaction totaling $16.5 billion plus the assumption of $2.6 billion debt. On August 23, 2006, Anadarko completed the acquisition of Western in an all-cash transaction totaling $4.8 billion plus the assumption of $625 million debt. Anadarko financed $22.5 billion for the acquisitions under a 364-day committed acquisition facility. In November 2006, the Company sold its wholly-owned Canadian oil and gas subsidiary, Anadarko Canada Corporation, for approximately $4.3 billion before tax. After tax proceeds from the divestiture were used to reduce debt under the acquisition facility. Unless noted otherwise, the following information relates to continuing operations and excludes the discontinued Canadian operations. SeeAcquisitions and Divestitures, Outlook andDiscontinued Operations for additional information.

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 total year-end 2003 proved reserves and about 20% of total 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 of Continuing Operations

Selected Data

millions except per share amounts	2006		2005		2004
Financial Results
Revenues	$	10,187	$	6,187	$	5,124
Costs and expenses		5,300		2,652		2,607
Interest expense and other (income) expense		649		130		417
Income tax expense		1,442		1,332		799
Income from continuing operations	$	2,796	$	2,073	$	1,301
Earnings per common share — diluted	$	6.02	$	4.36	$	2.58
Average number of common shares outstanding — diluted		464		475		503
Operating Results
Total proved reserves (MMBOE)		3,011		2,187		2,113
Annual sales volumes (MMBOE)		178		138		161
Capital Resources and Liquidity
Cash provided by operating activities	$	5,034	$	3,502	$	2,743
Capital expenditures		4,594		2,943		2,510
Total debt		22,991		3,627		3,790
Stockholders’ equity	$	14,913	$	11,051	$	9,285
Debt to total capitalization ratio		61%		25%		29%

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In May 2006, the Company’s shareholders approved an increase in authorized shares so Anadarko could complete a two-for-one stock split to be effected in the form of a stock dividend. The distribution date was May 26, 2006 to stockholders of record on May 12, 2006. All prior period share and per share information presented on the following pages have been revised to reflect the stock split.

Anadarko’s financial and operating results for 2006 include the operating results of Kerr-McGee and Western since the dates of their acquisition.

Financial Results — Continuing Operations

Net Income  Anadarko’s net income from continuing operations for 2006 totaled $2.8 billion, or $6.02 per share (diluted), compared to net income from continuing operations for 2005 of $2.1 billion, or $4.36 per share (diluted). Anadarko had net income from continuing operations in 2004 of $1.3 billion, or $2.58 per share (diluted). The increase in 2006 net income was primarily due to higher sales volumes and net realized commodity prices, partially offset by higher operating costs and expenses and higher interest expense. The higher sales volumes, operating expenses and interest expense were due primarily to the impact of operations acquired and debt incurred with the third quarter 2006 acquisitions, charges associated with impairments of certain international properties and an increase in other costs and expenses. The increase in 2005 net income compared to 2004 was primarily due to higher net realized commodity prices and lower expenses, partially offset by lower volumes associated with divestitures in late 2004. Natural gas sales, and oil and condensate sales for 2006 include $579 million and $258 million, respectively, related to the recognition of net unrealized gains on derivatives used to manage price risk. Unrealized gains (losses) related to derivatives were not material in 2005 or 2004. The majority of the unrealized gains recognized in 2006 related to derivatives assumed with the Kerr-McGee acquisition.

Revenues

millions	2006		2005		2004
Gas sales	$	4,186	$	2,968	$	2,583
Oil and condensate sales		4,601		2,703		2,022
Natural gas liquids sales		594		437		439
Gathering, processing and marketing sales		718		76		51
Other		88		3		29
Total	$	10,187	$	6,187	$	5,124

Anadarko’s total revenues for 2006 increased 65% compared to 2005 and total revenues for 2005 increased 21% compared to 2004. The increase in 2006 was primarily due to higher sales volumes and net commodity prices. 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 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 increased total revenues $1,131 million during 2006 compared to a decrease of $294 million in 2005. The impact of price risk management decreased total revenues $518 million during 2004. SeeEnergy Price Riskunder Item 7a andNote 9 — Financial Instruments under Item 8 of this Form 10-K.

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Analysis of Oil and Gas Operations Sales Volumes

	2006	2005	2004
Barrels of Oil Equivalent (MMBOE)
United States	147	106	131
Algeria	23	24	22
Other International	8	8	8
Total	178	138	161
Barrels of Oil Equivalent per Day (MBOE/d)
United States	404	292	358
Algeria	64	65	61
Other International	21	22	22
Total	489	379	441

During 2006, Anadarko’s daily sales volumes increased 29% compared to 2005 primarily due to higher sales volumes associated with the third quarter 2006 acquisitions and higher sales volumes from the Gulf of Mexico, partially offset by lower legacy gas volumes in east Texas and Louisiana, and lower oil sales volumes in Venezuela. During 2005, Anadarko’s daily sales volumes decreased 14% compared to 2004 due to lower sales volumes in the United States as a result of divestitures of non-core properties in late 2004.

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

Natural Gas Sales Volumes and Average Prices

	2006		2005			2004
United States (Bcf)		558		414			499
MMcf/d		1,529		1,136			1,363
Price per Mcf	$	6.14	$	7.44		$	5.62
Gains (losses) on derivatives	$	1.36	$	(0.28	)	$	(0.44	)
Total price per Mcf	$	7.50	$	7.16		$	5.18

Anadarko’s daily natural gas sales volumes in 2006 increased 35% compared to 2005. The increases were primarily due to higher sales volumes associated with the third quarter acquisitions and higher volumes in the Haley field of West Texas, partially offset by natural declines in east Texas and north Louisiana. The Company’s daily natural gas sales volumes for 2005 were down 17% compared to 2004 primarily due to the impact of divestitures in the United States in late 2004, 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.

Excluding the impact of both realized and unrealized gains and losses on derivatives, Anadarko’s average natural gas price for 2006 decreased 17% compared to the same period of 2005. Excluding the impact of both realized and unrealized gains and losses on derivatives, Anadarko’s average natural gas price for 2005 increased 32% compared to the same period of 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. As of December 31, 2006, the Company has utilized price risk management on 36% of its anticipated natural gas wellhead sales volumes for 2007.

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Crude Oil and Condensate Sales Volumes and Average Prices

	2006		2005			2004
United States (MMBbls)		39		24			32
MBbls/d		108		68			88
Price per barrel	$	59.41	$	51.67		$	38.71
Gains (losses) on derivatives	$	9.18	$	(7.32	)	$	(7.06	)
Total price per barrel	$	68.59	$	44.35		$	31.65
Algeria (MMBbls)		23		24			22
MBbls/d		64		65			61
Price per barrel	$	65.59	$	54.38		$	34.78
Other International (MMBbls)		8		8			8
MBbls/d		21		22			22
Price per barrel	$	48.58	$	39.37		$	27.91
Total (MMBbls)		70		56			62
MBbls/d		193		155			171
Price per barrel	$	60.29	$	51.03		$	37.12
Gains (losses) on derivatives	$	5.15	$	(3.19	)	$	(4.84	)
Total price per barrel	$	65.44	$	47.84		$	32.28

Anadarko’s daily crude oil and condensate sales volumes for 2006 were up 25% compared to the same period of 2005. The increases in 2006 were primarily due to higher sales volumes associated with the third quarter 2006 acquisitions and additional wells being tied in and put into production at the Company’s legacy properties in the Gulf of Mexico, partially offset by a decrease in sales volumes from Venezuela due to recent contract changes. Anadarko’s daily crude oil and condensate sales volumes for 2005 decreased 9% compared to 2004 due to the impact of divestitures in the United States 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. Production of oil usually is not affected by seasonal swings in demand.

Excluding the impact of both realized and unrealized gains and losses on derivatives, Anadarko’s average crude oil price for 2006 increased 18% compared to the same period of 2005 and increased 37% for 2005 compared to the same period of 2004. The higher crude oil prices were attributed to continuing political unrest in oil exporting countries, increased worldwide demand and the impact of hurricanes in the Gulf of Mexico on oil production and infrastructure. As of December 31, 2006, the Company has utilized price risk management on 41% of its anticipated oil and condensate volumes for 2007.

Natural Gas Liquids Sales Volumes and Average Prices

	2006		2005		2004
Total (MMBbls)		15		13		16
MBbls/d		42		36		43
Price per barrel	$	39.58	$	34.56	$	27.84

Anadarko’s daily NGLs sales volumes in 2006 were up 17% compared to 2005, primarily due to higher sales volumes associated with the third quarter 2006 acquisitions. The Company’s 2005 daily NGLs sales volumes were down 16% compared to 2004, primarily due to the impact of divestitures in the United States in 2004.

During 2006, average NGLs prices increased 15% compared to the same period of 2005 and increased 24% for 2005 compared to the same period of 2004. NGLs production is dependent on natural gas and NGLs prices as well as the economics of processing the natural gas to extract NGLs. NGLs sales represent revenues derived from the processing of Anadarko’s natural gas production.

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Gathering, Processing and Marketing Revenues

millions	2006		2005		2004
Gathering and processing sales	$	538	$	26	$	21
Marketing sales		180		50		30
Total	$	718	$	76	$	51

During 2006, gathering and processing sales increased $512 million compared to the same period of 2005. The increase was due primarily to gathering and processing operations acquired with the 2006 acquisitions. During 2005, gathering and processing sales increased $5 million compared to the same period of 2004. Gathering and processing revenues represent revenues derived from gathering and processing natural gas from sources other than the Company’s production. Marketing sales primarily represent the revenues earned on sales of third party gas, oil and NGLs, net of purchases.

Costs and Expenses

millions	2006		2005		2004
Oil and gas operating	$	799	$	400	$	481
Oil and gas transportation and other		341		256		218
Gathering, processing and marketing		553		56		39
General and administrative		668		393		373
Depreciation, depletion and amortization		1,976		1,111		1,132
Other taxes		575		358		292
Impairments		388		78		72
Total	$	5,300	$	2,652	$	2,607

During 2006, Anadarko’s costs and expenses increased 100% compared to 2005 due to the following factors:

— Oil and gas operating expense increased 100% due to $253 million in operating expenses for properties acquired with the 2006 acquisitions and $146 million associated with increased workover, maintenance and repair activity in the United States, an increase in expenses in the Gulf of Mexico associated with higher volumes, and rising utility and fuel expenses as a result of higher energy costs and industry demand.

— Oil and gas transportation and other expenses increased 33%. Transportation expenses increased primarily due to higher volumes transported as a result of the 2006 acquisitions.

— Gathering, processing and marketing expenses increased $497 million. Costs associated with gathering and processing operations increased $430 million primarily due to facilities acquired with Western and Kerr-McGee. Marketing transportation and cost of product increased $67 million primarily due to higher volumes transported as a result of the 2006 acquisitions and the assumption of firm transportation contracts during the year.

— General and administrative (G&A) expense increased 70% due primarily to increases of $93 million related to compensation, legal and other general expenses attributed to the operations acquired from Kerr-McGee and Western, $77 million associated with rising compensation costs for legacy employees, $77 million related to severance and one-time benefits associated with Company’s initial post acquisition asset realignment and restructuring efforts and $28 million related to increases in general office expenses at legacy locations.

— Depreciation, depletion and amortization (DD&A) expense increased 78%. DD&A expense associated with oil and gas properties increased $479 million due to higher costs associated with acquiring, finding and developing oil and gas reserves, $307 million due to higher volumes associated with the acquisitions and $13 million related to higher asset retirement obligation accretion expense. Depreciation of other property and equipment increased $66 million due primarily to gathering, processing and general properties obtained with the third quarter 2006 acquisitions. The total impact of the third quarter 2006 acquisitions on DD&A expense was an increase of $706 million.

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— Other taxes increased 61%. The increase includes a $103 million accrual for the estimated impact of a new Algerian exceptional profits tax. SeeOther Developments. The remaining increase of $114 million is primarily due to the effect of higher production volumes and higher commodity prices on production taxes.

— Impairments in 2006 include a $178 million loss associated with the termination of the Venezuela operating service agreement in exchange for an 18% equity interest in a new operating company, a $139 million impairment related to the decision to suspend construction of the Company’s Bear Head LNG project in Nova Scotia and $71 million in impairments related to exploration activities at various international locations.

During 2005, Anadarko’s costs and expenses increased 2% compared to 2004 due to the following factors:

— Oil and gas operating expense decreased $81 million primarily due to the impact of properties divested in late 2004 and included $12 million associated with 2004 severance and other costs related to divestitures and reorganization efforts.

— Oil and gas transportation and other expenses increased 17%. The $12 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.

— Gathering, processing and marketing expenses increased 44% primarily due to higher transportation expenses and NGLs transportation, fractionation and processing costs. The $36 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, gathering, processing and marketing sales revenues.

— G&A expense increased 5% primarily due to an increase of $47 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 $13 million. These increases were partially offset by a $28 million decrease in legal expenses and a decrease of $16 million due to 2004 severance and other costs related to divestitures and reorganization efforts.

— DD&A expense decreased 2%. DD&A expense includes decreases of $151 million related to lower production volumes and $8 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 $138 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 23% primarily due to higher 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.

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Interest Expense and Other (Income) Expense

millions	2006			2005			2004
Interest Expense
Gross interest expense	$	730		$	266		$	328
Premium and related expenses for early retirement of debt		—			—			100
Capitalized interest		(75	)		(60	)		(70	)
Net interest expense		655			206			358
Other (Income) Expense
Interest income		(47	)		(17	)		(5	)
Firm transportation keep-whole contract valuation		4			(56	)		(1	)
Operating lease settlement		—			—			63
Other		37			(3	)		2
Total other (income) expense		(6	)		(76	)		59
Total	$	649		$	130		$	417

Interest Expense  Anadarko’s gross interest expense increased 174% during 2006 compared to 2005. The increase was primarily due to an increase in debt associated with the acquisitions of Kerr-McGee and Western. Gross interest expense in 2005 decreased 19% compared to 2004 due to lower average outstanding debt. Interest expense for 2004 included $100 million of premiums and related expenses for the early retirement of debt in 2004. For additional information seeAcquisitions and Divestituresand Debt below andInterest Rate Risk under Item 7a of this Form 10-K.

In 2006, capitalized interest increased by 25% compared to 2005. The 2006 increase was primarily due to the higher capitalized costs that qualify for interest capitalization. In 2005, capitalized interest decreased by 14% compared to 2004. The 2005 decrease was primarily due to lower capitalized costs that qualify for interest capitalization.

Other (Income) Expense  For 2006, the Company had other income of $6 million compared to other income of $76 million for 2005. The decrease of $70 million was primarily due to a $60 million decrease in gains related to the effect of market values for firm transportation subject to a keep-whole agreement, a $22 million loss on an impaired equity investment and an $18 million loss related to environmental and legal reserve adjustments, partially offset by a $30 million increase in interest income. The keep-whole agreement was terminated April 1, 2006.

For 2005, the Company had other income of $76 million compared to other expense of $59 million for 2004. The favorable change of $135 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 and an increase in interest income of $12 million.

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Income Tax Expense

millions except percentages	2006		2005		2004
Income tax expense	$	1,442	$	1,332	$	799
Effective tax rate		34%		39%		38%

For 2006, income taxes increased 8% compared to 2005 primarily due to an increase in income before income taxes, partially offset by a decrease in state income taxes resulting from enacted Texas legislation, excess U.S. foreign tax credits and a decrease in net foreign income taxes. For 2005, income taxes increased 67% compared to 2004 primarily due to higher income before income taxes.

Variances from the 35% statutory rate are caused by foreign taxes in excess of federal statutory rates, state income taxes, excess U.S. foreign tax credits and other items.

Texas House Bill 3, signed into law in May 2006, eliminates the taxable capital and earned surplus components of the existing franchise tax and replaces these components with a taxable margin tax calculated on a combined basis. There will be no impact on Anadarko’s 2006 Texas current state income taxes as the new tax is effective for reports due on or after January 1, 2008 (based on business activity during 2007). Anadarko is required to include the impact of the law change on its deferred state income taxes in income for the period which includes the date of enactment. The adjustment, a reduction in Anadarko’s deferred state income taxes in the amount of approximately $69 million, net of federal benefit, was included in the 2006 tax provision.

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

Acquisitions and Divestitures  In August 2006, Anadarko acquired Kerr-McGee and Western in separate all-cash transactions. Anadarko initially financed $22.5 billion for the acquisitions through a 364-day committed acquisition facility with plans to repay it with proceeds from asset sales, free cash flow from operations and the issuance of equity, debt and bank financing during the term of the facility. Anadarko intends to reduce leverage significantly in 2007 through a combination of continued asset sales, retained earnings buildup, excess cash flow beyond capital expenditures and possible securities offerings. SeeOutlook. As of December 31, 2006, the Company has refinanced approximately $6 billion of the acquisition facility with new long-term issuances and repaid approximately $5.5 billion with divestiture proceeds and cash flow from operations.

Kerr-McGee Transaction  On August 10, 2006, Anadarko completed the acquisition of Kerr-McGee for $16.5 billion, or $70.50 per share, plus the assumption of $2.6 billion of debt. Kerr-McGee’s year-end 2005 proved reserves, excluding Gulf of Mexico shelf divestitures, totaled 898 MMBOE, of which approximately 62% was natural gas. Proved undeveloped reserves represented 30% of the total.

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

Western Transaction  On August 23, 2006, Anadarko completed the acquisition of Western for $4.8 billion, or $61.00 per share, plus the assumption of $625 million of debt. Western’s year-end 2005 proved reserves totaled 153 MMBOE, with proved undeveloped reserves representing 57% of the total. Essentially all of the reserves are natural gas.

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

Divestitures  In November 2006, Anadarko sold its wholly-owned subsidiary, Anadarko Canada Corporation, for approximately $4.3 billion before taxes. The sale is part of a portfolio refocusing effort stemming from the acquisitions of Kerr-McGee and Western. Net proceeds from the divestiture were used to retire debt. SeeDiscontinued Operations.

On the acquisition date, Kerr-McGee’s other assets included approximately $1 billion of assets held for sale. The sale of these assets closed in August 2006 and the proceeds were also used to pay down debt incurred to fund the acquisitions.

In November 2006, Anadarko reached an agreement to sell its interests in the Knotty Head and Big Foot oil discoveries, as well as the Big Foot North prospect in the Gulf of Mexico for $901 million. In December 2006, the Company reached an agreement to sell its Vernon and Ansley fields, located in Jackson Parish, Louisiana, for $1.6 billion. In January 2007, Anadarko signed two separate unrelated agreements to sell its interests in the Williston basin, Elk basin and Gooseberry area of the Northern Rockies for a total of $810 million, as well as an agreement to divest control of Anadarko’s interests in 28 Permian basin oil fields in West Texas for $1 billion. Certain of these transactions have closed and the remaining transactions are expected to close in the first half of 2007.

In February 2007, Anadarko signed an agreement to sell its interests in certain natural gas properties in Oklahoma and Texas for $860 million. This agreement is expected to close during the second quarter of 2007. During February, Anadarko also closed on the sale of its Genghis Khan discovery in the deepwater Gulf of Mexico for $1.33 billion. Anadarko will use net proceeds from all of these sales to further reduce debt under the acquisition facility.

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. 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.

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.

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

MMBOE	2006		2005		2004
Proved Reserves
Beginning of year	2,449		2,367		2,513
Reserve additions and revisions	1,043		291		335
Sales in place	(287	)	(51	)	(290	)
Production	(194	)	(158	)	(191	)
End of year	3,011		2,449		2,367
Proved Developed Reserves
Beginning of year	1,524		1,517		1,727
End of year	1,989		1,524		1,517

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The Company’s proved natural gas reserves at year-end 2006 were 10.5 Tcf compared to 7.9 Tcf at year-end 2005 and 7.5 Tcf at year-end 2004. Anadarko’s proved crude oil, condensate and NGLs reserves at year-end 2006 were 1.3 billion barrels compared to 1.1 billion barrels at the end of both 2005 and 2004. Crude oil, condensate and NGLs comprised about 42%, 46% and 47% of the Company’s proved reserves at year-end 2006, 2005 and 2004, respectively.

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

Reserve Additions and Revisions  During 2006, the Company added 1,043 MMBOE of proved reserves as a result of additions (purchases in place, discoveries, improved recovery and extensions) and revisions.

Additions  During 2006, Anadarko added 1,278 MMBOE of proved reserves. Of this amount, 1,030 MMBOE were related to purchases in place primarily associated with the acquisitions of Kerr-McGee and Western. In addition, the Company added 248 MMBOE of proved reserves primarily as a result of successful drilling in core areas onshore in the United States. 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 through successful drilling in its North American properties and the deepwater Gulf of Mexico, successful improved recovery operations in Wyoming and minor producing property acquisitions.

The Company expects the majority of future reserve additions to come from infill drilling and extensions of current fields and new discoveries onshore in North America and the deepwaters of the Gulf of Mexico, as well as through improved recovery operations, purchases of proved properties in strategic areas and successful exploration in international growth areas. The success of these operations will directly impact reserve additions or revisions in the future.

Revisions Total revisions in 2006 were (235) MMBOE or 9.6% of the beginning of year reserve base. Performance revisions of (136) MMBOE were related primarily to downward revisions of the Company’s reserves at the K2 complex in the Gulf of Mexico and adjustments in Algeria. Price revisions in 2006 of (99) MMBOE were primarily due to a significant decrease in natural gas prices since the end of 2005. Total revisions for 2005 and 2004 were (23) MMBOE and (54) MMBOE, respectively. Revisions in 2005 related primarily to 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. 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.

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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 1997 - 2006, Anadarko’s annual reserve revisions, up or down, have been below 10% of the previous year-end proved reserve base for both types of revisions. In the aggregate, over the past decade, the average reserve revision has been a negative 1.8% and the average performance-related reserve revision has been a negative 1.1%.

STAT TAB LE FOR GRAPH ON PAGE 42
History of Reserve Revisions
	Performance		Price
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	%
2006	-5.6	%	-4.0	%
	Total		Excluding Price
10-Year Average	-1.8	%	-1.1	%
% of Previous Year-End Reserve Base
-20 -15 -10 -5 0 5 10 15 20

Sales in Place  In 2006, the Company sold properties located in Canada representing 248 MMBOE of proved reserves, respectively. In addition, sales in place included 39 MMBOE of proved reserves related to government imposed contract changes which resulted in the Company’s Venezuelan properties being exchanged for an equity interest in a new Venezuela operating entity. In 2005, Anadarko 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 in the United States and Canada representing 226 MMBOE and 64 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. About 37% of the Company’s PUDs booked prior to 2004 are in Algeria and are being developed according to an Algerian government approved plan. The remaining PUDs booked prior to 2004 are primarily associated with Alaska and ongoing programs in the onshore United States for improved recovery.

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The following data presents the Company’s PUDs vintage, geographic location and percentage of total proved reserves as of December 31, 2006:

STAT TABLE FOR GRAPH ON PAGE 43
Worldwide Proved Undeveloped Reserves
Years from Initial Booking	PUDs	(MMBOE)	Cumulative	% of PUDs
0	595		58	%
1	87		67	%
2	73		74	%
3	132		87	%
4	9		88	%
5+	126		100	%
0 100 200 300 400 500 600 0% 25% 50% 75% 100%

Worldwide Proved Undeveloped Reserves Analysis

Country	PUDs (MMBOE)	Percentage of Total PUDs	Percentage of Total Proved Reserves
United States	897	88%	30%
Algeria	111	11%	4%
Other International	14	1%	—%
Total	1,022	100%	34%

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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 record in converting PUDs to developed reserves over the periods shown.

STAT TABLE FOR GRAPH ON PAGE 44 (TOP OF PAGE)
Worldwide Proved Undeveloped Reserves
PUD Reserves by Year PUD Booked
Year PUD Booked	PUDs	(MMBOE)
2006					595
2005				295	87
2004			310	208	73
2003	328		221	191	132
2002	100		64	46	9
2001	184		132	94	64
pre-2001	174		123	91	62
	2003		2004	2005	2006
	End of Year
totals	786		850	925	1022
0 200 400 600 800 1000 1200

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 18%. 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 increase in proved reserves and production in 2006 is primarily related to the third quarter acquisitions of Kerr-McGee and Western. The decrease in proved reserves in 2004 and production in 2005 is primarily related to properties sold in 2004.

STAT TABLE FOR GRAPH ON PAGE 44 (BOTTOM OF PAGE)
	Reserves converted to production
	Proved Reserves	(MMBOE)	Produced	(MBOE/d)
1996	601		104
1997	708		120
1998	935		129
1999	991		135
2000	2061		306
2001	2305		546
2002	2328		539
2003	2513		525
2004	2367		520
2005	2449		434
2006	3011		531
	Reserves		Production
CAGR	17	%	18	%
0 500 1000 1500 2000 2500 3000 3500
0 100 200 300 400 500 600 700

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Future Net Cash Flows  At December 31, 2006, the present value (discounted at 10%) of future net cash flows from Anadarko’s proved reserves was $25.6 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 decrease of $3.7 billion or 12% in 2006 compared to 2005 is primarily due to a significant decrease in natural gas prices and the sale of Canadian operations, partially offset by increases associated with the Kerr-McGee and Western acquisitions. SeeSupplemental Informationunder 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.

Gathering, Processing and Marketing Strategies

Overview  Anadarko supports and seeks to enhance the value of its oil and gas operations through its GPM activities. These activities provide for the gathering, processing, transportation and ultimate sale of the Company’s production. In addition, the GPM function provides services for third-party customers.

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

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

Marketing  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. In 2006, the Company also engaged in sales of greenhouse gas emission reduction credits (ERCs) derived from CO₂injection operations in Wyoming. The Company expects additional sales of ERCs in the future.

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, fully utilize transportation capacity, 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. The Company does not engage in market-making practices and limits its trading activities to oil, gas and NGL commodity contracts. The Company’s trading risk position, typically, is a net short position that is offset by the Company’s natural long position as a producer. SeeEnergy Price Riskunder Item 7a of this Form 10-K.

In an effort to protect the Company from commodity price risk stemming from the acquisitions of Kerr-McGee and Western, the Company has derivatives in place covering 72% and 55% of the acquired companies’ expected volumes on a BOE basis for 2007 and 2008, respectively. This price risk management program employs the use of three-way collars, along with certain other derivatives, intended to help ensure a return on investment while maintaining upside potential that could result from higher commodity prices.

In recent years, 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

45

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. While natural gas prices have fallen over the last year, price volatility persists due to a relatively tight supply and demand balance. Anadarko markets its natural gas production to maximize the commodity value and reduce the inherent risks of the physical commodity markets. Anadarko Energy Services Company (AESC), 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.

The Company owns a significant amount of natural gas firm transportation capacity which is used to ensure access to downstream markets and provides the opportunity to capture incremental value when pricing differentials between physical locations occur. The Company also stores some of its purchased natural gas in contracted storage facilities with the intent of selling the gas at a higher price in the future. Normally, the Company has forward contracts in place (physical delivery or financial derivative instruments) to sell the stored gas at a fixed price.

In 2005 and 2004, approximately 9% and 15%, respectively, of the Company’s gas production was sold under long-term contracts to Duke Energy Corporation (Duke). These sales represent 4% and 7% of total revenues related to continuing operations in 2005 and 2004, respectively. As these contracts expired, the Company integrated the marketing of the natural gas previously sold to Duke into its marketing operations and sells it to various purchasers at market prices. At the end of 2006, there were no volumes remaining under the original long-term contract with Duke. Volumes sold to Duke under the long-term contracts were at market prices.

Western and Kerr-McGee both have gas marketing organizations that are being incorporated into AESC. Kerr-McGee has a long-term gas sales contract with Cinergy (since acquired by Fortis). In 2006, approximately 50% of gas volumes and revenues associated with the Kerr-McGee acquisition were sold under this legacy contract. This contract is expected to be terminated in March 2007, with the associated volumes being integrated into the Company’s marketing operations.

Crude Oil, Condensate and NGLs  Anadarko’s crude oil, condensate and NGLs revenues are derived from production in the U.S., 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. Oil from Algeria is sold by tanker as Saharan Blend to customers primarily in the Mediterranean area. Saharan Blend is a high quality crude that provides refiners large quantities of premium products like jet and diesel fuel. Oil from China is sold by tanker as Cao Fei Dian (CFD Blend) to customers primarily in the Far East markets. CFD Blend is a heavy sour crude oil which is sold into both the prime fuels refining market and the heavy fuel oil blend stock market. The Company also purchases and sells third-party produced crude oil, condensate and NGLs in the Company’s domestic and international market areas. Included in this strategy is the use of contracted NGLs storage facilities and various derivative instruments.

Capital Resources and Liquidity

Overview  Anadarko’s primary sources of cash during 2006 were the issuance of debt, cash flow from operating activities and divestitures. The Company used cash primarily to fund the acquisitions of Kerr-McGee and Western, to fund its capital spending program, repurchase Anadarko common stock, pay dividends and retire debt as well as preferred stock. Anadarko’s primary source of cash during 2005 was cash flow from operating activities. The Company used 2005 cash flow primarily to fund its capital spending program, repurchase

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Anadarko common stock and pay dividends. In addition, the Company used $170 million of cash from the 2004 divestitures to retire debt in 2005. 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. The Company funded its capital investment programs in 2004 primarily through cash flow from operating activities.

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

Debt  At year-end 2006, Anadarko’s total debt was $23.0 billion compared to total debt of $3.6 billion at year-end 2005 and $3.8 billion at year-end 2004. In August 2006, the Company financed $22.5 billion under a 364-day acquisition facility in order to fund the Kerr-McGee and Western acquisitions and repay a portion of the debt assumed with the acquisitions. The variable-rate facility is based on London Interbank Offered Rate (LIBOR) and had a weighted-average interest rate of approximately 5.80% at December 31, 2006. As of December 31, 2006, the Company has refinanced approximately $6 billion of the acquisition facility with new long-term issuances (discussed below) and repaid $5.5 billion with divestiture proceeds and cash flow from operations. An aggregate principal amount of $2.1 billion of debt assumed in the Kerr-McGee acquisition remains outstanding as of December 31, 2006.

In September 2006, the Company issued $5.5 billion senior notes including floating rate notes due 2009, 5.95% notes due 2016, and 6.45% notes due 2036. The net proceeds were used to repay a portion of the acquisition facility. The floating rate notes due 2009 had an average interest rate of approximately 5.76% at December 31, 2006.

In October 2006, the Company received $500 million of proceeds from a private offering of Zero Coupon Senior Notes due 2036. The notes were issued with a yield to maturity of 5.24% and the holders have an option to put the notes back to the Company periodically. The net proceeds from the private offering were used to repay a portion of the acquisition facility.

The Company had $182 million of commercial paper outstanding at December 31, 2006. During 2006, the Company redeemed for cash an aggregate principal amount of $122 million of debt that was outstanding as of December 31, 2005. Of this amount, $80 million was related to continuing operations. For additional information on the Company’s debt instruments, such as transactions during the period, years of maturity and interest rates, seeNote 8 — Debt and Interest Expenseof theNotes to Consolidated Financial Statementsunder Item 8 of this Form 10-K.

Cash Flow from Operating Activities  Anadarko’s cash flow from continuing operating activities in 2006 was $5.0 billion compared to $3.5 billion in 2005 and $2.7 billion in 2004. The increase in 2006 cash flow was attributed to the impact of the acquisitions and higher commodity prices, partially offset by higher costs and expenses and slightly lower legacy sales volumes. The increase in 2005 cash flow compared to 2004 was attributed to higher net realized commodity prices, partially offset by lower sales volumes resulting from the 2004 divestitures.

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

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

millions	2006			2005			2004
Property acquisitions
Development — proved	$	14,496		$	44		$	(1	)
Exploration — unproved		13,379			229			135
Development		3,079			1,959			1,919
Exploration		903			588			387
Total oil and gas costs incurred*		31,857			2,820			2,440
Less: Corporate acquisitions		(27,491	)		—			—
Less: Asset retirement costs		(158	)		(29	)		(47	)
Plus: Asset retirement expenditures		25			25			24
Total oil and gas capital expenditures*		4,233			2,816			2,417
Gathering, processing and marketing and other		361			127			93
Total	$	4,594		$	2,943		$	2,510

* 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 56% in 2006 compared to 2005. The Company’s capital spending increased 17% in 2005 compared to 2004. The increase in 2006 resulted primarily from an increase in exploration lease acquisitions, offshore drilling completions, development of the CBM infrastructure and capital expenditures of the acquired companies. 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 2006 relate primarily to Kerr-McGee and Western. The acquisitions in 2005 and 2004 primarily relate to exploratory nonproducing leases.

Anadarko participated in a total of 1,537 gross wells in 2006 compared to 688 gross wells in 2005 and 793 gross wells in 2004.

The following table provides additional detail of the Company’s drilling activity in 2006 and 2005.

	Gas	Oil	Dry	Total
2006 Exploratory
Gross	56	7	13	76
Net	34.6	3.6	5.7	43.9
2006 Development
Gross	1,183	272	6	1,461
Net	631.6	205.6	2.2	839.4
2005 Exploratory
Gross	15	6	6	27
Net	8.0	3.8	3.5	15.3
2005 Development
Gross	516	143	2	661
Net	290.8	93.5	1.2	385.5

Gross: total wells in which there was participation.

Net: working interest ownership.

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The Company’s 2006 exploration and development drilling program is discussed inOil and Gas Properties and Activitiesunder Item 1 of this Form 10-K.

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 2005. Shares may be repurchased either in the open market or through privately negotiated transactions. During 2006 and 2005, Anadarko purchased 2.5 million and 21.6 million shares of common stock for $0.1 billion and $0.9 billion, respectively, under these programs. The repurchase program does not obligate Anadarko to acquire any specific number of shares and may be discontinued at any time. At December 31, 2006, $636 million remained available for stock repurchases under the program authorized in 2005.

Dividends  In 2006, Anadarko paid $167 million in dividends to its common stockholders (nine cents per share per quarter). In 2005, Anadarko paid $170 million in dividends to its common stockholders (nine cents per share per quarter). In 2004, Anadarko paid $139 million in dividends to its common stockholders (seven cents per share per quarter). Anadarko has paid a dividend to its common stockholders continuously since becoming an independent company in 1986. The amount of future dividends for Anadarko common stock will depend on earnings, financial conditions, capital requirements and other factors, and will be determined by the Board of Directors on a quarterly basis.

The covenants in the Company’s credit agreement provide for a maximum capitalization ratio of 75% debt, exclusive of the effect of any noncash writedowns, until September 30, 2007. After September 30, 2007, the maximum capitalization ratio is 60% debt. As of December 31, 2006, Anadarko’s capitalization ratio was 61%.

The Company amended the credit agreement prior to closing the acquisitions to allow for a higher maximum capitalization ratio covenant to allow the Company to pay dividends consistent with past practices. Although the covenants of the agreement do not specifically restrict the payment of dividends, the Company could be limited in the amount of dividends it could pay in order to stay below the maximum capitalization ratio. Based on these covenants, retained earnings of approximately $7.6 billion were not limited as to the payment of dividends.

In 2006, Anadarko also paid $3 million in preferred stock dividends. In 2005 and 2004, the Company paid $5 million in preferred stock dividends. In 2007 preferred stock dividends are expected to be $3 million.

Outlook  The Company’s goals include continuing to find or acquire high-margin oil and gas reserves at competitive prices while keeping operating costs at efficient levels. Anadarko completed the acquisitions of Kerr-McGee and Western in August 2006 in two separate all-cash transactions. These transactions required $22.5 billion of capital which was funded through a 364-day acquisition facility that matures in August 2007. The Company announced its intention to repay the borrowings under the acquisition facility with proceeds from asset sales, free cash flow from operations and the potential issuances of equity, debt and bank financing. Anadarko intends to reduce leverage significantly during 2007.

In 2006, the Company repaid approximately $1 billion of borrowings with the proceeds received from the sale of the former Kerr-McGee Gulf of Mexico shelf properties. In addition, the Company issued $5.5 billion of senior notes in the public market in 2006 and also received $500 million from a private offering of senior notes in 2006, with proceeds from both debt issuances applied to the repayment of the acquisition facility. The Company also closed the sale of its wholly-owned subsidiary, Anadarko Canada Corporation, for approximately $4.3 billion pretax and further reduced the borrowings under the facility with after-tax proceeds. As of December 31, 2006, Anadarko had an aggregate principal amount of approximately $11 billion outstanding under the acquisition facility, which matures in August 2007.

Anadarko has signed several additional separate and unrelated agreements with various companies for the divestiture of certain non-core properties in the Gulf of Mexico and onshore in the United States for a combined total of approximately $6.5 billion before income taxes. Certain of these agreements have closed and the remaining are expected to close in the first half of 2007.

The Company expects total after-tax proceeds from the Canadian sale and the other transactions mentioned above to be about $9 billion. The Company expects to divest certain other assets by the end of 2007, with

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expected incremental after-tax proceeds totaling between $2 billion and $6 billion. The proceeds from all of these transactions are being used to reduce indebtedness.

After the sales are complete, the Company expects proved reserves of the new Anadarko will be about 2.5 billion BOE, only slightly higher than at the beginning of 2006. The goal of the Kerr-McGee and Western acquisitions was to provide for a more economically efficient platform with higher and more consistent growth potential. The new portfolio is expected to be better balanced, with lower-risk U.S. onshore resource plays that help smooth out the volatility inherent in its deepwater Gulf of Mexico and international programs. The Company believes the acquisitions and subsequent portfolio restructuring will have the following key benefits:

• A lower-risk, more efficient portfolio of core producing properties;

• A large and high-quality portfolio, which should result in more consistent and predictable reserve and production performance;

• An expanded leasehold position, which provides access to exploration opportunities worldwide;

• A substantial inventory of identified prospects, which will help deliver value from the exploratory drilling program over many years to come; and

• Expanded technical capabilities, combining the exploration, development, project management and operational skill sets of all three companies.

The Company currently expects 2007 capital spending to be approximately $4.2 billion. The Company has allocated about 69% capital spending to development activities, 16% to exploration activities, 12% to gas gathering and processing activities and the remaining 3% for capitalized interest, overhead and other items. The Company’s capital discipline strategy is to set capital activity at levels that are self-funding. Anadarko believes that its expected level of cash flow, and continued adherence to its capital discipline strategy, will be sufficient to fund the Company’s projected operational program for 2007.

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 various noncommitted credit lines that may be offered by certain banks from time to time at then-quoted rates. As of December 31, 2006, 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 supported 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 sell securities off its shelf registration statement filed 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.

For additional information on factors that could impact Anadarko’s future results of operations, cash flows from operating activities or financial position seeRisk Factors under Item 1a of this Form 10-K.

Other Developments

Algeria  Anadarko’s operations in Algeria have been governed by an Agreement for Exploration and Exploitation of Liquid Hydrocarbons (PSC) that Anadarko Algeria Corporation entered into in October 1989 with Sonatrach, the national oil company of Algeria. In March 2006, Anadarko received from Sonatrach a letter purporting to give notice under the PSC that enactment of law relating to hydrocarbons triggered Sonatrach’s right under the PSC to renegotiate the PSC in order to re-establish the equilibrium of Anadarko’s and Sonatrach’s interests. Anadarko and Sonatrach reached an impasse over whether Sonatrach has a right to renegotiate the PSC based on this new law and have entered into a formal non-binding conciliation process under the terms of the PSC to try to resolve this dispute. At this time, Anadarko is unable to reasonably estimate what the economic impact under the PSC might be if Sonatrach is successful in modifying the PSC.

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In July 2006, the Algerian parliament approved legislation establishing an exceptional profits tax on foreign companies’ Algerian oil and gas production. The legislation provides that an exceptional profits tax ranges from 5% to 50% on exceptional profits whenever the monthly price of Brent crude averages over $30 per barrel, applied retroactively to production from August 1, 2006. The July 2006 legislation did not specify all the aspects necessary to quantify the tax liability, but indicated that regulations clarifying the determination of the tax would be issued in the future. In December 2006, implementing regulations were issued and Sonatrach notified the Company as to the applicable regulatory provisions. The applicable regulatory provisions provide that exceptional profits tax is imposed on gross production at rates of taxation ranging from 5% to 50% based on average daily production volumes for each calendar month. Uncertainty exists as to whether the exceptional profits tax will apply to the full value of production or only to the value of production in excess of $30 per barrel.

In the fourth quarter of 2006, the Company recorded a $103 million liability for exceptional profits tax, with associated expense reflected in other taxes in the consolidated statement of income. This amount represents the Company’s estimate of its liability for exceptional profits tax from the law’s August 1, 2006 effective date through year-end 2006, based on the assumption that the tax applies only to production value in excess of $30 per barrel. If the exceptional profits tax is applied to the full value of production, the Company’s estimated 2006 liability for exceptional profits tax would be $190 million. The Company is not yet in a position to confirm the probable interpretation of the law, but is continuing to monitor further guidance to determine the law’s ultimate application to the Company.

For 2007, assuming an average oil price of $60 per barrel and application of the exceptional profits tax to production value in excess of $30 per barrel, Anadarko’s estimated annual production tax expense for the exceptional profits tax would be $225 million. If the exceptional profits tax is applied to the full value of production rather than to the value in excess of $30 per barrel, the estimated annual expense would double. Sonatrach has notified the Company that it will begin collecting current and past exceptional profits tax in March 2007, by retaining 85% of the barrels to which Anadarko is entitled until the Company’s current and prior period liability for exceptional profits tax has been satisfied.

Anadarko currently has 111 million barrels of proved undeveloped reserves in Algeria, the economics of which are sensitive to the exceptional profits tax. Anadarko is reviewing whether these reserves remain economic under existing development plans if the exceptional profits tax is applied to the entire production value. Assuming that the exceptional profits tax applies to the full value of production and this 111 million barrels of existing proved undeveloped Algerian reserves would then become uneconomic, based on the Company’s analysis, no full-cost ceiling test impairment would have been required at December 31, 2006.

In response to the Algerian government’s imposition of the exceptional profits tax, the Company has notified Sonatrach of its disagreement with the proposed collection of the exceptional profits tax. The Company believes that the PSC provides fiscal stability through several of its provisions. At this time, the Company cannot determine the ultimate outcome of any possible negotiations or any potential recourse to conciliation or arbitration by either side.

Venezuela  Anadarko’s operations in Venezuela have been governed by an Operating Service Agreement (OSA) that was entered into in November 1993 with 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 through a Venezuelan joint venture in which Petrobras acted as operator. In 2005, the Venezuelan Ministry of Energy and Petroleum announced that all OSAs concluded by PDVSA between 1992 and 1997 were subject to renegotiation. As a result, in October 2006, the OSA was converted into a new operating company, Petroritupano S.A. An affiliate of PDVSA, Corporación Venezolana del Petróleo, S.A. (CVP), and PDVSA have a 60% interest, Petrobras has a 22% interest, and Anadarko has an 18% interest in the new company. In October 2006, Anadarko, CVP and Petrobras executed the relevant contracts creating the aforementioned interests in the new company. The OSA terminated automatically with the creation of Petroritupano S.A.

For the year ended 2006, Anadarko 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) and approximately $4 million of interest and penalties related to SENIAT’s tax assessment.

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With the termination of the OSA in exchange for an 18% interest in the new company, Anadarko began accounting for its interest in the new company using the equity method in the fourth quarter 2006. As a result of this exchange, Anadarko recorded a loss of $178 million in the fourth quarter of 2006.

With respect to these assets, Anadarko is currently analyzing its options, including a possible sale. As of December 31, 2006, less than 1% of Anadarko’s total assets were associated with operations located in Venezuela.

Discontinued Operations

In November 2006, Anadarko sold its wholly-owned subsidiary, Anadarko Canada Corporation, for approximately $4.3 billion before income taxes. Accordingly, the Canadian oil and gas operations have been classified as discontinued operations in the consolidated statements of income and cash flows and the associated assets and liabilities have been classified as held for sale in the consolidated balance sheets. As of September 30, 2006, operations in Canada had represented approximately 6% of Anadarko’s total assets and 9% of third quarter 2006 sales volumes. The following table summarizes selected data pertaining to discontinued operations.

millions except per share amounts	2006			2005		2004
Revenues	$	717		$	913	$	955
Income from discontinued operations	$	330		$	490	$	377
Gain on disposition of discontinued operations		2,263			—		—
Income from discontinued operations before income taxes		2,593			490		377
Income tax expense		535			92		72
Income from discontinued operations, net of taxes	$	2,058		$	398	$	305
Earnings per common share from discontinued operations — diluted	$	4.44		$	0.84	$	0.60
Annual sales volumes (MMBOE)		17			20		29
Cash flow provided by (used in) operating activities	$	(139	)	$	644	$	464
Capital expenditures	$	588		$	494	$	580

Income from discontinued operations, net of tax, for 2006 increased 417% compared to the same period of 2005 primarily due to the gain on the sale of Canadian operations, a decrease in Canadian tax rates and higher oil prices, partially offset by an increase in Canadian taxes associated with the gain on sale and a decrease in recognized sales volumes as a result of the November 2006 sale. Income tax expense for 2006 includes a $79 million decrease related to Canadian tax rate changes.

Income from discontinued operations, net of tax, for 2005 increased 30% compared to the same period of 2004 primarily due to significantly higher commodity prices, partially offset by decreases in sales volumes and costs and expenses associated with Canadian properties sold in late 2004.

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

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Obligations and Commitments

Following is a summary of the Company’s obligations as of December 31, 2006:

	Obligations by Period
millions	1 Year		2-3 Years		4-5 Years		Later Years		Total
Total debt
Principal	$	11,475	$	2,449	$	1,625	$	9,284	$	24,833
Interest		1,111		1,367		1,120		8,255		11,853
Operating leases
Drilling rig commitments		1,126		2,456		712		105		4,399
Production platforms		85		156		123		408		772
Other		86		137		83		38		344
Asset retirement obligations		37		61		55		897		1,050
Gathering, processing and marketing activities		211		312		206		293		1,022
Oil and gas activities		—		316		146		48		510

Operating Leases  Operating lease obligations include several drilling rig commitments that qualify as operating leases. During 2006 and 2005, Anadarko entered into various agreements to secure the necessary drilling rigs to execute its drilling strategy over 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. Lease payments for these drilling rig commitments, net of amounts billed to partners, will be capitalized as a component of oil and gas properties.

The Company also has $1.1 billion in commitments under noncancelable operating lease agreements for production platforms and equipment, buildings, facilities and aircraft.

For additional information seeNote 20 — Commitmentsof theNotes to Consolidated Financial Statementsunder Item 8 of this Form 10-K.

Gathering, Processing and Marketing Activities  Anadarko has entered into various transportation, storage and purchase agreements in order to access markets and provide flexibility for the sale of its natural gas and crude oil in certain areas. The above table includes amounts related to these commitments. During 2006, the precedent agreements the Company had entered to secure transportation of natural gas upon completion of its Bear Head LNG facility were terminated.

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 2007 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 $510 million, comprised of $335 million in the United States, $16 million in Algeria and $159 million in other international locations. The Company also routinely enters into short-term commitments, which are included in the Company’s 2007 capital budget of $4.2 billion; therefore, these commitments are not included in the preceding table.

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Marketing and Trading Contracts  The following tables provide information as of December 31, 2006 regarding the Company’s marketing and trading portfolio of physical delivery and financially settled derivative instruments. The other changes in fair value in the table below relate primarily to contracts assumed in the 2006 acquisitions. SeeCritical Accounting Policies and Estimates for an explanation of how the fair value for derivatives is calculated.

millions	Marketing and Trading
Fair value of contracts outstanding as of December 31, 2005 — assets (liabilities)	$	3
Contracts realized or otherwise settled during 2006		(2	)
Fair value of new contracts when entered into during 2006		2
Other changes in fair value		56
Fair value of contracts outstanding as of December 31, 2006 — assets (liabilities)	$	59

	Fair Value of Contracts as of December 31, 2006
Assets (Liabilities) millions	Maturity less than 1 Year		Maturity 1-3 Years		Maturity 4-5 Years		Maturity in excess of 5 Years		Total
Marketing and Trading
Prices actively quoted	$	57	$	2	$	—	$	—	$	59

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 price risk management position and price volatility, the Company may be required from time to time to advance cash to its counterparties in order to satisfy these margin deposit requirements. During 2006, the Company’s margin deposit requirements have ranged from zero to $64 million. The Company had margin deposits of $31 million outstanding at December 31, 2006.

Other  In 2006, including discontinued operations, the Company made contributions of $59 million to its funded pension plans, $86 million to its unfunded pension plans and $14 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 2007, the Company expects to contribute $13 million to its funded pension plans, $50 million to its unfunded pension plans and $21 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 2007 for the pension plans; however, they are expected to be at levels similar to those made in 2006. The Company expects future payments for other postretirement benefit plans to increase above those made in 2006 due to the assumption of Kerr-McGee’s plans in August 2006.

Anadarko is also subject to various environmental remediation and reclamation obligations arising from federal, state and local laws and regulations. As of December 31, 2006, the Company’s balance sheet included an $87 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, seeNote 8 — Debt and Interest Expense, Note 9 — Financial Instruments, Note 10 — Sale of Future Hard Minerals Royalty Revenues, Note 11 — Asset Retirement Obligations, Note 21 — Pension Plans, Other Postretirement Benefits and Employee Savings Plans andNote 22 — Contingenciesof theNotes to Consolidated Financial Statementsunder 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 determination of proved reserves, litigation, environmental liabilities, income taxes and fair values. In 2006, significant estimates were also involved in accounting for business combinations. 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.

Business Combinations  Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities of the acquired business and recording deferred taxes for any differences between the allocated values and tax basis of assets and liabilities. Any excess of the purchase price over the amounts assigned to assets and liabilities is recorded as goodwill. In connection with Anadarko’s August 2006 acquisitions of Kerr-McGee and Western, the Company recorded goodwill for the excess of the purchase price over the value assigned to individual assets acquired and liabilities assumed. The Company’s fair value estimates for the 2006 acquisitions are subject to change as additional information becomes available and is assessed by Anadarko.

Purchase Price Allocation  The purchase price allocation is accomplished by recording the asset or liability at its estimated fair value. Anadarko uses all available information to make these fair value determinations, including information commonly considered by the Company’s engineers in valuing individual oil and gas properties and sales prices for similar assets. Estimated deferred taxes are based on available information concerning the tax basis of the acquired company’s assets and liabilities and carryforwards at the merger date, although such estimates may change in the future as additional information becomes known. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed relative to the total acquisition cost.

Goodwill  The Company is required to assess goodwill for impairment annually, or more often as circumstances warrant. The first step of that process is to compare the fair value of the reporting unit to which goodwill has been assigned to the carrying amount of the associated net assets and goodwill. If the estimated fair value is greater than the carrying amount of the reporting unit, then no impairment loss is required. The Company completed its most recent annual goodwill impairment test, with no impairment indicated. Although Anadarko cannot predict when or if goodwill will be impaired in the future, impairment charges may occur if we are unable to replace the value of our depleting asset base or if other adverse events (for example, lower sustained oil and gas prices) reduce the fair value of the associated reporting unit.

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 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.

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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.

Management is currently assessing the potential effects of converting from the full cost method to the successful efforts method of accounting for oil and gas activities. Should the Company decide to change accounting methods, financial statements for prior periods will be restated to reflect the results and balances that would have been reported had it been following the successful efforts method of accounting.

Asset Retirement Obligation  The initial estimated retirement obligation of properties is recognized as a liability, with an associated increase in properties and equipment. Accretion expense is recognized over the estimated productive life of the related assets. 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. Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations.

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.

Significant properties are individually evaluated 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 aggregated and 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 specific exclusions, 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.

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The Company’s derivative instruments are either exchange traded or transacted in an over-the-counter market. Valuation is determined by reference to readily available public data. Option fair values are based on the Black-Scholes option pricing model and verified against the applicable counterparty’s fair values.

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 earnings volatility. Through the end of 2006, Anadarko applied hedge accounting to some of its commodity derivatives. Derivative accounting rules are complex, subject to interpretation in their application and interpretative guidance continues to evolve. As a result of this accounting risk, effective January 1, 2007, Anadarko discontinued hedge accounting on all existing commodity and interest rate derivatives. Such a change will not affect Anadarko’s reported financial position or cash flows and will not require adjustments to previously reported financial statements.

Benefit Plan Obligations  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. Determination of the projected benefit obligations for the Company’s defined benefit pension and postretirement plans is important to the recorded amounts for such obligations on the balance sheet and to the amount of benefit expense in the income statement. This also impacts the Company’s decisions for amounts contributed into the plans.

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

Discount rate  The discount rate assumption used by the Company is meant to reflect the interest rate at which the pension and other postretirement obligations could effectively be settled on the measurement date. The Company currently uses a yield curve analysis, for a majority of the plans, to support the discount rate assumption. This analysis involves the creation of a hypothetical Aa spot yield curve represented by a series of high-quality, non-callable, marketable bonds, then discounts the projected cash flows from each plan at interest rates on the created curve specifically applicable to the timing of each respective cash flow. The present values of the cash flows are then accumulated, and a weighted-average discount rate is calculated by imputing the single discount rate that equates to the total present value of the cash flows. The consolidated discount rate assumption is determined by evaluation of the weighted-average discount rates determined for each of the Company’s significant pension and postretirement plans. The weighted-average discount rate assumption used by the Company as of December 31, 2006 was 5.75%.

Expected long-term rate of return  The expected long-term rate of return on assets assumption was determined using the year-end 2006 pension investment balances by category and projected target asset allocations for 2007. 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 weighted-average expected long-term rate of return on plan assets assumption used by the Company as of December 31, 2006 was 7.75%.

Rate of compensation increases  The Company determines this assumption based on its long-term plans for compensation increases specific to employee groups covered and expected economic conditions. The assumed rate of salary increases includes the effects of merit increases, promotions and general inflation. The weighted-average rate of increase in long-term compensation levels assumption used by the Company as of December 31, 2006 was 5.0%.

Health care cost trend rate The health care cost trend assumptions are developed based on historical cost data, the near-term outlook and an assessment of likely long-term trends. For year-end 2006 measurement purposes, the Company used separate assumptions of cost increase rates for medical, prescription drugs and dental benefits

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covered by the plans. An 8% annual rate of increase in the per capita cost of covered medical benefits was assumed for 2006, decreasing gradually to 5% in 2015 and later years. For prescription drug benefits, a rate of increase of 13% in the per capita cost was assumed for 2006, decreasing gradually to 5% in 2015 and later years. For dental care costs, the Company assumed a flat rate of increase of 5%.

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

Income Taxes  The amount of income taxes recorded by the Company requires the interpretation of complex rules and regulations of various taxing jurisdictions throughout the world. The Company has recognized deferred tax assets and liabilities for 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.

Recent Accounting Developments

New Accounting Principles  Financial Accounting Standards Board Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109,” was issued in 2006 and became effective January 1, 2007 for Anadarko. FIN 48 defines the criteria an individual tax position must meet for any part of the benefit of that position to be recognized in the financial statements. FIN 48 also provides guidance, among other things, on the measurement of the income tax benefit associated with uncertain tax positions, de-recognition, classification, interest and penalties and financial statement disclosures. In light of the acquisitions of Kerr-McGee and Western in 2006, the Company is currently evaluating the potential effects of adopting FIN 48 on its financial statements. The Company cannot reasonably determine the impact of FIN 48 on its financial statements at this time, but will complete its analysis during the first quarter of 2007.

In September 2006, the FASB issued Statement of Financial Accounting Standard (SFAS) No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosure requirements for fair value measurements. SFAS No. 157 does not require new fair value measurements. Rather, its provisions will apply when fair value measurements are performed under other accounting pronouncements. SFAS No. 157 is effective for Anadarko in the first quarter of 2008. The Company is currently evaluating the effects of adoption on its financial statements.

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Item 7a.  Quantitative and Qualitative Disclosures About Market Risk

The Company’s primary market risks are fluctuations in energy prices and interest rates. These fluctuations can affect revenues and 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, seeNote 1 — Summary of Significant Accounting Policies, Note 8 — DebtandNote 9 — Financial Instrumentsof theNotes to Consolidated Financial Statementsunder Item 8 of this Form 10-K.

Energy Price Risk  The Company’s most significant market risk is the pricing for natural gas, crude oil and NGLs. Management expects energy prices to remain volatile and unpredictable. If energy prices decline significantly, revenues and cash flow would significantly decline. In addition, a 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 450 Bcf of natural gas and 87 MMBbls of crude oil as of December 31, 2006 (excluding physical delivery fixed price contracts not accounted for as derivative instruments). As of December 31, 2006, the Company had a net unrealized gain of $35 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 $519 million. However, this loss would be substantially offset by an increase in the value of that portion of the Company’s production covered by the derivative instruments.

Derivative Instruments Held for Trading Purposes  As of December 31, 2006, the Company had a net unrealized gain of $59 million (gains of $143 million and losses of $84 million) on derivative financial instruments entered into for trading purposes. 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 $11 million.

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

Interest Rate Risk  As of December 31, 2006, Anadarko had outstanding $13.2 billion of variable-rate debt and $9.8 billion of fixed-rate debt. Excluding the impact of interest rate swaps in place, a 10% increase in LIBOR interest rates would increase gross interest expense approximately $76 million per year. Anadarko is a party to two interest rate swap agreements whereby the Company receives a fixed interest rate and pays a floating interest rate indexed to LIBOR. One swap, which was entered into during March 2006, has an initial term of 25 years and a notional amount of $600 million. The other swap expires in 2007 and has a notional amount of $150 million. These agreements were entered into to better balance the fixed-rate to floating-rate percentage of debt obligations. As of December 31, 2006, the Company had a net unrealized loss of $8 million on the fair value of these agreements. A 10% increase in LIBOR interest rates that were in effect on December 31, 2006, would result in an additional unrealized loss of approximately $40 million on these swaps.

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Item 8.  Financial Statements and Supplementary Data

ANADARKO PETROLEUM CORPORATION

INDEX

CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Management	61
Management’s Assessment of Internal Control Over Financial Reporting	61
Reports of Independent Registered Public Accounting Firm	62
Statements of Income, Three Years Ended December 31, 2006	65
Balance Sheets, December 31, 2006 and 2005	66
Statements of Stockholders’ Equity, Three Years Ended December 31, 2006	67
Statements of Comprehensive Income, Three Years Ended December 31, 2006	68
Statements of Cash Flows, Three Years Ended December 31, 2006	69
Notes to Consolidated Financial Statements	70
Supplemental Information on Oil and Gas Exploration and Production Activities	111
Supplemental Quarterly Information	126

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ANADARKO PETROLEUM CORPORATION

REPORT OF MANAGEMENT

Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this annual report. The consolidated financial statements present fairly the Company’s financial position, results of operations and cash flows in conformity with 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 the stockholders’ and Directors’ meetings.

MANAGEMENT’S ASSESSMENT OF INTERNAL CONTROL OVER FINANCIAL REPORTING

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

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

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006. This assessment was based on criteria established inInternal 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, 2006 the Company’s internal control over financial reporting is effective based on those criteria. Anadarko acquired Kerr-McGee and Western in August 2006 and excluded from the assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, Kerr-McGee’s internal control over financial reporting associated with total assets of $28,775 million and total revenues of $2,527 million and Western’s internal control over financial reporting associated with total assets of $8,488 million and total revenues of $653 million included in the consolidated financial statements of Anadarko as of and for the year ended December 31, 2006.

KPMG LLP has issued an audit report on our assessment of the Company’s internal control over financial reporting as of December 31, 2006.

/S/    JAMES T. HACKETT

James T. Hackett

Chairman, President and Chief Executive Officer

/S/    R.A. WALKER

R.A. Walker

Senior Vice President, Finance and

Chief Financial Officer

February 27, 2007

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Anadarko Petroleum Corporation:

We have audited management’s assessment, included in the accompanyingManagement’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, 2006, based on criteria established inInternal 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, 2006, is fairly stated, in all material respects, based on criteria established inInternal 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, 2006, based on criteria established inInternal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Anadarko Petroleum Corporation acquired Kerr-McGee Corporation and Western Gas Resources, Inc. during 2006, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, Kerr-McGee Corporation’s internal control over financial reporting associated with total assets of $28,775 million and total revenues of $2,527 million and Western Gas Resources, Inc.’s internal control over financial reporting associated with total assets of $8,488 million and total revenues of $653 million included in the consolidated financial statements of Anadarko Petroleum Corporation and

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subsidiaries as of and for the year ended December 31, 2006. Our audit of internal control over financial reporting of Anadarko Petroleum Corporation and subsidiaries also excluded an evaluation of the internal control over financial reporting of Kerr-McGee Corporation and Western Gas Resources, Inc.

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, 2006 and 2005, 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, 2006, and our report dated February 27, 2007 expressed an unqualified opinion on those consolidated financial statements.

/s/    KPMG LLP

Houston, Texas

February 27, 2007

63

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, 2006 and 2005, 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, 2006. 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 auditing 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, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for defined benefit pension and other postretirement plans in 2006.

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, 2006, based on criteria established inInternal Control-Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 27, 2007 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

/s/    KPMG LLP

Houston, Texas

February 27, 2007

64

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

	Years Ended December 31
	2006			2005			2004
millions except per share amounts
Revenues
Gas sales	$	4,186		$	2,968		$	2,583
Oil and condensate sales		4,601			2,703			2,022
Natural gas liquids sales		594			437			439
Gathering, processing and marketing sales		718			76			51
Other		88			3			29
Total		10,187			6,187			5,124
Costs and Expenses
Oil and gas operating		799			400			481
Oil and gas transportation and other		341			256			218
Gathering, processing and marketing		553			56			39
General and administrative		668			393			373
Depreciation, depletion and amortization		1,976			1,111			1,132
Other taxes		575			358			292
Impairments		388			78			72
Total		5,300			2,652			2,607
Operating Income		4,887			3,535			2,517
Interest Expense and Other (Income) Expense
Interest expense		655			206			358
Other (income) expense		(6	)		(76	)		59
Total		649			130			417
Income from Continuing Operations Before Income Taxes		4,238			3,405			2,100
Income Tax Expense		1,442			1,332			799
Income from Continuing Operations		2,796			2,073			1,301
Income from Discontinued Operations, net of taxes		2,058			398			305
Net Income	$	4,854		$	2,471		$	1,606
Preferred Stock Dividends		3			5			5
Net Income Available to Common Stockholders	$	4,851		$	2,466		$	1,601
Per Common Share
Income from Continuing Operations — basic	$	6.06		$	4.40		$	2.60
Income from Continuing Operations — diluted	$	6.02		$	4.36		$	2.58
Income from Discontinued Operations, net of taxes — basic	$	4.47		$	0.85		$	0.61
Income from Discontinued Operations, net of taxes — diluted	$	4.44		$	0.84		$	0.60
Net Income Available to Common Stockholders — basic	$	10.54		$	5.24		$	3.21
Net Income Available to Common Stockholders — diluted	$	10.46		$	5.19		$	3.18
Dividends	$	0.36		$	0.36		$	0.28
Average Number of Common Shares Outstanding — Basic		460			470			499
Average Number of Common Shares Outstanding — Diluted		464			475			503

See accompanying notes to consolidated financial statements.

65

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

	December 31
	2006			2005
millions
ASSETS
Current Assets
Cash and cash equivalents	$	491		$	561
Accounts receivable, net of allowance:
Customers		1,476			1,109
Others		1,815			493
Other current assets		764			276
Current assets held for sale		68			477
Total		4,614			2,916
Properties and Equipment
Original cost (includes unproved properties of $14,683 and $1,198 as of December 31, 2006 and 2005, respectively)		57,965			23,130
Less accumulated depreciation, depletion and amortization		9,226			7,935
Net properties and equipment — based on the full cost method of accounting for oil and gas properties		48,739			15,195
Other Assets		865			561
Goodwill and Other Intangible Assets		4,616			1,089
Long-term Assets Held for Sale		10			2,827
Total Assets	$	58,844		$	22,588
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	3,501		$	1,485
Accrued expenses		1,739			499
Current debt		11,471			80
Current liabilities associated with assets held for sale		47			339
Total		16,758			2,403
Long-term Debt		11,520			3,547
Other Long-term Liabilities
Deferred income taxes		13,240			3,993
Other		2,413			819
Long-term liabilities associated with assets held for sale		—			775
Total		15,653			5,587
Stockholders’ Equity
Preferred stock, par value $1.00 per share
(2.0 million shares authorized, 0.05 million and 0.09 million shares issued as of December 31, 2006 and 2005, respectively)		46			89
Common stock, par value $0.10 per share
(1.0 billion and 450.0 million shares authorized, 467.4 million and 266.3 million shares issued as of December 31, 2006 and 2005, respectively)		47			27
Paid-in capital		5,429			6,063
Retained earnings		9,919			6,957
Treasury stock (0.4 million and 34.4 million shares as of December 31, 2006 and 2005, respectively)		(20	)		(2,423	)
Executives and Directors Benefits Trust, at market value (4.0 million and 2.0 million shares as of December 31, 2006 and 2005, respectively)		(174	)		(189	)
Accumulated other comprehensive income (loss):
Unrealized loss on derivative instruments		(137	)		(5	)
Foreign currency translation adjustments		—			549
Pension and other postretirement plans		(197	)		(17	)
Total		(334	)		527
Total		14,913			11,051
Commitments and Contingencies (Note 20 and Note 22)
Total Liabilities and Stockholders’ Equity	$	58,844		$	22,588

See accompanying notes to consolidated financial statements.

66

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

	Years Ended December 31
	2006			2005			2004
millions
Preferred Stock
Balance at beginning of year	$	89		$	89		$	89
Preferred stock repurchased and retired		(43	)		—			—
Balance at end of year		46			89			89
Common Stock
Balance at beginning of year		27			26			26
Common stock issued		1			1			—
Two-for-one stock split		23			—			—
Retirement of treasury stock		(4	)		—			—
Balance at end of year		47			27			26
Paid-in Capital
Balance at beginning of year		6,063			5,741			5,453
Common stock issued		224			263			260
Two-for-one stock split		(23	)		—			—
Retirement of treasury stock		(820	)		—			—
Revaluation to market for Executives and Directors Benefits Trust		(15	)		59			28
Balance at end of year		5,429			6,063			5,741
Retained Earnings
Balance at beginning of year		6,957			4,661			3,199
Net income		4,854			2,471			1,606
Dividends — preferred		(3	)		(5	)		(5	)
Dividends — common		(167	)		(170	)		(139	)
Retirement of treasury stock		(1,722	)		—			—
Balance at end of year		9,919			6,957			4,661
Treasury Stock
Balance at beginning of year		(2,423	)		(1,476	)		(166	)
Purchase of treasury stock		(142	)		(947	)		(1,310	)
Retirement of treasury stock		2,545			—			—
Balance at end of year		(20	)		(2,423	)		(1,476	)
Employee Stock Ownership Plan
Balance at beginning of year		—			(7	)		(22	)
Release of shares		—			7			15
Balance at end of year		—			—			(7	)
Executives and Directors Benefits Trust
Balance at beginning of year		(189	)		(130	)		(102	)
Revaluation to market		15			(59	)		(28	)
Balance at end of year		(174	)		(189	)		(130	)
Accumulated Other Comprehensive Income (Loss), net of taxes
Balance at beginning of year		527			381			122
Unrealized gain (loss) on derivative instruments		(132	)		18			97
Foreign currency translation adjustments		(549	)		67			182
Minimum pension liability adjustments		7			61			(20	)
Adoption of SFAS No. 158		(187	)		—			—
Balance at end of year		(334	)		527			381
Total Stockholders’ Equity	$	14,913		$	11,051		$	9,285

See accompanying notes to consolidated financial statements.

67

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Years Ended December 31
	2006			2005			2004
millions
Net Income Available to Common Stockholders	$	4,851		$	2,466		$	1,601
Add: Preferred stock dividends		3			5			5
Net Income		4,854			2,471			1,606
Other Comprehensive Income (Loss), net of taxes
Unrealized gains (losses) on derivative instruments:
Unrealized losses during the period(1)		(135	)		(126	)		(165	)
Reclassification adjustment for loss included in net income(2)		3			144			262
Total unrealized gains (losses) on derivative instruments		(132	)		18			97
Foreign currency translation adjustments:
Unrealized foreign currency gains(3)		73			67			182
Reclassification of foreign currency translation to gain on the disposition of Canadian operations(4)		(622	)		—			—
Total foreign currency translation adjustments		(549	)		67			182
Pension and other postretirement plans adjustments(5)		7			61			(20	)
Total		(674	)		146			259
Comprehensive Income	$	4,180		$	2,617		$	1,865
(1) net of income tax benefit of:	$	77		$	73		$	96
(2) net of income tax expense of:		(2	)		(82	)		(153	)
(3) net of income tax expense of:		(14	)		(9	)		(22	)
(4) net of income tax benefit of:		105			—			—
(5) net of income tax benefit (expense) of:		(3	)		(35	)		11

See accompanying notes to consolidated financial statements.

68

ANADARKO PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31
	2006			2005			2004
millions
Cash Flow from Operating Activities
Net income	$	4,854		$	2,471		$	1,606
Less income from discontinued operations, net of taxes		2,058			398			305
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		1,976			1,111			1,132
Deferred income taxes		523			480			201
Impairments		388			78			72
Unrealized (gains) losses on derivatives		(837	)		7			(12	)
Other noncash items		52			(33	)		69
Changes in assets and liabilities:
Increase in accounts receivable		(398	)		(516	)		(274	)
Increase in accounts payable and accrued expenses		647			351			335
Other items — net		(113	)		(49	)		(81	)
Cash provided by operating activities — continuing operations		5,034			3,502			2,743
Cash provided by (used in) operating activities — discontinued operations		(139	)		644			464
Net cash provided by operating activities		4,895			4,146			3,207
Cash Flow from Investing Activities
Acquisitions, net of cash acquired		(21,087	)		—			(46	)
Additions to properties and equipment		(4,569	)		(2,918	)		(2,486	)
Sales of properties and equipment and other assets		1,086			160			2,087
Cash used in investing activities — continuing operations		(24,570	)		(2,758	)		(445	)
Cash provided by (used in) investing activities — discontinued operations		3,613			(495	)		408
Net cash used in investing activities		(20,957	)		(3,253	)		(37	)
Cash Flow from Financing Activities
Proceeds from issuance of debt, net of offering costs		33,818			4			18
Retirements of debt		(17,697	)		(170	)		(1,188	)
Increase (decrease) in accounts payable, banks		61			86			(43	)
Sale of future hard minerals royalty revenues		—			—			158
Dividends paid		(170	)		(175	)		(144	)
Settlement of derivatives with a financing element		(122	)		—			—
Purchase of treasury stock		(142	)		(947	)		(1,310	)
Repurchase and retirement of preferred stock		(43	)		—			—
Issuance of common stock		130			168			194
Cash provided by (used in) financing activities — continuing operations		15,835			(1,034	)		(2,315	)
Cash provided by (used in) financing activities — discontinued operations		(12	)		3			(46	)
Net cash provided by (used in) financing activities		15,823			(1,031	)		(2,361	)
Effect of Exchange Rate Changes on Cash — discontinued operations		11			3			3
Net (Decrease) Increase in Cash and Cash Equivalents		(228	)		(135	)		812
Cash and Cash Equivalents at Beginning of Period		739			874			62
Cash and Cash Equivalents at End of Period	$	511		$	739		$	874

See accompanying notes to consolidated financial statements.

69

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

1. Summary of Significant Accounting Policies

General  Anadarko Petroleum Corporation is engaged in the exploration, development, production, gathering, processing 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. During the third quarter of 2006, Anadarko completed the acquisitions of Kerr-McGee Corporation (Kerr-McGee) and Western Gas Resources, Inc. (Western). See Note 2. The terms “Anadarko” and “Company” refer to Anadarko Petroleum Corporation and its subsidiaries.

Discontinued Operations  Certain amounts have been reclassified to present the Company’s Canadian operations as discontinued operations. Unless otherwise indicated, information presented in the notes to the financial statements relates only to Anadarko’s continuing operations. Information related to discontinued operations is included in Note 4 and in some instances, where appropriate, is included as a separate disclosure within the individual footnotes.

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. Investments in entities over which it has significant influence, but not control, are carried at cost adjusted for equity in earnings or (losses) and distributions received. 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 determination of proved reserves, litigation, environmental liabilities, income taxes, and fair values. Changes in facts and circumstances or discovery of new information may result in revised estimates and actual results may differ from these estimates.

Changes in Accounting Principles  In January 2006, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 123(R), “Share-Based Payment,” using the modified prospective method. See Note 5.

In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — An Amendment of FASB Statements No. 87, 88, 106, and 132(R).” SFAS No. 158 requires companies to recognize the overfunded or underfunded status of a defined benefit postretirement plan in its balance sheet, measured as the difference between the fair value of plan assets and the benefit obligation, and recognize changes in the funded status of a plan during the reporting period as a component of accumulated comprehensive income. The recognition and disclosure provisions of SFAS No. 158 are effective for Anadarko as of December 31, 2006 and were adopted as of that date. See Note 21.

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 of the full cost pool.

70

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

1. Summary of Significant Accounting Policies (Continued)

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 are individually evaluated 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 properties are evaluated. The Land Grant’s mineral interests (both working and royalty interests) are owned by the Company in perpetuity.

Insignificant properties are aggregated and 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.

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 related 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

71

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

1. Summary of Significant Accounting Policies (Continued)

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 information on the effect of cash flow hedges, seeSupplemental Information on Oil and Gas Exploration and Production Activities — Discounted Future Net Cash Flows.

Asset Retirement Obligations  The initial estimated retirement obligation of properties is recognized as a liability, with an associated increase in properties and equipment. Accretion expense is recognized over the estimated productive life of the related assets. 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. Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations.

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.

Realized gains and losses on derivative instruments that receive cash flow hedge accounting treatment and any associated hedge ineffectiveness and realized and unrealized gains and losses on derivative instruments that do not receive cash flow hedge accounting treatment are included in gas sales, oil and condensate sales and NGLs sales.

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 production are also included in gas sales, oil and condensate sales and NGLs sales. Marketing margins related to purchase of third-party commodities are included in gathering, processing and marketing sales.

Derivative Instruments  Anadarko utilizes derivative instruments in conjunction with its marketing and trading activities and to manage the price risk attributable to the Company’s forecasted sale of its oil, natural gas and NGLs production. Anadarko also periodically utilizes derivatives to manage its exposure associated with NGLs processing, interest rates and foreign currency exchange rates. All derivatives, other than those that meet the normal purchases and sales exception, are carried on the balance sheet at fair value.

72

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

1. Summary of Significant Accounting Policies (Continued)

For those derivatives that are designated and qualify for hedge accounting, Anadarko formally documents the hedging relationship including the risk management objective and strategy for undertaking the hedge. In order to qualify for hedge accounting, the changes in value of the hedging instrument must be expected to be highly effective in offsetting changes in value of the hedged item. Anadarko assesses the correlation between the hedging instrument and the hedged item at inception of the hedging relationship and each quarter thereafter utilizing regression analysis. 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 affects earnings. The ineffective portion of unrealized gains and losses attributable to cash flow hedges, if any, is recognized currently in earnings. 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. Gains and losses attributable to derivative instruments that are not designated or do not qualify for hedge accounting are recognized currently in earnings.

Through the end of 2006, Anadarko applied hedge accounting to some of its commodity and interest rate derivatives. Effective January 1, 2007, Anadarko discontinued hedge accounting on all existing commodity and interest rate derivatives. From that date forward, all gains and losses on such instruments will be recognized in earnings when incurred. Net derivative losses in accumulated other comprehensive income as of December 31, 2006, will be reclassified to earnings in future periods as the original hedged transactions affect earnings. Discontinuing hedge accounting will not affect Anadarko’s reported financial position or cash flows and does not require adjustments to previously reported financial statements.

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. See Note 9.

Inventories  Materials and supplies and commodity inventories are stated at the lower of average cost or market and removed at carrying value.

Goodwill and Other Intangible Assets  Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed. The Company assesses the carrying amount of goodwill by testing the goodwill for impairment annually and when impairment indicators arise. 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. No goodwill impairment was indicated as of December 31, 2006.

Future changes in goodwill may result from, among other things, finalization of preliminary purchase price allocations, changes in deferred income tax liabilities related to previous acquisitions, divestitures, impairments or future acquisitions or future divestitures.

73

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

1. Summary of Significant Accounting Policies (Continued)

Other intangible assets represent contractual rights obtained in connection with acquisitions that have favorable terms relative to the market value on the day on the acquisition. Other intangible assets are amortized over their estimated useful lives and are reviewed for impairment whenever impairment indicators are present. See Note 3.

Legal Contingencies  The Company is subject to legal proceedings, claims and liabilities which arise in the ordinary course of its business. Except for legal contingencies acquired in a business combination which are recorded at fair value, the Company accrues for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. See Note 22.

Environmental Contingencies  Except for environmental contingencies acquired in a business combination which are recorded at fair value, 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 additional information becomes available 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 at their undiscounted value as assets when their receipt is deemed probable. See Note 22.

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  The Company accounts for stock-based compensation under the fair value method. The Company grants various types of stock-based awards including stock options, nonvested equity shares (restricted stock) and performance-based awards. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Restricted stock awards are valued using the market price of Anadarko common stock on the grant-date. For performance-based 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 Anadarko common stock on the grant-date. Liability-classified awards are valued at the end of each period based on the specifications of each plan. The Company records compensation cost for stock-based compensation awards over the requisite service period. Compensation cost is recognized net of estimated forfeitures. As each award vests, an adjustment is made to compensation cost for any difference between the estimated forfeitures and the actual forfeitures related to the vested shares. For equity awards that contain service and market conditions, compensation cost is recorded using the straight-line method. If the requisite service period is satisfied, compensation cost 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 the grant-date. See Note 5.

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, restricted stock and performance-based stock awards under the treasury stock method if including such potential shares of common stock is dilutive. See Note 13.

74

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

1. Summary of Significant Accounting Policies (Continued)

Recently Issued Accounting Standards Not Yet Adopted  FASB Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109,” was issued in 2006 and became effective January 1, 2007 for Anadarko. FIN 48 defines the criteria an individual tax position must meet for any part of the benefit of that position to be recognized in the financial statements. FIN 48 also provides guidance on the measurement of the income tax benefit associated with uncertain tax positions, de-recognition, classification, interest and penalties and financial statement disclosures. In light of the acquisitions of Kerr-McGee and Western in 2006, the Company is currently evaluating the potential effects of adopting FIN 48 on its financial statements. The Company cannot reasonably determine the impact of FIN 48 on its financial statements at this time, but will complete its analysis during the first quarter of 2007.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosure requirements for fair value measurements. SFAS No. 157 does not require new fair value measurements. Rather, its provisions will apply when fair value measurements are performed under other accounting pronouncements. SFAS No. 157 is effective for Anadarko in the first quarter of 2008. The Company is currently evaluating the effects of adoption on its financial statements.

2. Acquisitions

On August 10, 2006, Anadarko completed the acquisition of Kerr-McGee, an independent exploration and production company, in an all-cash transaction totaling $16.5 billion, plus the assumption of debt of approximately $2.6 billion. On August 23, 2006, Anadarko completed the acquisition of Western, also an independent exploration and production company, in an all-cash transaction totaling $4.8 billion, plus the assumption of debt of $625 million. These transactions were financed for $22.5 billion under a 364-day committed acquisition facility. See Note 8.

Management believes that one of the most attractive aspects of Kerr-McGee and Western is the overlap of their asset bases with Anadarko’s existing portfolio, resulting in the Company holding increased positions in two important North American oil and gas basins, the Rockies and the deepwater Gulf of Mexico. These two geographic areas tie directly to Anadarko’s strategy to identify and develop unconventional resources and explore in these proven basins. Other important factors were the ability to secure intellectual talent to help exploit these areas as well as others and the expansion of the Company’s gas gathering, processing and treating operations.

The acquisitions are accounted for under the purchase method of accounting. Under this method of accounting, the Company’s historical operating results for periods prior to the acquisitions remain unchanged. At the date of the acquisitions, the assets and liabilities of Anadarko continue to be recorded based upon their historical costs, and the assets and liabilities of Kerr-McGee and Western are recorded at their estimated fair values. Results of operations attributable to Kerr-McGee and Western were included in Anadarko’s consolidated statement of income beginning on their respective acquisition dates in the third quarter of 2006.

75

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

2. Acquisitions (Continued)

The following is a preliminary allocation of the purchase price to the assets acquired and liabilities assumed in the Kerr-McGee and Western acquisitions as of their respective acquisition dates.

millions	Kerr-McGee			Western			Total
Allocation of Purchase Price
Current assets	$	1,561		$	528		$	2,089
Property and equipment		23,808			7,483			31,291
Other assets		1,268			70			1,338
Intangible assets		194			137			331
Goodwill		3,188			104			3,292
Current debt		(309	)		(625	)		(934	)
Other current liabilities		(2,611	)		(451	)		(3,062	)
Long-term debt		(2,280	)		—			(2,280	)
Deferred income taxes		(6,869	)		(2,352	)		(9,221	)
Other long-term liabilities		(1,434	)		(121	)		(1,555	)
	$	16,516		$	4,773		$	21,289

The purchase price allocation is based on a preliminary assessment of the fair value of the assets acquired and liabilities assumed in the Kerr-McGee and Western transactions. The assessment of the fair values of oil and gas properties and certain plant and gathering facilities acquired were based on projections of expected future net cash flows, discounted to present value. Other assets and liabilities were recorded at their historical book values which the Company believes represent the best current estimate of fair value. The liabilities assumed include certain amounts associated with contingencies, such as legal, environmental and guarantees, which were estimated by management. Long-term debt assumed was recorded at fair value based on the market prices of Kerr-McGee’s publicly traded debt as of August 10, 2006. The amount allocated to goodwill is all associated with the oil and gas segment. The purchase price allocation is preliminary subject to finalizing fair value appraisals and completing evaluations of proved and unproved oil and gas properties, deferred income taxes, asset retirement obligations, contractual arrangements and legal and environmental matters. These and other estimates are subject to change as additional information becomes available and is assessed by Anadarko.

Allocations of the purchase price to Kerr-McGee’s and Western’s property and equipment include approximately $12.9 billion for the estimated fair value associated with unproved oil and gas properties. Kerr-McGee’s other assets include approximately $1 billion of assets Kerr-McGee previously held for sale. The sale of these assets closed in August 2006 and the proceeds were used to pay down debt incurred to fund the acquisitions. No gain or loss was recognized from the sale of these assets.

The following table presents summarized pro forma information for Anadarko as if the acquisitions occurred on January 1, 2006 and 2005.

millions except per share amounts	2006		2005
Revenues	$	13,665	$	11,846
Income from continuing operations	$	2,759	$	2,102
Earnings per share from continuing operations — basic	$	5.99	$	4.47
Earnings per share from continuing operations — diluted	$	5.95	$	4.43

The pro forma information is presented for illustration purposes only, in accordance with the assumptions set forth below, and is not necessarily indicative of the operating results that would have occurred had the

76

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

2. Acquisitions (Continued)

acquisitions been completed at the assumed dates, nor is it necessarily indicative of future operating results of the combined enterprise. The pro forma information does not reflect any cost savings or other synergies anticipated as a result of the acquisitions, or any future acquisition related expenses. The pro forma adjustments include estimates and assumptions based on currently available information. Management believes the estimates and assumptions are reasonable, and the significant effects of the transactions are properly reflected.

The pro forma information for 2006 and 2005 is a result of combining the income statements of Anadarko with the pre-acquisition results from January 1, 2006 and 2005 of Kerr-McGee and Western adjusted for 1) recording pro forma interest expense on debt incurred to acquire Kerr-McGee and Western; 2) DD&A expense of Kerr-McGee and Western calculated in accordance with the full cost method of accounting applied to the adjusted basis of the properties acquired using the purchase method of accounting; 3) reversal of Kerr-McGee’s and Western’s historical impairments and gains and losses on sales of oil and gas properties to conform to the full cost method of accounting for oil and gas activities; 4) certain costs that had been expensed under the successful efforts method of accounting that are capitalized under the full cost method of accounting; 5) capitalization of interest expense on a portion of the fair value of unevaluated properties based on estimated levels of exploration and development activity; and 6) the related income tax effects of these adjustments based on the applicable statutory tax rates. Certain historical amounts related to Kerr-McGee and Western’s results were reclassified to conform to the current presentation.

3. Goodwill and Other Intangible Assets

During 2006, the Company recorded goodwill of $3.3 billion associated with the acquisitions of Kerr-McGee and Western. As discussed in Note 2, the allocation of part of the Kerr-McGee and Western acquisition cost to goodwill is preliminary and is subject to change as the purchase price allocation is finalized. None of Anadarko’s goodwill is deductible for tax purposes.

Changes in the carrying amount of goodwill for 2006 and 2005 are as follows:

millions	2006			2005
Balance at beginning of year	$	1,089		$	1,202
Goodwill associated with acquisitions		3,292			—
Other changes, net		(49	)		(113	)
Balance at end of year	$	4,332		$	1,089

Goodwill of $107 million has been allocated to the Canadian operations and is included in Long-term Assets Held for Sale on the December 31, 2005 consolidated balance sheet.

Intangible assets subject to amortization at December 31, 2006 are as follows:

millions	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Balance at December 31, 2005	$	—	$	—		$	—
Transportation contracts		171		(10	)		161
Drilling contracts		160		(37	)		123
Balance at December 31, 2006	$	331	$	(47	)	$	284

Amortization of transportation contract intangibles reduces earnings, while amortization of drilling contract intangibles increases amounts capitalized to oil and gas properties. The estimated amortization for the next five

77

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

3. Goodwill and Other Intangible Assets (Continued)

years is $136 million, $39 million, $28 million, $23 million and $20 million, respectively. The remaining weighted-average amortization period for the transportation contracts and drilling contracts is 5.4 years and 1.1 years, respectively.

4. Discontinued Operations and Other Divestitures

Discontinued Operations  In November 2006, Anadarko sold its wholly-owned subsidiary, Anadarko Canada Corporation, for approximately $4.3 billion before taxes. Accordingly, the Canadian operations have been classified as discontinued operations in the consolidated statements of income and cash flows and the assets and associated liabilities have been classified as held for sale in the consolidated balance sheets. The disposition is part of a portfolio refocusing effort stemming from the acquisitions of Kerr-McGee and Western. Net proceeds from the Canadian divestiture were used to retire debt. Under the Company’s 364-day term loan agreement, the Company is required to use net cash proceeds from any significant dispositions of assets to repay debt. Because the Canadian assets were subject to this requirement, approximately $58 million of interest expense related to the portion of debt that was repaid upon the sale of the Canadian operations is included in results of discontinued operations for the year ended December 31, 2006.

In December 2006, the Company also exchanged its remaining oil and gas properties in Canada for interests in oil and gas properties in the United States. The associated $40 million pretax gain is included in gain on disposition of discontinued operations.

The following table summarizes the amounts included in income from discontinued operations for all periods presented.

millions except per share amounts	2006		2005		2004
Revenues	$	717	$	913	$	955
Income from discontinued operations	$	330	$	490	$	377
Gain on disposition of discontinued operations		2,263		—		—
Income from discontinued operations before income taxes		2,593		490		377
Income tax expense		535		92		72
Income from discontinued operations, net of taxes	$	2,058	$	398	$	305

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

millions	2006			2005			2004
Income from discontinued operations	$	2,593		$	490		$	377
Statutory tax rate		35	%		35	%		35	%
Tax computed at statutory rate	$	908		$	172		$	132
Adjustment resulting from:
Foreign taxes in excess of federal statutory tax rate		46			(29	)		6
Cross border financing		(45	)		(51	)		(51	)
Effect of change in Canadian income tax rate		(79	)		—			(15	)
Tax on sale of discontinued operations differing from statutory rate		(295	)		—			—
Total income tax expense related to discontinued operations	$	535		$	92		$	72
Effective tax rate		21	%		19	%		19	%

78

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

4. Discontinued Operations and Other Divestitures (Continued)

The tax effects of temporary differences that give rise to significant portions of the deferred assets (liabilities) associated with assets held for sale at December 31, 2006 and 2005 are as follows:

millions	2006		2005
Oil and gas exploration and development costs	$	—	$	(38	)
Other		7		—
Net current deferred tax liabilities		7		(38	)
Oil and gas exploration and development costs		—		(665	)
Other		—		(107	)
Gross long-term deferred tax liabilities		—		(772	)
Other		—		46
Gross long-term deferred tax assets		—		46
Less: valuation allowance on deferred tax assets not expected to be realized		—		—
Net long-term deferred tax assets		—		46
Net long-term deferred tax liabilities		—		(726	)
Total deferred taxes	$	7	$	(764	)

The following presents the main classes of assets and liabilities associated with Canadian operations as of December 31, 2006 and 2005.

millions	2006		2005
ASSETS
Cash	$	20	$	178
Accounts receivable		24		248
Other current assets		24		51
Total Current Assets Held for Sale		68		477
Net properties and equipment		—		2,667
Other assets		10		53
Goodwill		—		107
Total Long-term Assets Held for Sale	$	10	$	2,827
LIABILITIES
Accounts payable	$	30	$	240
Accrued expenses		17		57
Current debt		—		42
Total Current Liabilities associated with Assets Held for Sale		47		339
Long-term debt		—		8
Deferred income taxes		—		726
Other liabilities		—		41
Total Long-term Liabilities associated with Assets Held for Sale	$	—	$	775

79

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

4. Discontinued Operations and Other Divestitures (Continued)

Other Divestitures  Anadarko has signed several separate and unrelated agreements with various companies for the divestiture of certain non-core properties in the Gulf of Mexico and onshore in the United States for a combined total of approximately $6.5 billion before income taxes. Certain of these agreements closed in early 2007 with the remaining agreements expected to close by the end of the second quarter of 2007. Anadarko plans to use net proceeds from these divestitures to further reduce debt under the acquisition facility.

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.

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. Excluding the sale of the Canadian operations in 2006, dispositions during 2006, 2005 and 2004 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.

5. Stock-Based Compensation

Effective January 2006, the Company adopted SFAS No. 123(R), which requires the Company to estimate forfeitures in calculating the expense related to share-based compensation as opposed to recognizing these forfeitures and the corresponding reduction in expense as they occur. The related cumulative adjustment as of January 1, 2006 of $2 million before income taxes was recorded as a reduction to general and administrative expense in 2006 and was not presented separately in the income statement due to immateriality. Prior to the adoption of SFAS No. 123(R), the Company followed the fair value method of accounting for share-based compensation under SFAS No. 123, “Accounting for Stock-Based Compensation.” Results for prior periods have not been revised. The adoption of SFAS No. 123(R) did not have a material impact on the Company’s income before income taxes, net income or basic and diluted earnings per share for 2006. The effect on net income and earnings per share for 2005 and 2004, had the Company applied the fair value recognition provisions of SFAS No. 123(R) to all options, was not material.

Prior to the adoption of SFAS No. 123(R), the Company reported amounts attributable to the benefits of tax deductions in excess of recognized compensation in the financial statements (excess tax benefits) in the statement of cash flows as operating activities in other items, net. SFAS No. 123(R) requires the cash flows resulting from excess tax benefits to be classified as financing cash flows. For 2006, $36 million in excess tax benefits were included in cash flow from financing activities. For 2005 and 2004, $35 million and $19 million, respectively, in excess tax benefits, which would have been presented in cash flow from financing activities under SFAS No. 123(R), were included in cash flow from operating activities. Cash received from stock option exercises for 2006, 2005 and 2004 was $91 million, $168 million and $200 million, respectively.

Activities and balances presented include amounts associated with discontinued operations. All share and price per share information presented has been restated to give retroactive effect to the May 2006 two-for-one stock split that was affected in the form of a stock dividend. See Note 13.

80

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

5. Stock-Based Compensation (Continued)

The Company generally issues new shares to satisfy employee share-based payment plans. At December 31, 2006, 12 million shares of the 47 million shares of Anadarko common stock originally authorized for awards under the active share-based compensation plans remain available for future issuance. The number of shares available is reduced by awards granted. A summary of stock-based compensation cost is presented below:

millions	2006		2005		2004
Compensation cost:
Restricted stock	$	53	$	29	$	18
Other		26		28		34
Compensation cost		79		57		52
Less: capitalization of compensation cost		16		15		14
Total compensation cost, pretax		63		42		38
Income tax benefit		20		15		14

Equity Classified Awards

Stock Options  Certain employees may be granted options to purchase shares of Anadarko common stock under the 1999 Stock Incentive Plan. Stock options are granted with an exercise price equal to, or greater than, 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 options vest over service periods ranging from one to four years.

Nonemployee directors may be granted nonqualified stock options under the 1998 Director Stock Plan. Stock options are granted with an exercise price equal to 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 options vest over service periods ranging from the date of grant up to two years.

The fair value of stock option awards is determined using the Black-Scholes option pricing model. For 2006, 2005 and 2004, the expected life of the option was estimated based upon historical exercise behavior. For 2006, the expected forfeiture rate was estimated separately. For 2006, the volatility assumption was based upon historical and implied volatilities over a term commensurate with the expected life of the option. For 2005 and 2004, the volatility assumption was based upon historical price volatility over a term commensurate with the expected life of the option. For 2006, 2005 and 2004, the risk-free interest rate was based on the U.S. Treasury rate for a term commensurate with the expected life of the option. For 2006, the dividend yield was based upon a 12-month average dividend yield. For 2005 and 2004, the dividend yield was based on a historical dividend yield. The Company used the following weighted-average assumptions to estimate the fair value of stock options granted during 2006, 2005 and 2004.

	2006		2005		2004
Expected option life — years	5.0		5.4		5.2
Volatility	29.8	%	29.6	%	33.6	%
Risk-free interest rate	4.4	%	4.5	%	3.5	%
Dividend yield	0.8	%	0.7	%	0.6	%

81

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

5. Stock-Based Compensation (Continued)

A summary of stock option activity for the year ended December 31, 2006 is presented below:

	Shares (millions)		Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (years)	Aggregate Intrinsic Value (millions)
Outstanding at January 1, 2006	9.57		$	25.57
Granted	1.23		$	48.87
Exercised	(4.07	)	$	22.38
Forfeited or expired	(0.08	)	$	30.85
Outstanding at December 31, 2006	6.65		$	31.78	3.9	$	85
Vested or expected to vest at December 31, 2006	6.54		$	31.71	3.9	$	84
Exercisable at December 31, 2006	4.11		$	26.96	2.6	$	68

The weighted-average grant-date fair value of stock options granted during 2006, 2005 and 2004 was $15.44, $14.43 and $11.48, respectively, using the Black-Scholes option pricing model. The total intrinsic value of stock options exercised during 2006, 2005 and 2004 was $107 million, $136 million and $101 million, respectively, based on the difference between the market price at the exercise date and the option price. As of December 31, 2006, there was $26 million of total unrecognized compensation cost related to stock options, which is expected to be recognized over a weighted-average period of 1.9 years.

Restricted Stock  Shares of common stock may be granted to certain employees and nonemployee directors as restricted stock under the 1999 Stock Incentive Plan and the 1998 Director Stock Plan. Restricted stock is subject to forfeiture restrictions and cannot be sold, transferred or disposed of during the restriction period. The holders of restricted stock generally have the same rights as 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 the shares. Restricted stock awards vest over service periods ranging from the date of grant up to four years. Restricted stock is not considered issued and outstanding until it vests.

A summary of restricted stock activity for the year ended December 31, 2006 is presented below:

	Shares (millions)		Weighted-Average Grant-Date Fair Value
Nonvested at January 1, 2006	3.11		$	34.92
Granted	3.64		$	48.88
Vested	(1.78	)	$	31.71
Forfeited	(0.12	)	$	38.06
Nonvested at December 31, 2006	4.85		$	46.51

The weighted-average grant-date fair value of restricted stock granted during 2005 and 2004 was $42.38 and $32.06, respectively. The total fair value of restricted shares vested during 2006, 2005 and 2004 was $84 million, $32 million and $34 million, respectively, based on the market price at the vesting date. As of December 31, 2006, there was $197 million of total unrecognized compensation cost related to restricted stock, which is expected to be recognized over a weighted-average period of 2.5 years.

82

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

5. Stock-Based Compensation (Continued)

Performance-Based Share Awards  Anadarko and key officers of the Company have three Performance Unit Agreements with three-year terms under the 1999 Stock Incentive Plan. The agreements provide for issuance of up to a maximum of 200,400 shares of Anadarko common stock after a three-year performance period ending in 2007, a maximum of 506,000 shares of Anadarko common stock after a three-year performance period ending in 2008 and a maximum of 358,200 shares of Anadarko common stock after a three-year performance period ending in 2009. 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. The fair value per share for the performance conditions is $31.54, $47.14 and $49.86 for the agreements related to the three-year periods ending 2007, 2008 and 2009, respectively. During 2006, 73,200 shares were issued under these agreements with a fair value of $3 million.

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 160,000 shares of Anadarko common stock after a two-year performance period that ended in 2005 and a four-year performance 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. During 2006, 28,800 shares were issued for the performance period that ended in 2005 with a fair value of $2 million.

As of December 31, 2006, there was $16 million of total estimated unrecognized compensation cost related to performance-based share awards, which is expected to be recognized over a weighted-average period of 2.0 years.

Liability Classified Awards

Long-Term Incentive Cash Program  Anadarko offered a cash incentive program to employees of the Company’s previously owned Canadian subsidiary that provided potential cash payments based upon attainment of specified Anadarko stock price targets. The awards vested over service periods of two years from the date of grant and expire five years from the date of grant. For 2006, 2005 and 2004, the liability paid was $14 million, $21 million and $12 million, respectively. As of December 31, 2006, there was no remaining liability under this program.

Value Creation Plan  The Company offers a cash incentive program that provides employees the opportunity to earn cash bonus awards based on the Company’s total shareholder return for the year compared to the total shareholder return of a predetermined group of peer companies. As of December 31, 2006, no liability was required to be recorded for this plan.

6. Inventories

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

	2006		2005
millions
Materials and supplies	$	158	$	90
Natural gas		42		18
Crude oil and NGLs		55		24
Total	$	255	$	132

83

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

7. Properties and Equipment

A summary of the original cost of properties and equipment by function follows:

	2006		2005
millions
Oil and gas	$	51,563	$	20,886
Gathering, processing and marketing		4,486		516
Minerals		1,201		1,208
Other		715		520
Total	$	57,965	$	23,130

Oil and gas properties include costs of $14.7 billion and $1.2 billion at December 31, 2006 and 2005, respectively, which were excluded from capitalized costs being amortized. These amounts represent unproved properties and major development projects in which the Company owns a direct interest. The increase in costs excluded during 2006 is primarily related to the estimated fair value of unproved properties acquired in the Kerr-McGee and Western acquisitions. At December 31, 2006 and 2005, the Company’s investment in countries where proved reserves have not been established was $1.3 billion and $107 million, respectively.

As a result of contract and structural changes imposed by the Government of Venezuela, Anadarko’s investment in Venezuela oil and gas properties was converted from an operating service agreement, under which Anadarko’s interest was previously consolidated, to an 18% interest in a new operating company, Petroritupano, S.A. The conversion was completed in the fourth quarter of 2006, and the Company began accounting for its interest under the equity method since its ownership interest and other contractual rights, such as a seat on the Board of Directors and the ability to nominate managerial personnel, provides evidence that significant influence is present.

During 2006, 2005 and 2004, the Company made provisions for impairments of $388 million, $78 million and $72 million, respectively. Impairments in 2006 include a $178 million loss associated with the contract and structural changes in Venezuela, a $139 million impairment related to the decision to suspend construction of the Company’s Bear Head LNG project in Nova Scotia and $71 million in impairments related to exploration activities at various international locations. 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 included ceiling test impairments of oil and gas properties in Qatar of $62 million as a result of lower future production estimates and other international exploration activities.

Total interest costs incurred during 2006, 2005 and 2004 were $730 million, $266 million and $428 million, respectively. Of these amounts, the Company capitalized $75 million, $60 million and $70 million during 2006, 2005 and 2004, respectively, as part of the cost of properties.

Properties and equipment include internal costs related to exploration, development and construction activities of $171 million, $143 million and $144 million capitalized during 2006, 2005 and 2004, respectively.

84

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

8. Debt and Interest Expense

	December 31,
	2006				2005
millions	Principal		Carrying Value		Principal		Carrying Value
364-day Acquisition Facility *	$	11,000	$	11,000	$	—	$	—
Commercial Paper, current *		182		182		—		—
7.00% Notes due 2006 *		—		—		51		50
5.375% Notes due 2007 *		143		143		142		142
6.625% Notes due 2007 *		150		146		—		—
3.25% Notes due 2008		350		350		350		350
6.75% Notes due 2008		47		46		47		46
7.30% Notes due 2009		52		52		52		51
Floating Rate Notes due 2009		2,000		2,000		—		—
6.75% Notes due 2011		950		922		950		917
6.875% Notes due 2011		675		708		—		—
6.125% Notes due 2012		170		168		170		168
5.00% Notes due 2012		82		81		82		81
5.95% Notes due 2016		1,750		1,743		—		—
7.05% Debentures due 2018		114		106		114		106
Zero Yield Puttable Contingent Debt Securities due 2021		—		—		30		30
6.95% Notes due 2024		650		676		—		—
7.50% Debenture due 2026		112		106		112		106
7.00% Debentures due 2027		54		54		54		54
7.125% Debentures due 2027		150		158		—		—
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
7.50% Notes due 2031		900		855		900		862
7.875% Notes due 2031		500		584		—		—
Zero Coupon Notes due 2036		2,360		505		—		—
6.45% Notes due 2036		1,750		1,742		—		—
7.73% Debentures due 2096		61		61		61		61
7.50% Debentures due 2096		78		72		78		72
7.25% Debentures due 2096		49		49		49		49
Total debt	$	24,833		22,991	$	3,746	$	3,627
Less current debt *				11,471				80
Total long-term debt			$	11,520			$	3,547

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.

85

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

8. Debt and Interest Expense (Continued)

The net unamortized debt discount, represented in the table above, of $1.8 billion and $119 million as of December 31, 2006 and 2005, respectively, will be amortized to interest expense 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. The average interest rate in effect for commercial paper issued as of December 31, 2006 was 5.45%.

In August 2006, the Company financed $22.5 billion under a 364-day acquisition facility in order to fund the Kerr-McGee and Western acquisitions. The variable-rate facility is based on London Interbank Offered Rate (LIBOR) and had a weighted-average interest rate of approximately 5.80% at December 31, 2006. During 2006, Anadarko repaid approximately $11.5 billion of debt under the 364-day acquisition facility with a combination of proceeds from divestitures, long-term refinancing and available cash flow from operations.

In September 2006, the Company issued $5.5 billion senior notes including Floating Rate Notes due 2009, 5.95% Notes due 2016 and 6.45% Notes due 2036. The net proceeds were used to repay a portion of the acquisition facility. The Floating Rate Notes due 2009 had an average interest rate of approximately 5.76% at December 31, 2006.

In October 2006, the Company received $500 million of proceeds from a private offering of Zero Coupon Senior Notes due 2036 with an aggregate principal value at maturity of $2.4 billion. The Company initially recorded the note in long-term debt at the proceeds amount. The carrying value as of December 31, 2006 includes an increase of $5 million related to accretion expense recognized in 2006. The notes were issued with a yield to maturity of 5.24%, and the holders have an option to put the notes back to the Company periodically at the carrying value. The net proceeds from the private offering were used to repay a portion of the acquisition facility.

An aggregate principal amount of $2.4 billion of outstanding debt was assumed in connection with the Kerr-McGee acquisition, of which $2.1 billion was outstanding as of December 31, 2006 and $307 million was repaid at maturity subsequent to the acquisition. The Company recorded $155 million of debt premium, representing the excess of the fair value over the face value of the debt assumed, which is being amortized to interest expense over the remaining term of the related debt.

An aggregate principal amount of $625 million of outstanding debt was assumed in connection with the Western acquisition and redeemed for cash immediately upon completion of the acquisition.

During 2006, the Company redeemed for cash an aggregate principal amount of $122 million of debt that was outstanding as of December 31, 2005. Of this amount, $80 million is related to continuing operations.

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.

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 borrowing capacity under the agreement up to a total available credit amount of $1.25 billion. The credit agreement initially had 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 Company amended the credit agreement prior to closing the acquisitions to provide for a maximum capitalization ratio of 75% debt, exclusive of the effect of any noncash writedowns, until September 30, 2007. After September 30, 2007, the maximum capitalization ratio is once again 60% debt. The agreement terminates in August 2009. As of December 31, 2006, the Company had no outstanding borrowings under this agreement; however, outstanding letters of credit on the agreement have reduced the available credit amount by $33 million.

86

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

8. Debt and Interest Expense (Continued)

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 was of a long-term investment nature; therefore, net foreign currency translation gains of $63 million and $138 million for 2005 and 2004, respectively, were recorded as a component of other comprehensive income. The intercompany note was settled during 2006 in conjunction with the sale of Canadian operations and previous amounts recorded to other comprehensive income were included in the gain on disposition of discontinued operations.

	2006			2005			2004
millions
Interest Expense
Gross interest expense	$	730		$	266		$	328
Premium and related expenses for early retirement of debt		—			—			100
Capitalized interest		(75	)		(60	)		(70	)
Net interest expense	$	655		$	206		$	358

Total maturities related to debt for the five years ending December 31, 2011 are shown below.

millions
2007	$	11,475
2008		397
2009		2,052
2010		—
2011		1,625

9. Financial Instruments

The following information provides the carrying value and estimated fair value of the Company’s financial instruments:

	Carrying Amount			Fair Value
millions
2006
Cash and cash equivalents	$	491		$	491
Total debt		22,991			23,455
Derivative instruments
Asset		420			420
Liability		(326	)		(326	)
2005
Cash and cash equivalents	$	561		$	561
Total debt		3,627			4,213
Derivative instruments
Asset		93			93
Liability		(134	)		(134	)

87

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

9. Financial Instruments (Continued)

Cash and Cash Equivalents  The carrying amount reported on the balance sheet approximates fair value.

DebtThe fair value of debt at December 31, 2006 and 2005 is the estimated amount the Company would have to pay to repurchase 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 or gas processing operations. 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’s marketing and trading business 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 market prices of natural gas, NGLs and crude oil. Derivative financial instruments are also used to mitigate price risk that is incurred to meet customers’ pricing requirements.

In addition, the Company may use options and swaps to manage exposure associated with changes in interest rates and foreign currency exchange rates. As discussed in Note 1, Anadarko discontinued hedge accounting for all of its commodity and interest derivatives prospectively, effective January 1, 2007.

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. Commodity 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. Interest rate swaps are used by the Company to fix or float the interest rates attributable to the Company’s existing or forecasted debt issuances.

Settlements of futures contracts are guaranteed by the New York Mercantile Exchange (NYMEX) or the International Petroleum Exchange and have nominal credit risk. Over-the-counter traded swaps and options and physical delivery agreements expose the Company to credit risk to 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 when settling with its swap and option counterparties.

At December 31, 2006 and 2005, the Company had unrealized derivative amounts recorded in other current assets in the consolidated balance sheet of $353 million and $69 million, respectively.

Oil and Gas Activities  At December 31, 2006 and 2005, the Company had option contracts and swap contracts in place to hedge the sales price of a portion of its expected future sales of equity oil and gas production. The derivative financial instruments receive hedge accounting treatment if they qualify and are so designated. The timing of the recognition of gains and losses in earnings associated with derivative instruments is dependent on whether hedge accounting is utilized and the effectiveness of the hedge. The effective portion of unrealized gains and losses attributable to derivatives that receive hedge accounting is reported as a component of other comprehensive income and reclassified into earnings in the same period the hedged transaction is recognized. For those derivatives that do not qualify for hedge accounting or were not designated, unrealized gains and losses are

88

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

9. Financial Instruments (Continued)

recognized currently in oil and gas revenues. All realized gains and losses related to derivative financial instruments that are undertaken to hedge the sales price of the Company’s future sales of its gas and oil production are recorded to gas sales and oil and condensate sales when recognized. During 2006, unrealized gains of $837 million were recognized in gas and oil sales compared to unrealized losses of $7 million during 2005 and unrealized gains of $12 million during 2004.

The fair value of all oil and gas related derivative instruments and the accumulated other comprehensive income balance applicable to the unrealized gains and losses on oil and gas derivative financial instruments that are designated as cash flow hedges (excluding the physical delivery sales contracts) are as follows:

	2006			2005
millions
Fair Value — Asset (Liability)
Current	$	(95	)	$	(28	)
Long-term		130			(25	)
Total	$	35		$	(53	)
Accumulated other comprehensive loss before income taxes	$	(10	)	$	(8	)
Accumulated other comprehensive loss after income taxes	$	(6	)	$	(5	)

Gains attributable to cash flow hedge ineffectiveness of $1 million, $10 million and $12 million were recognized in revenue during 2006, 2005 and 2004, respectively. During 2006, 2005 and 2004, net unrealized gains (losses) of $27 million, 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 not probable of occurring due to either property divestitures or well performance. Net gains of approximately $11 million (pretax) and $7 million (after tax) are expected to be reclassified from accumulated other comprehensive income into gas and oil and condensate sales during 2007.

89

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

9. Financial Instruments (Continued)

Below is a summary of the Company’s financial derivative instruments related to its oil and gas production as of December 31, 2006. The natural gas prices are NYMEX Henry Hub. The crude oil prices are a combination of NYMEX Cushing and Brent Dated.

	2007			2008			2009			Average 2010- 2012
Natural Gas
Three-Way Collars (thousand MMBtu/d)		30			500			50			—
Price per MMBtu
Ceiling sold price	$	11.23		$	14.26		$	12.60		$	—
Floor purchased price	$	9.00		$	7.50		$	7.50		$	—
Floor sold price	$	6.00		$	5.00		$	5.00		$	—
Two-Way Collars (thousand MMBtu/d)		386			—			—			—
Price per MMBtu
Ceiling sold price	$	10.73		$	—		$	—		$	—
Floor purchase price	$	6.27		$	—		$	—		$	—
Fixed Price (thousand MMBtu/d)		405			105			90			—
Price per MMBtu	$	7.14		$	8.16		$	7.84		$	—
Total (thousand MMBtu/d)		821			605			140			—
Basis Swaps (thousand MMBtu/d)		557			575			20			—
Price per MMBtu	$	(1.08	)	$	(1.05	)	$	(1.08	)	$	—
Crude Oil
Three-Way Collars (MBbls/d)		35			86			48			8
Price per barrel
Ceiling sold price	$	86.16		$	92.98		$	87.04		$	87.04
Floor purchased price	$	58.57		$	56.07		$	52.51		$	49.35
Floor sold price	$	43.57		$	41.07		$	37.51		$	34.34
Two-Way Collars (MBbls/d)		19			—			—			—
Price per barrel
Ceiling sold price	$	60.40		$	—		$	—		$	—
Floor purchased price	$	44.33		$	—		$	—		$	—
Fixed Price (MBbls/d)		27			—			—			—
Price per barrel	$	51.44		$	—		$	—		$	—
Total (MBbls/d)		81			86			48			8

MBbls/d — thousand barrels per day

MMBtu — million British thermal units

MMBtu/d — million British thermal units per day

90

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

9. Financial Instruments (Continued)

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.

Marketing and Trading Activities  Gains and losses attributed to the Company’s marketing and trading derivative instruments (both physically and financially settled) are recognized currently in earnings. The marketing and trading 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 gains and losses that are attributable to third-party production are recorded to gathering, processing and marketing sales. The fair values of these derivatives as of December 31, 2006 and 2005 are as follows:

	2006		2005
millions
Fair Value — Asset (Liability)
Current	$	57	$	1
Long-term		2		2
Total	$	59	$	3

Firm Transportation Keep-Whole Agreement  Effective April 1, 2006, Anadarko and Duke Energy Corporation (Duke) terminated the keep-whole agreement and Duke transferred to Anadarko a portfolio of certain gas transportation agreements that had been subject to the keep-whole agreement on several U.S. and Canadian pipelines. While the agreement was in effect, it was accounted for at fair value, with gains and losses recorded in other (income) expense. 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.

Interest Rate Swap  Anadarko is a party to two interest rate swaps whereby the Company receives a fixed interest rate and pays a floating interest rate. The first swap was entered into in March 2006 and has an initial term of 25 years and a notional amount of $600 million. This swap qualified and initially was designated for fair value hedge accounting. Realized gains and losses on the interest rate swaps are recorded to interest expense. The unrealized gains (losses) related to changes in the fair value of the interest rate swap and the hedged debt are also recorded to interest expense. The fair value of the interest rate swap ($5 million) is reflected within liabilities and the related change in fair value of the hedged debt ($8 million) is reflected in the carrying value of the associated long term debt. Any difference between the changes in the fair value of the swaps and the carrying value of hedged debt represents hedge ineffectiveness. The second swap, which was acquired with the acquisition of Kerr-McGee, expires in October 2007 and has a notional amount of $150 million. This swap did not qualify for hedge accounting treatment and, therefore, all gains and losses are recorded to interest expense.

In anticipation of the permanent debt financing associated with the acquisitions, Anadarko entered into swaps to fix interest rates and in doing so mitigated a portion of the risk it had to unfavorable interest rate changes prior to the issuance of debt. In June 2006, Anadarko entered into a three-month forward-looking

91

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

9. Financial Instruments (Continued)

30-year swap agreement with a notional value of $1.5 billion and two three-month forward-looking 10-year swap agreements with a combined notional value of $1 billion whereby the Company paid a fixed interest rate and received a floating interest rate indexed to LIBOR. In July 2006, Anadarko entered into a three-month forward-looking 30-year swap agreement with a notional value of $250 million and two three-month forward-looking 10-year swap agreements with combined notional value of $500 million whereby the Company paid a fixed interest rate and received a floating interest rate indexed to LIBOR. The transactions qualified for cash flow hedge accounting. Due to favorable interest rate movement during the hedge period, the Company realized a pre-tax loss of $211 million ($132 million after tax) on these swaps when they settled during September 2006 at the time of the debt issuance. The loss was recorded to accumulated other comprehensive income, and is being amortized to interest expense over the term of the hedged debt. At December 31, 2006, the accumulated other comprehensive loss was $206 million (pretax) and $131 million (after tax). It is anticipated that during 2007, losses of $19 million (pretax) and $12 million (after tax) will be reclassified from accumulated other comprehensive income (loss) to interest expense. See Note 8 for a discussion of both fixed and variable rate debt issued in September 2006.

10. 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 2006, 2005 and 2004, the Company amortized $16 million, $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 cumulative future amount that the third-party investor expects to receive, prior to the 5% of any excess royalties described above, is $170 million. This amount and the payment timing are subject to change based upon the actual royalties received by the Company during the term of the agreement.

11. Asset Retirement Obligations

The majority of Anadarko’s asset retirement obligations relate to the plugging and abandonment of oil and gas properties. The liability for asset retirement obligations is initially recorded at estimated fair value, with an offsetting increase to properties and equipment. Accretion expense is recognized over the estimated productive life of the related assets, increasing the liability to its expected settlement value. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the asset retirement cost.

92

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

11. Asset Retirement Obligations (Continued)

The following table provides a rollforward of the asset retirement obligations. Liabilities settled include, among other things, asset retirement obligations that were assumed by the purchasers of divested properties. Revisions in estimated liabilities during the period relate primarily to revisions of estimated inflation rates and can include, among other things, escalating retirement costs, changes in property lives and the expected timing of settling asset retirement obligations.

	2006			2005
millions
Carrying amount of asset retirement obligations at beginning of year	$	253		$	210
Liabilities assumed with acquisitions		672			—
Other liabilities incurred		39			56
Liabilities settled		(57	)		(10	)
Accretion expense		24			15
Revisions in estimated liabilities		119			(19	)
Impact of foreign currency exchange rate changes		—			1
Carrying amount of asset retirement obligations at end of year	$	1,050		$	253

At December 31, 2006 and 2005, asset retirement obligations of $1,013 million and $221 million, respectively, were included in other long-term liabilities.

12. Preferred Stock

Anadarko has $46 million of 5.46% Series B Cumulative Preferred Stock issued in the form of 0.05 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 plus any accrued or unpaid dividends, before any distributions are made on the Company’s common stock.

Anadarko repurchased $43 million of preferred stock during 2006. For each of the years 2006, 2005 and 2004, dividends of $54.60 per share (equivalent to $5.46 per Depositary Share) were paid to holders of preferred stock.

13. Common Stock

In May 2006, the Company’s shareholders approved an increase in authorized shares so Anadarko could complete a two-for-one stock split to be effected in the form of a stock dividend. The distribution date was May 26, 2006 to stockholders of record on May 12, 2006. In addition, the Company’s Board of Directors approved the retirement of the Company’s existing treasury stock prior to the stock split distribution date. The book value of the treasury shares was allocated to common stock, paid-in capital and retained earnings at the time of retirement. Except for the presentation of common shares authorized and issued on the consolidated balance sheet and shares presented in the table below, all share and per share information has been revised to give retroactive effect to the stock split.

93

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

13. Common Stock (Continued)

The changes in the Company’s shares of common stock are as follows:

	2006		2005	2004
millions
Shares of common stock issued
Beginning of year	266		262	257
Exercise of stock options	3		4	5
Issuance of restricted stock	2		—	—
Retirement of treasury stock	(36	)	—	—
Two-for-one stock split	232		—	—
End of year	467		266	262
Shares of common stock held in treasury
Beginning of year	34		23	3
Purchase of treasury stock	1		11	20
Shares received for restricted stock vested and options exercised	1		—	—
Retirement of treasury stock	(36	)	—	—
End of year	—		34	23
Shares of common stock held for Employee Stock Ownership Plan
Beginning of year	—		—	1
Release of shares	—		—	(1	)
End of year	—		—	—
Shares of common stock held for Executives and Directors Benefits Trust
Beginning of year	2		2	2
Two-for-one stock split	2		—	—
End of year	4		2	2
Shares of common stock outstanding at end of year	463		230	237

In each quarter of 2005 and 2006, dividends of nine cents per share were paid to holders of common stock. In each quarter of 2004, dividends of seven 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 75% debt, exclusive of the effect of any noncash writedowns, until September 30, 2007. After September 30, 2007, the maximum capitalization ratio is 60% debt. Although the covenants of the agreement do not specifically restrict the payment of dividends, the Company could be limited in the amount of dividends it could pay in order to stay below the maximum capitalization ratio. Based on these covenants, as of December 31, 2006, retained earnings of approximately $7.6 billion were not limited as to the payment of dividends.

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.

94

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

13. Common Stock (Continued)

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 2006, the Company purchased 2.5 million shares of common stock in the open market for $0.1 billion under the program. During 2005 and 2004, Anadarko purchased 21.6 million and 40.5 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.

As of December 31, 2006 and 2005, the Company had 4 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 accrued expenses in current liabilities are $10 million at December 31, 2006, and in other long-term liabilities — other are $38 million and $34 million as of December 31, 2006 and 2005, 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 21.

The reconciliation between basic and diluted EPS from continuing operations is as follows:

	For the Year Ended December 31, 2006					For the Year Ended December 31, 2005					For the Year Ended December 31, 2004
	Income		Shares	Per Share Amount		Income		Shares	Per Share Amount		Income		Shares	Per Share Amount
millions except per share amounts
Basic EPS
Income from continuing operations	$	2,796				$	2,073				$	1,301
Preferred stock dividends		3					5					5
Net income from continuing operations available to common stockholders	$	2,793	460	$	6.06	$	2,068	470	$	4.40	$	1,296	499	$	2.60
Effect of ZYP-CODES		—	—				—	1				—	—
Effect of dilutive stock options and performance-based stock awards		—	4				—	4				—	4
Diluted EPS
Net income from continuing operations available to common stockholders plus assumed conversion	$	2,793	464	$	6.02	$	2,068	475	$	4.36	$	1,296	503	$	2.58

For the years ended December 31, 2006, 2005 and 2004, awards for 1.8 million, 0.1 million and 1.5 million average shares, respectively, of common stock were excluded from the diluted EPS calculation because their inclusion would have been anti-dilutive.

See Note 5 for information related to common stock issued under stock-based compensation plans.

95

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

14. Statements of Cash Flows Supplemental Information

Net cash provided by investing activities of discontinued operations in 2006 includes proceeds of $4.2 billion from the disposition of Canadian operations, net of cash included in the sale. The differences between cash and cash equivalents on the consolidated balance sheet and statement of cash flows at December 31, 2006 and 2005 are due to $20 million and $178 million, respectively, related to Canadian operations which is included in Current Assets Held for Sale on the balance sheet.

The amounts of cash paid for interest (net of amounts capitalized) and income taxes, including amounts related to discontinued operations, are as follows:

	2006		2005		2004
millions
Cash paid:
Interest	$	596	$	191	$	345
Income taxes	$	778	$	439	$	256
Non-cash investing activities:
Fair value of properties and equipment received in non-monetary exchange transactions	$	151	$	—	$	—

15. 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, Qatar, Singapore, Spain, Switzerland, United Kingdom and Venezuela. 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, 2006 and 2005, accounts receivable are shown net of allowance for uncollectible accounts of $5 million and $6 million, respectively.

In 2006, there were no sales to individual customers that exceeded 10% of the Company’s total revenues. In 2005 and 2004, sales to affiliates of Duke were $747 million and $903 million, respectively, which accounted for 12% and 18% of the Company’s total 2005 and 2004 revenues, respectively.

16. 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, gathering, processing and marketing activities and minerals activities. The oil and gas exploration and production segment finds and produces natural gas, crude oil, condensate and NGLs. The gathering, processing and marketing segment is responsible for gathering, processing, transporting and selling most of Anadarko’s production as well as volumes of gas, oil and NGLs purchased from third parties. 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 fair value.

96

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

16. Segment and Geographic Information (Continued)

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 Exploration & Production		Gathering, Processing & Marketing			Minerals		All Other & Intercompany Eliminations			Total
millions
2006
Total revenues	$	9,284	$	815		$	59	$	29		$	10,187
Depreciation, depletion and amortization		1,836		71			3		66			1,976
Impairments		249		139			—		—			388
Other costs and expenses		1,719		715			2		500			2,936
Total costs and expenses		3,804		925			5		566			5,300
Operating income (loss)	$	5,480	$	(110	)	$	54	$	(537	)	$	4,887
Net properties and equipment	$	42,802	$	4,306		$	1,178	$	453		$	48,739
Capital expenditures	$	4,233	$	283		$	—	$	78		$	4,594
Goodwill	$	4,332	$	—		$	—	$	—		$	4,332
2005
Total revenues	$	6,013	$	180		$	40	$	(46	)	$	6,187
Depreciation, depletion and amortization		1,039		21			3		48			1,111
Impairments		78		—			—		—			78
Other costs and expenses		1,058		152			2		251			1,463
Total costs and expenses		2,175		173			5		299			2,652
Operating income (loss)	$	3,838	$	7		$	35	$	(345	)	$	3,535
Net properties and equipment	$	13,280	$	405		$	1,188	$	322		$	15,195
Capital expenditures	$	2,816	$	77		$	—	$	50		$	2,943
Goodwill	$	1,089	$	—		$	—	$	—		$	1,089
2004
Total revenues	$	4,963	$	155		$	35	$	(29	)	$	5,124
Depreciation, depletion and amortization		1,061		20			4		47			1,132
Impairments		72		—			—		—			72
Other costs and expenses		982		115			2		304			1,403
Total costs and expenses		2,115		135			6		351			2,607
Operating income (loss)	$	2,848	$	20		$	29	$	(380	)	$	2,517
Net properties and equipment	$	11,690	$	357		$	1,192	$	324		$	13,563
Capital expenditures	$	2,417	$	57		$	—	$	36		$	2,510
Goodwill	$	1,202	$	—		$	—	$	—		$	1,202

97

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

16. Segment and Geographic Information (Continued)

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

	2006		2005		2004
millions
Revenues
United States	$	8,293	$	4,573	$	4,131
Algeria		1,526		1,292		770
Other International		368		322		223
Total	$	10,187	$	6,187	$	5,124

	2006		2005
millions
Net Properties and Equipment
United States	$	45,622	$	13,518
Algeria		806		843
Other International		2,311		834
Total	$	48,739	$	15,195

17. Other Taxes

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

	2006		2005		2004
Production and severance	$	339	$	213	$	157
Ad valorem		187		121		112
Payroll and other		49		24		23
Total	$	575	$	358	$	292

18. Severance Expenses

During 2006, general and administrative expense includes $77 million and oil and gas operating expense includes $5 million related to severance and benefits associated with the Company’s post acquisition asset realignment and restructuring efforts.

98

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

19. Income Taxes

Components of income tax expense are as follows:

	2006			2005		2004
millions
Current
Federal	$	291		$	327	$	283
State		25			2		22
Foreign		616			523		283
Total		932			852		588
Deferred
Federal		692			363		175
State		(63	)		64		35
Foreign		(119	)		53		1
Total		510			480		211
Total	$	1,442		$	1,332	$	799

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

	2006			2005			2004
millions
Income from continuing operations before income taxes
Domestic	$	3,389		$	2,356		$	1,544
Foreign		849			1,049			556
Total	$	4,238		$	3,405		$	2,100
Statutory tax rate		35	%		35%			35	%
Tax computed at statutory rate	$	1,483		$	1,192		$	735
Adjustments resulting from:
State income taxes (net of federal income tax benefit)		(24	)		43			37
Foreign taxes in excess of federal statutory tax rate		159			157			38
Excess U.S. foreign tax credit generated		(195	)		(79	)		––
Other — net		19			19			(11	)
Total income tax expense	$	1,442		$	1,332		$	799
Effective tax rate		34	%		39%			38	%

The effect of stock-based compensation deducted for tax purposes in excess of amounts recognized for financial accounting purposes has been credited directly to paid-in capital in amounts of $45 million, $53 million and $36 million for 2006, 2005 and 2004, 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 previous restructuring of the Company’s Venezuelan operations was reversed to income.

99

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

19. Income Taxes (Continued)

The Company is currently under examination by the Internal Revenue Service (IRS), and 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 2006 and 2005 that deferred tax liabilities related to pre-acquisition tax contingencies of approximately $45 million and $101 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.

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets (liabilities) at December 31, 2006 and 2005 are as follows:

	2006			2005
millions
Net current deferred tax assets	$	7		$	9
Net current deferred tax liability		(426	)		(6	)
Oil and gas exploration and development operations		(12,137	)		(3,264	)
Mineral operations		(433	)		(443	)
Other depreciable properties		(1,403	)		(117	)
Other		(81	)		(538	)
Gross long-term deferred tax liabilities		(14,054	)		(4,362	)
Oil and gas exploration and development costs		107			71
Net operating loss carryforward		303			88
Foreign tax credit carryforward		—			83
Other		792			338
Gross long-term deferred tax assets		1,202			580
Less: valuation allowance on deferred tax assets not expected to be realized		(388	)		(211	)
Net long-term deferred tax assets		814			369
Net long-term deferred tax liabilities		(13,240	)		(3,993	)
Total deferred taxes	$	(13,659	)	$	(3,990	)

Total deferred taxes at December 31, 2006 and 2005 include state deferred taxes of approximately $607 million and $213 million, respectively. Total deferred taxes as of December 31, 2006 and 2005 also include foreign deferred taxes of approximately $606 million and $280 million, respectively.

At December 31, 2006 and 2005, the Company had income taxes receivable of $899 million and $256 million, respectively, that are included in accounts receivable other.

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.

100

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

19. Income Taxes (Continued)

Tax carryforwards at December 31, 2006, which are available for utilization on future income tax returns, are as follows:

	Domestic		Foreign		Domestic Expiration	Foreign Expiration
millions
Net operating loss — regular tax	$	—	$	7	—	2009
Net operating loss — state	$	4,713	$	—	2007-2026	—

20. Commitments

Leases  The Company has long-term drilling rig commitments that meet the operating lease criteria, totaling $4.4 billion. The Company also has various commitments under noncancelable operating lease agreements of $1.1 billion for production platforms and equipment, buildings, facilities and aircraft. These operating leases expire at various dates through 2024. Certain of these operating leases contain residual value guarantees at the end of the lease term, however, at December 31, 2006, no material liabilities were accrued for these guarantees. At December 31, 2006, future minimum lease payments under operating leases are as follows:

	Operating Leases
millions
2007	$	1,297
2008		1,650
2009		1,099
2010		634
2011		284
Later years		551
Total future minimum lease payments	$	5,515

Total rental expense, net of sublease income, amounted to $125 million in 2006 and $40 million in both 2005 and 2004. Total rental expense includes contingent rental expense related to processing fees of $14 million and $7 million in 2006 and 2005, respectively.

Drilling Rig Commitments  During 2006 and 2005, Anadarko entered into various agreements to secure a portion of the drilling rigs necessary to execute its drilling plans over the next several years. The table of future minimum lease payments above includes approximately $3.8 billion for nine offshore drilling vessels and $636 million for certain contracts for onshore United States drilling rigs. 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 install and own Independence Hub, a semi-submersible platform in the deepwater Gulf of Mexico. The platform structure, expected to be mechanically complete in 2007, 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.

101

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

20. Commitments (Continued)

The Company is also a party to 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 table of future minimum lease payments above includes $212 million related to the monthly demand charge for these agreements. The agreements do not contain any purchase options, purchase obligations or value guarantees.

Spar Platform and Production Vessel Leases  As part of the Kerr-McGee acquisition, Anadarko became responsible for operating leases related to certain spar platforms in the Gulf of Mexico and a floating production, storage and offloading vessel in China. The table of future minimum lease payments above includes approximately $559 million for these agreements. These agreements also contain residual value guarantees totaling $37 million at the end of the lease periods.

Buildings  The table of future minimum lease payments above includes the Company’s lease payment obligations of $92 million related to office building leases. The Company leases two corporate office buildings located in The Woodlands, Texas. The lease term is seven years and 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, 2006, the Company was in compliance with these covenants. The Company has provided a residual value guarantee for any deficiency of up to $187 million if the properties are sold for less than the lease balance. 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 $46 million related to aircraft leases. Some of these leases provide for a residual value guarantee for any deficiency if the aircraft are sold for less than the sale option amount (approximately $27 million). In addition, the Company is entitled to any proceeds from a sale of the aircraft in excess of the sale option amount.

Other Equipment Leases  Included in the table of future minimum lease payments above are lease payments of approximately $120 million related to equipment associated with various gas gathering and processing systems. In the event the Company does not purchase the equipment at the end of the leases, the Company may be required to make payments in connection with residual value guarantees ranging from $27 million to $35 million.

Other Commitments  In the normal course of business, the Company enters into other contractual agreements to purchase natural gas or crude oil, pipeline capacity, storage capacity, utilities and other services. Aggregate future payments under these contracts total $1.53 billion, of which $211 million is expected to be paid in 2007, $411 million in 2008, $217 million in 2009, $182 million in 2010, $170 million in 2011 and $341 million thereafter.

During the third quarter of 2006, the precedent agreements the Company had entered into to secure transportation of natural gas upon completion of its Bear Head LNG facility were terminated.

102

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

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

Pension Plans and Other Postretirement Benefits  The Company has non-contributory defined benefit pension plans, including both qualified and supplemental plans, and a foreign contributory defined benefit pension plan. The Company also provides certain health care and life insurance benefits for retired employees. Health care benefits are funded by contributions from the Company and the retiree. The Company’s retiree life insurance plan is noncontributory. The Company uses a December 31 measurement date for each of the plans, with the exception of one plan which has a measurement date of September 30.

The following activities and balances include amounts associated with Anadarko’s Canadian operations that were sold in the fourth quarter of 2006 and are presented as discontinued operations in the accompanying consolidated financial statements.

In 2006, the Company made contributions of $59 million to its funded pension plans, $86 million to its unfunded pension plans and $14 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 2007, the Company expects to contribute $13 million to its funded pension plans, $50 million to its unfunded pension plans and $21 million to its unfunded other postretirement benefit plans.

As discussed in Note 1, Anadarko adopted SFAS No. 158 as of December 31, 2006. SFAS No. 158 requires the Company, among other things, to recognize the overfunded or underfunded status of each defined benefit postretirement plan in its balance sheet, measured as the difference between the fair value of plan assets and the benefit obligation, and recognize changes in the funded status of a plan during the reporting period as a component of accumulated comprehensive income (loss). The following table presents the effect of adopting SFAS No. 158 on Anadarko’s December 31, 2006 consolidated balance sheet.

millions	Balances Prior to SFAS No. 158 Adoption			Adjustments			Balances After SFAS No. 158 Adoption
Other assets	$	1,018		$	(153	)	$	865
Accrued expenses		1,719			20			1,739
Deferred income taxes		13,346			(106	)		13,240
Other long-term liabilities—other		2,293			120			2,413
Accumulated other comprehensive income (loss)		(147	)		(187	)		(334	)

As of December 31, 2006, components of accumulated other comprehensive income (loss) associated with the pension and other postretirement benefit plans and the related amounts expected to be amortized to net periodic benefit cost in 2007 are as follows.

millions	Pension Benefits			Other Benefits
Accumulated other comprehensive income (loss), before income taxes
Prior service cost	$	(5	)	$	(7	)
Net actuarial loss		(255	)		(42	)
	$	(260	)	$	(49	)
Amounts expected to be recognized in 2007 net periodic benefit cost
Prior service cost	$	1		$	—
Net actuarial loss		13			2
	$	14		$	2

103

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

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

The following table sets forth changes in the benefit obligations and fair value of plan assets for the Company’s pension and other postretirement benefit plans for the years ended December 31, 2006 and 2005, as well as the funded status of the plans and amounts recognized in the financial statements as of December 31, 2006 and 2005.

	Pension Benefits						Other Benefits
	2006			2005			2006			2005
millions
Change in benefit obligations
Benefit obligations at beginning of year	$	762		$	675		$	188		$	164
Service cost		49			36			16			15
Interest cost		59			38			13			9
Plan amendments		—			—			7			—
Settlements		5			—			—			—
Actuarial (gain) loss		43			61			(1	)		6
Contributions by plan participants		1			—			4			2
Benefit payments		(190	)		(45	)		(18	)		(8	)
Foreign currency exchange rate changes		8			(3	)		—			—
Acquisition of Kerr-McGee		784			—			137			—
Sale of Canadian operations		(34	)		—			(3	)		—
Benefit obligations at end of year	$	1,487		$	762		$	343		$	188
Change in plan assets
Fair value of plan assets at beginning of year	$	588		$	475		$	—		$	—
Actual return on plan assets		135			38			—			—
Employer contributions		145			121			14			6
Contributions by plan participants		1			—			4			2
Benefit payments		(190	)		(45	)		(18	)		(8	)
Foreign currency exchange rate changes		6			(1	)		—			—
Acquisition of Kerr-McGee		580			—			—			—
Sale of Canadian operations		(46	)		—			—			—
Fair value of plan assets at end of year	$	1,219		$	588		$	—		$	—
Funded status of the plans at end of year	$	(268	)	$	(174	)	$	(343	)	$	(188	)
Unrecognized actuarial loss		n/a			314			n/a			47
Unrecognized prior service cost		n/a			6			n/a			1
Total recognized		n/a		$	146			n/a		$	(140	)
Total recognized amounts in the balance sheet consist of:
Other assets	$	—		$	170		$	—		$	—
Accrued expenses		(50	)		—			(21	)		—
Other long-term liabilities—other		(218	)		(49	)		(322	)		(140	)
Total recognized	$	(268	)	$	121		$	(343	)	$	(140	)

104

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

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

The accumulated benefit obligation for all defined benefit pension plans was $1.2 billion and $589 million as of December 31, 2006 and 2005, respectively. For the Company’s defined benefit pension plans with accumulated benefit obligations in excess of plan assets, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets were $815 million, $710 million and $611 million, respectively, as of December 31, 2006, and $57 million, $49 million and zero, respectively, as of December 31, 2005. The Company’s benefit obligations under selected unfunded pension plans are secured by the Anadarko Petroleum Corporation Executives and Directors Benefits Trust. See Note 13.

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

	Pension Benefits									Other Benefits
	2006			2005			2004			2006		2005			2004
millions
Components of net periodic benefit cost
Service cost	$	49		$	36		$	24		$	16	$	15		$	11
Interest cost		59			38			32			14		9			9
Expected return on plan assets		(64	)		(38	)		(33	)		—		—			—
Settlements		8			—			—			—		—			—
Special termination benefits		—			—			1			—		—			—
Amortization of transition asset		—			—			(1	)		—		—			—
Amortization of prior service cost (credit)		1			1			1			1		(1	)		(1	)
Amortization of actuarial loss		20			17			11			3		3			4
Net periodic benefit cost	$	73		$	54		$	35		$	34	$	26		$	23

The increase (decrease) in the Company’s pension liability included in other comprehensive income related to the pension plans was $(10) million, $(96) million and $31 million for 2006, 2005 and 2004, respectively, before income taxes.

Following are the weighted-average assumptions used by the Company in determining the pension and other postretirement benefit obligations as of December 31, 2006 and 2005:

	Pension Benefits				Other Benefits
	2006		2005		2006		2005
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.

105

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

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

Following are the weighted-average assumptions used by the Company in determining the net periodic pension and other postretirement benefit cost for 2006, 2005 and 2004:

	Pension Benefits						Other Benefits
	2006		2005		2004		2006		2005		2004
percent
Discount rate	5.75	%	5.75	%	6.25	%	5.75	%	5.75	%	6.25	%
Long-term rate of return on plan assets	7.75	%	8.0	%	8.0	%	n/a		n/a		n/a
Rates of increase in compensation levels	5.0	%	5.0	%	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 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 55%-65% equity securities, 25%-35% fixed income and zero to 10% other. 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, 2006 and 2005 were comprised of assets by category as follows:

	2006		2005
percent
Assets
Equity securities	67	%	79	%
Fixed income	29		19
Other	4		2
Total	100	%	100	%

There are no direct investments in Anadarko securities included in plan assets; however, there may be indirect investments in Anadarko securities through the plans’ mutual fund investments. The expected long-term rate of return on assets assumption was determined using the year-end 2006 pension investment balances by category and projected target asset allocations for 2007. 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.

106

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

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

The following benefit payments, which reflect expected future service as appropriate, are expected to be paid as follows:

	Pension Benefit Payments		Other Benefit Payments
millions
2007	$	226	$	21
2008		88		20
2009		91		21
2010		99		22
2011		108		23
2012-2016		657		132

For year-end 2006 measurement purposes, the Company used separate assumptions of cost increase rates for medical, prescription drugs and dental benefits covered by the plans. An 8% annual rate of increase in the per capita cost of covered medical benefits was assumed for 2006, decreasing gradually to 5% in 2015 and later years. For prescription drug benefits, a rate of increase of 13% in the per capita cost was assumed for 2006, decreasing gradually to 5% in 2015 and later years. For dental care costs, the Company assumed a flat rate of increase of 5%. For year-end 2005 measurement purposes, the Company used a single composite rate of cost increase assumption, which was an 11% annual rate of increase in the per capita cost of covered health care benefits for 2005, 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	$	3	$	(2	)
Effect on other postretirement benefit obligation	$	22	$	(18	)

Employee Savings Plan  The Company has employee savings plans (ESP), which are defined contribution plans. 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 $20 million for 2006 and $14 million in each of the years 2005 and 2004. 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.

22. Contingencies

General  Litigation charges of $16 million, $64 million and $62 million were expensed during 2006, 2005 and 2004, respectively. The Company is a defendant in a number of lawsuits and is involved in governmental proceedings arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims and environmental claims. The Company has also been named as a defendant in various personal injury claims, including claims by employees of third-party contractors alleging exposure to asbestos, silica and benzene while working at refineries (previously owned by predecessors of acquired companies) located in Texas, California and Oklahoma. While the ultimate outcome and impact on the Company cannot be predicted with

107

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

22. Contingencies (Continued)

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. The Company was named as a defendant in a case styledU.S. of America ex rel. Harold E. Wright v. AGIP Company, et al. filed in September 2000 in the U.S. District Court for the Eastern District of Texas, Lufkin Division. Kerr-McGee was also named as a defendant in this legal proceeding. This lawsuit generally alleges that the Company, including Kerr-McGee and 117 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 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 and the court has set a trial date for fall 2007. Kerr-McGee has reached a settlement with the government, however, the court has permitted Mr. Wright to conduct additional discovery to test the reasonableness of the settlement. Discovery is currently underway. Management has accrued a liability for the potential settlement.

Deepwater Royalty Relief Act  In 1995, the United States Congress passed the Deep Water Royalty Relief Act (DWRRA) to stimulate exploration and production of oil and natural gas by providing relief from the obligation to pay royalty on certain federal leases located in the deep waters of the Gulf of Mexico. After the passage of the DWRRA, the Minerals Management Service (MMS) included price thresholds on leases issued in 1996, 1997 and 2000 that eliminated this royalty relief if these price thresholds were exceeded. The 1998 and 1999 leases did not contain price threshold provisions. Anadarko currently owns interests in several deepwater Gulf of Mexico leases granted during the 1996-2000 time period (some originally owned by Kerr-McGee). In January 2006, the Department of the Interior (DOI) ordered Kerr-McGee Oil and Gas Corporation (KMOG) to pay oil and gas royalties and accrued interest on KMOG’s deepwater Gulf of Mexico production associated with eight 1996, 1997 and 2000 leases, for which KMOG believes royalties are suspended under the DWRRA. MMS is an agency of DOI. DOI issued the Order to Pay based on the assertion that DOI has the discretion to eliminate royalty relief under the DWRRA when oil and gas prices exceed certain levels specified by DOI. KMOG believes that DOI does not have the discretion to eliminate royalty relief on the DWRRA leases issued 1996 through 2000 and, accordingly, is contesting the Order to Pay additional royalties. In that regard, on March 17, 2006, KMOG filed a lawsuit in the U.S. District Court for the Western District of Louisiana against DOI for injunctive and declaratory relief with respect to DOI’s claims for additional royalties. KMOG and DOI have agreed to mediate the dispute voluntarily. By order of the court in the KMOG litigation, KMOG and DOI will report on March 1, 2007 to the court as to the status of their mediation efforts. Management believes it has adequately accrued reserves for any potential liability under the 1996, 1997 and 2000 leases that contain price thresholds. Given that, under the applicable statutes, regulations and lease terms attributable to the 1998 and 1999 leases, no royalties are owed on production from the lease until the applicable royalty suspension volumes are exhausted, no amounts have been accrued for potential royalty payments under those leases.

108

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

22. Contingencies (Continued)

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

In 2006, the Company recorded a $103 million liability and production tax expense (included in other taxes in the statement of income) for exceptional profits tax based on the assumption that the tax applies only to production value in excess of $30 per barrel. If the exceptional profits tax is applied to the full value of production, Anadarko estimates the 2006 liability for exceptional profits tax would be $190 million. The Company has not concluded as to the probable interpretation of the law, but is continuing to monitor further guidance to determine the law’s ultimate application.

In response to the Algerian government’s imposition of the exceptional profits tax, the Company has notified Sonatrach of its disagreement with the proposed collection of the exceptional profits tax. The Company believes that the PSC provides fiscal stability through several of its provisions. At this time, the Company cannot determine the ultimate outcome of any possible negotiations, or any potential recourse to conciliation, or arbitration by either side.

Other Guarantees and Indemnifications  Under the terms of the Master Separation Agreement entered into between Kerr-McGee and Tronox Incorporated (Tronox), a former wholly-owned subsidiary that held Kerr-McGee’s chemical business, Kerr-McGee agreed to reimburse Tronox for 50% of certain qualifying environmental remediation costs incurred and paid by Tronox and its subsidiaries before November 28, 2012, subject to certain limitations and conditions. The reimbursement obligation is limited to a maximum aggregate reimbursement of $100 million. The Company has recognized a liability of $59 million associated with this reimbursement obligation in connection with the acquisition of Kerr-McGee.

The Company is guarantor for specific financial obligations of a trona mining affiliate. The investment in this entity 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 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, $32 million under term loans 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, 2006.

In connection with its various acquisitions, the Company routinely indemnifies the former officers and directors of acquired companies in respect to acts or omissions occurring prior to the effective date of the acquisition. The Company also agrees to maintain directors’ and officers’ liability insurance on these individuals with respect to acts or omissions occurring prior to the acquisition, generally for a period of six years. No liability has been recognized for these indemnifications.

The Company also provides certain indemnifications in relation to dispositions of assets. These indemnifications typically relate to disputes, litigation or tax matters existing at the date of disposition. In connection with the sale of the Canadian subsidiary in 2006, the Company indemnified the purchaser for certain 2006 transactions entered into in anticipation of sale and for potential future audit adjustments that may be imposed by the Canadian taxing authorities for tax years prior to the sale. The Company believes it is probable

109

ANADARKO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

22. Contingencies (Continued)

that these losses will have to be settled with the purchaser in cash. The Company has a $194 million liability recorded for the contingency.

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.

Anadarko is also subject to various environmental remediation and reclamation obligations arising from federal, state and local laws and regulations. As of December 31, 2006, the Company’s balance sheet included an $87 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.

110

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

The following is historical revenue and cost information relating to the Company’s oil and gas activities. The discontinued operations presented on the following pages are associated with the Company’s Canadian operations.

Algeria Developments   Uncertainty exists as to whether the exceptional profits tax, as discussed in Note 22, will apply to the full value of production or only to the value of production in excess of $30 per barrel. Results of operations for 2006, as well as December 31, 2006 reserve quantities and standardized measure of discounted future cash flows for the Company’s Algerian operations were determined assuming the exceptional profits tax applies to production value in excess of $30 per barrel. Should the exceptional profits tax be applied to the entire value of production, the Company’s production volumes and revenues would be unaffected, but the expense and cash flows for production taxes would be greater than assumed.

The Company currently has 111 million barrels of proved undeveloped reserves in Algeria, the economics of which are sensitive to the exceptional profits tax. Anadarko is reviewing whether these reserves remain economic under existing development plans if the exceptional profits tax is applied to the entire production value. The Company is not yet in a position to confirm the probable interpretation of the law, but is continuing to monitor further guidance to determine the law’s ultimate application. The Company believes that the PSC provides fiscal stability through several of its provisions. At this time, the Company cannot determine the ultimate outcome of any possible negotiations, or any potential recourse to conciliation, or arbitration by either side.

Other International Developments  Due to contract and structural changes imposed by the Government of Venezuela, Anadarko’s investment in Venezuela oil and gas properties, governed by an operating service agreement, was converted into an 18% equity interest in a new operating company in October 2006. The oil and gas results for Venezuela are included in the following information under Other International through the conversion date. The following information excludes the Company’s share of its equity investment in Venezuela due to immateriality.

Costs Excluded

Costs associated with unproved properties and major development projects related to continuing operations of $14.7 billion and $1.2 billion as of December 31, 2006 and 2005, 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 Dec. 31, 2006
millions	Prior Years		2004		2005		2006
Property acquisition	$	498	$	51	$	152	$	437	$	1,138
Exploration		26		24		39		13,318		13,407
Capitalized interest		61		10		17		50		138
Total	$	585	$	85	$	208	$	13,805	$	14,683

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SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

millions	United States			Algeria			Other Int’l			Total Continuing Operations			Discontinued Operations			Total
Costs Excluded by Country at December 31, 2006
Property acquisition	$	1,132		$	—		$	6		$	1,138			—		$	1,138
Exploration		11,862			15			1,530			13,407			—			13,407
Capitalized interest		112			1			25			138			—			138
Total	$	13,106		$	16		$	1,561		$	14,683			—		$	14,683
Changes in Costs Excluded by Country
December 31, 2004	$	1,311		$	6		$	148		$	1,465		$	177		$	1,642
Additional costs incurred		691			7			64			762			62			824
Costs transferred to DD&A pool		(935	)		(8	)		(86	)		(1,029	)		(130	)		(1,159	)
Impact of foreign currency rate		—			—			—			—			2			2
December 31, 2005		1,067			5			126			1,198			111			1,309
Additional costs incurred		12,627			12			1,506			14,145			—			14,145
Costs transferred to DD&A pool		(588	)		(1	)		(71	)		(660	)		—			(660	)
Sale of discontinued operations		—			—			—			—			(111	)		(111	)
December 31, 2006	$	13,106		$	16		$	1,561		$	14,683		$	—		$	14,683
Capitalized Costs Related to Oil and Gas Activities
2006
Capitalized
Unproved properties	$	13,106		$	16		$	1,561		$	14,683		$	—		$	14,683
Proved properties		34,514			1,337			1,029			36,880			—			36,880
		47,620			1,353			2,590			51,563			—			51,563
Accumulated DD&A		7,900			553			308			8,761			—			8,761
Net capitalized costs	$	39,720		$	800		$	2,282		$	42,802		$	—		$	42,802
2005
Capitalized
Unproved properties	$	1,067		$	5		$	126		$	1,198		$	111		$	1,309
Proved properties		17,282			1,262			1,144			19,688			5,148			24,836
		18,349			1,267			1,270			20,886			5,259			26,145
Accumulated DD&A		6,627			432			547			7,606			2,611			10,217
Net capitalized costs	$	11,722		$	835		$	723		$	13,280		$	2,648		$	15,928

112

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Costs Incurred in Oil and Gas Activities

millions	United States			Algeria		Other Int’l		Total Continuing Operations			Discontinued Operations		Total
2006
Property acquisition
Unproved	$	11,974		$	—	$	1,405	$	13,379		$	54	$	13,433
Proved		13,893			3		600		14,496			1		14,497
Exploration		769			23		111		903			106		1,009
Development (1)		2,965			58		56		3,079			414		3,493
Total Costs Incurred	$	29,601		$	84	$	2,172	$	31,857		$	575	$	32,432
2005
Property acquisition
Unproved	$	216		$	—	$	13	$	229		$	40	$	269
Proved		44			—		—		44			1		45
Exploration		527			12		49		588			134		722
Development (1)		1,854			45		60		1,959			319		2,278
Total Costs Incurred	$	2,641		$	57	$	122	$	2,820		$	494	$	3,314
2004
Property acquisition
Unproved	$	123		$	—	$	12	$	135		$	20	$	155
Proved		(1	)		—		—		(1	)		4		3
Exploration		339			20		28		387			126		513
Development (1)		1,809			40		70		1,919			429		2,348
Total Costs Incurred	$	2,270		$	60	$	110	$	2,440		$	579	$	3,019

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

	2006		2005		2004
millions
United States	$	1,161	$	367	$	861
Algeria		34		28		22
Other International		16		34		29
Total Continuing Operations	$	1,211	$	429	$	912

113

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. 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.

		United States		Algeria		Other Int’l			Total Continuing Operations		Discontinued Operations		Total
millions
2006
Net revenues from production
Third-party sales		$	4,712	$	518	$	247		$	5,477	$	515	$	5,992
Sales to consolidated affiliates			2,779		1,008		121			3,908		180		4,088
	��		7,491		1,526		368			9,385		695		10,080
Production costs
Oil and gas operating			690		42		67			799		109		908
Oil and gas transportation and other			317		23		1			341		—		341
Production related general and administrative expenses			60		1		2			63		44		107
Other taxes			420		103		2			525		11		536
			1,487		169		72			1,728		164		1,892
Depreciation, depletion and amortization			1,599		119		118			1,836		139		1,975
Impairments related to oil and gas properties			—		—		249			249		4		253
			4,405		1,238		(71	)		5,572		388		5,960
Income tax expense			1,578		510		(45	)		2,043		146		2,189
Results of operations		$	2,827	$	728	$	(26	)	$	3,529	$	242	$	3,771
DD&A rate per net equivalent barrel		$	10.84	$	5.11	$	15.59		$	10.30	$	8.30	$	10.12

114

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Results of Operations for Producing Activities (Continued)

	United States		Algeria		Other Int’l		Total Continuing Operations		Discontinued Operations		Total
millions
2005
Net revenues from production
Third-party sales	$	1,688	$	455	$	208	$	2,351	$	877	$	3,228
Sales to consolidated affiliates		2,808		837		113		3,758		36		3,794
		4,496		1,292		321		6,109		913		7,022
Production costs
Oil and gas operating		309		34		57		400		107		507
Oil and gas transportation and other		233		23		—		256		16		272
Production related general and administrative expenses		36		10		4		50		49		99
Other taxes		317		—		7		324		19		343
		895		67		68		1,030		191		1,221
Depreciation, depletion and amortization		833		97		109		1,039		223		1,262
Impairments related to oil and gas properties		—		—		78		78		—		78
		2,768		1,128		66		3,962		499		4,461
Income tax expense		969		429		36		1,434		190		1,624
Results of operations	$	1,799	$	699	$	30	$	2,528	$	309	$	2,837
DD&A rate per net equivalent barrel	$	7.84	$	4.08	$	13.33	$	7.52	$	11.02	$	7.96
2004
Net revenues from production
Third-party sales	$	1,621	$	203	$	146	$	1,970	$	849	$	2,819
Sales to consolidated affiliates		2,430		567		79		3,076		96		3,172
		4,051		770		225		5,046		945		5,991
Production costs
Oil and gas operating		390		34		57		481		160		641
Oil and gas transportation and other		195		22		—		217		26		243
Production related general and administrative expenses		28		9		5		42		49		91
Other taxes		267		—		3		270		21		291
		880		65		65		1,010		256		1,266
Depreciation, depletion and amortization		896		90		75		1,061		305		1,366
Impairments related to oil and gas properties		—		—		72		72		—		72
		2,275		615		13		2,903		384		3,287
Income tax expense		796		234		7		1,037		150		1,187
Results of operations	$	1,479	$	381	$	6	$	1,866	$	234	$	2,100
DD&A rate per net equivalent barrel	$	6.82	$	4.06	$	9.31	$	6.57	$	10.55	$	7.17

115

ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION

AND PRODUCTION ACTIVITIES

(Unaudited)

Oil and Gas Reserves

The following table shows estimates 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 PSA. The reserves include estimated quantities allocated to Anadarko for recovery of costs and Algerian income 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 2006 primarily due to the acquisitions of Kerr-McGee and Western and successful exploration and development drilling onshore in the United States, partially offset by the disposition of Canadian properties and downward revisions primarily related to the K2 complex in the Gulf of Mexico, adjustments in Algeria (not related to the exceptional profits tax) and a decrease in natural gas prices. 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 estimates of proved reserves are made using available geological and reservoir data as well as production performance data. These estimates 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.

In 2006, reserves associated with each of the legacy companies (Anadarko, Kerr-McGee and Western) were subjected to somewhat different internal and external processes in order to develop and validate the reserve estimates.

Anadarko Anadarko legacy proved reserve estimates were made by the Company’s engineers. Anadarko’s internal controls over reserve additions include using a corporate review team comprised of six technical experts: five members from within Anadarko, who are independent of the operating groups responsible for the reserve estimates, and a member from Netherland, Sewell & Associates, Inc. (NSAI). Through participation on the team, NSAI reviewed 96% of Anadarko legacy 2006 proved reserve additions.

The procedures and controls used in preparing the Company’s estimates of proved reserves for Anadarko legacy properties, as of December 31, 2006, were examined by NSAI. NSAI’s examination did not include certain properties for which sales were pending at December 31, 2006. NSAI was able to determine that Anadarko’s estimates of proved oil and gas reserves for Anadarko legacy properties 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. NSAI’s examination of Anadarko legacy properties consisted of: (1) a review and verification of the internal reserves management including the Company’s policies, expectations, and control systems; (2) a series of reviews with each of Anadarko’s asset teams to investigate conformance with SEC definitions and guidelines; and, (3) substantive testing of Anadarko legacy reserve estimates including detailed independent evaluation and comparison of the Company’s estimates to NSAI’s estimates for 31 major properties making up more than 70% of Anadarko’s legacy proved reserve base and present worth discounted at 10%.

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Oil and Gas Reserves (Continued)

Kerr-McGee Kerr-McGee legacy proved reserve estimates were made by the Company’s engineers. The reviews by NSAI of Kerr-McGee legacy properties were to verify that the reserve estimates were prepared in accordance with the guidelines and definitions of the SEC using generally accepted petroleum engineering and evaluation principles and to determine, for the properties reviewed, the reasonableness of the Company’s methods, procedures, and estimates. The reviews focused on reserve determination methodologies, procedures, and the data used in preparing these estimates. NSAI was able to express the opinion that the reviews were sufficient to determine that the general methods and procedures used by the Company in estimating the reserves for the legacy Kerr-McGee properties are reasonable and that the estimates for those properties reviewed have been prepared in accordance with SEC guidelines and definitions using generally accepted petroleum engineering and evaluation principles. The NSAI reviews of legacy Kerr-McGee properties were a review of procedures, methods and certain internal estimates only, and do not constitute a complete review, study or audit of the estimated proved reserves and future revenue for the Kerr-McGee legacy properties.

WesternWestern legacy proved reserve estimates were prepared by NSAI and represent oil and gas properties located in Colorado, Montana, New Mexico, Utah, and Wyoming. The reserve estimates in the NSAI report are estimates only and should not be construed as exact quantities. The titles to the properties were not examined by NSAI, nor was the actual degree or type of interest owned independently confirmed. The data used in the NSAI estimates was obtained from the Company, other interest owners, various operators of the properties, public data sources and the nonconfidential files of NSAI and were accepted as accurate.

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. About 37% of the Company’s PUDs booked prior to 2004 are in Algeria and are being developed according to an Algerian government approved plan. The remaining PUDs booked prior to 2004 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, 2006:

MMBOE	United States		Algeria		Other Int’l		Total		% of Total Proved Reserves
Year added
2006	581		—		14		595		20	%
2005	79		8		—		87		3	%
2004	69		4		—		73		2	%
2003	122		10		—		132		4	%
2002	2		7		—		9		1	%
Prior years	44		82		—		126		4	%
Total Proved Undeveloped Reserves	897		111		14		1,022		34	%
Total Proved Reserves	2,672		287		52		3,011
Percentage of Total Proved Reserves	34	%	39	%	27	%	34	%

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Oil and Gas Reserves (Continued)

The following table compares the December 31, 2006 PUDs to the December 31, 2005 and 2004 PUDs by year added. It illustrates the Company’s effectiveness in converting PUDs to developed reserves.

MMBOE	2006	2005	2004	% Reduction 2005-2006		% Reduction 2004-2006
Year added
2006	595	—	—	n/a		n/a
2005	87	295	—	71	%	n/a
2004	73	208	310	65	%	76	%
2003	132	191	221	31	%	40	%
2002	9	46	64	80	%	86	%
Prior years	126	185	255	32	%	51	%
Total Proved Undeveloped Reserves	1,022	925	850

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Oil and Gas Reserves (Continued)

	Natural Gas (Bcf)
	United States		Other Int’l		Total Continuing Operations		Discontinued Operations		Total
Proved Reserves
December 31, 2003	6,087		144		6,231		1,493		7,724
Revisions of prior estimates
Performance	(245	)	9		(236	)	(36	)	(272	)
Price-related	(4	)	—		(4	)	1		(3	)
Extensions, discoveries and other additions	1,387		—		1,387		227		1,614
Improved recovery	—		—		—		(1	)	(1	)
Purchases in place	10		—		10		3		13
Sales in place	(643	)	—		(643	)	(267	)	(910	)
Production	(499	)	—		(499	)	(138	)	(637	)
December 31, 2004	6,093		153		6,246		1,282		7,528
Revisions of prior estimates
Performance	29		—		29		(35	)	(6	)
Price-related	28		—		28		1		29
Extensions, discoveries and other additions	912		—		912		188		1,100
Improved recovery	—		—		—		—		—
Purchases in place	28		—		28		2		30
Sales in place	(98	)	(153	)	(251	)	(4	)	(255	)
Production	(414	)	—		(414	)	(102	)	(516	)
December 31, 2005	6,578		—		6,578		1,332		7,910
Revisions of prior estimates
Performance	(474	)	—		(474	)	—		(474	)
Price-related	(477	)	—		(477	)	(14	)	(491	)
Extensions, discoveries and other additions	1,151		—		1,151		31		1,182
Improved recovery	11		—		11		—		11
Purchases in place	4,256		—		4,256		—		4,256
Sales in place	(1	)	—		(1	)	(1,263	)	(1,264	)
Production	(558	)	—		(558	)	(86	)	(644	)
December 31, 2006	10,486		—		10,486		—		10,486
Proved Developed Reserves
December 31, 2003	4,725		—		4,725		1,164		5,889
December 31, 2004	4,469		—		4,469		997		5,466
December 31, 2005	4,553		—		4,553		1,024		5,577
December 31, 2006	7,618		—		7,618		—		7,618
Proved Undeveloped Reserves
December 31, 2003	1,362		144		1,506		329		1,835
December 31, 2004	1,624		153		1,777		285		2,062
December 31, 2005	2,025		—		2,025		308		2,333
December 31, 2006	2,868		—		2,868		—		2,868

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Oil and Gas Reserves (Continued)

	Oil, Condensate and NGLs (MMBbls)
	United States		Algeria		Other Int’l		Total Continuing Operations		Discontinued Operations		Total
Proved Reserves
December 31, 2003	691		361		109		1,161		65		1,226
Revisions of prior estimates
Performance	4		—		(4	)	—		(5	)	(5	)
Price-related	(5	)	7		(5	)	(3	)	1		(2	)
Extensions, discoveries and other additions	66		4		—		70		5		75
Improved recovery	42		—		—		42		(1	)	41
Purchases in place	1		—		—		1		—		1
Sales in place	(119	)	—		—		(119	)	(19	)	(138	)
Production	(48	)	(22	)	(9	)	(79	)	(6	)	(85	)
December 31, 2004	632		350		91		1,073		40		1,113
Revisions of prior estimates
Performance	—		(20	)	(16	)	(36	)	—		(36	)
Price-related	3		14		(9	)	8		1		9
Extensions, discoveries and other additions	74		4		—		78		2		80
Improved recovery	45		—		—		45		—		45
Purchases in place	—		—		—		—		—		—
Sales in place	(9	)	—		—		(9	)	—		(9	)
Production	(37	)	(24	)	(8	)	(69	)	(3	)	(72	)
December 31, 2005	708		324		58		1,090		40		1,130
Revisions of prior estimates
Performance	(36	)	(20	)	(1	)	(57	)	—		(57	)
Price-related	(17	)	(1	)	2		(16	)	—		(16	)
Extensions, discoveries and other additions	18		6		—		24		—		24
Improved recovery	25		—		—		25		—		25
Purchases in place	281		—		40		321		—		321
Sales in place	—		—		(39	)	(39	)	(38	)	(77	)
Production	(54	)	(22	)	(8	)	(84	)	(2	)	(86	)
December 31, 2006	925		287		52		1,264		—		1,264
Proved Developed Reserves
December 31, 2003	451		182		65		698		48		746
December 31, 2004	350		176		51		577		29		606
December 31, 2005	340		195		31		566		28		594
December 31, 2006	505		176		38		719		—		719
Proved Undeveloped Reserves
December 31, 2003	240		179		44		463		17		480
December 31, 2004	282		174		40		496		11		507
December 31, 2005	368		129		27		524		12		536
December 31, 2006	420		111		14		545		—		545

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Oil and Gas Reserves (Continued)

	Total (MMBOE)
	United States		Algeria		Other Int’l		Total Continuing Operations		Discontinued Operations		Total
Proved Reserves
December 31, 2003	1,704		361		134		2,199		314		2,513
Revisions of prior estimates
Performance	(37	)	—		(3	)	(40	)	(11	)	(51	)
Price-related	(6	)	7		(5	)	(4	)	1		(3	)
Extensions, discoveries and other additions	297		4		—		301		43		344
Improved recovery	42		—		—		42		(1	)	41
Purchases in place	3		—		—		3		1		4
Sales in place	(226	)	—		—		(226	)	(64	)	(290	)
Production	(131	)	(22	)	(9	)	(162	)	(29	)	(191	)
December 31, 2004	1,646		350		117		2,113		254		2,367
Revisions of prior estimates
Performance	5		(20	)	(16	)	(31	)	(6	)	(37	)
Price-related	9		14		(10	)	13		1		14
Extensions, discoveries and other additions	226		4		—		230		34		264
Improved recovery	45		—		—		45		—		45
Purchases in place	5		—		—		5		—		5
Sales in place	(25	)	—		(25	)	(50	)	(1	)	(51	)
Production	(106	)	(24	)	(8	)	(138	)	(20	)	(158	)
December 31, 2005	1,805		324		58		2,187		262		2,449
Revisions of prior estimates
Performance	(115	)	(20	)	(1	)	(136	)	—		(136	)
Price-related	(98	)	(1	)	2		(97	)	(2	)	(99	)
Extensions, discoveries and other additions	210		6		—		216		5		221
Improved recovery	27		—		—		27		—		27
Purchases in place	990		—		40		1,030		—		1,030
Sales in place	—		—		(39	)	(39	)	(248	)	(287	)
Production	(147	)	(22	)	(8	)	(177	)	(17	)	(194	)
December 31, 2006	2,672		287		52		3,011		—		3,011
Proved Developed Reserves
December 31, 2003	1,238		182		65		1,485		242		1,727
December 31, 2004	1,095		176		51		1,322		195		1,517
December 31, 2005	1,099		195		31		1,325		199		1,524
December 31, 2006	1,775		176		38		1,989		—		1,989
Proved Undeveloped Reserves
December 31, 2003	466		179		69		714		72		786
December 31, 2004	551		174		66		791		59		850
December 31, 2005	706		129		27		862		63		925
December 31, 2006	897		111		14		1,022		—		1,022

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(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, 2006, the present value (discounted at 10%) of future net cash flows from Anadarko’s proved reserves was $25.6 billion, (stated in accordance with the regulations of the SEC and the FASB). The decrease of $3.7 billion or 12% in 2006 compared to 2005 is primarily due to a significant decrease in natural gas prices and the sale of Canadian operations, partially offset by increases associated with the Kerr-McGee and Western acquisitions. Derivative instruments that qualify as cash flow hedges have not been included in the estimates of future net cash flows. As of December 31, 2006, the undiscounted and discounted amounts related to cash flow hedges that would have reduced future net cash flows were $37 million and $33 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, 2006 are as follows:

	2007		2008		2009
millions
United States	$	1,747	$	1,430	$	1,229
Algeria		124		202		176
Other International		39		10		1
Total	$	1,910	$	1,642	$	1,406

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Standardized Measure of Discounted Future Net Cash Flows

Relating to Proved Oil and Gas Reserves

	United States		Algeria		Other Int’l		Total Continuing Operations		Discontinued Operations		Total
millions
2006
Future cash inflows	$	98,537	$	18,301	$	2,425	$	119,263	$	—	$	119,263
Future production costs		26,407		3,858		814		31,079		—		31,079
Future development costs		10,142		983		83		11,208		—		11,208
Future income tax expenses		20,891		5,592		365		26,848		—		26,848
Future net cash flows		41,097		7,868		1,163		50,128		—		50,128
10% annual discount for estimated timing of cash flows		19,743		4,356		396		24,495		—		24,495
Standardized measure of discounted future net cash flows	$	21,354	$	3,512	$	767	$	25,633	$	—	$	25,633
2005
Future cash inflows	$	87,304	$	19,192	$	2,507	$	109,003	$	12,679	$	121,682
Future production costs		17,262		1,025		515		18,802		2,847		21,649
Future development costs		5,231		746		238		6,215		1,076		7,291
Future income tax expenses		22,671		6,445		607		29,723		2,692		32,415
Future net cash flows		42,140		10,976		1,147		54,263		6,064		60,327
10% annual discount for estimated timing of cash flows		22,384		5,238		338		27,960		3,075		31,035
Standardized measure of discounted future net cash flows	$	19,756	$	5,738	$	809	$	26,303	$	2,989	$	29,292
2004
Future cash inflows	$	54,908	$	14,348	$	2,669	$	71,925	$	7,564	$	79,489
Future production costs		12,303		1,108		543		13,954		1,969		15,923
Future development costs		3,718		599		365		4,682		648		5,330
Future income tax expenses		13,582		4,611		560		18,753		1,493		20,246
Future net cash flows		25,305		8,030		1,201		34,536		3,454		37,990
10% annual discount for estimated timing of cash flows		13,382		3,915		391		17,688		1,653		19,341
Standardized measure of discounted future net cash flows	$	11,923	$	4,115	$	810	$	16,848	$	1,801	$	18,649

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Changes in Standardized Measure of Discounted Future Net Cash Flows

Relating to Proved Oil and Gas Reserves

	United States			Algeria			Other Int’l			Total Continuing Operations			Discontinued Operations			Total
millions
2006
Beginning of year	$	19,756		$	5,738		$	809		$	26,303		$	2,989		$	29,292
Sales and transfers of oil and gas produced, net of production costs		(6,004	)		(1,357	)		(296	)		(7,657	)		(531	)		(8,188	)
Net changes in prices and production costs		(10,974	)		(1,441	)		5			(12,410	)		48			(12,362	)
Changes in estimated future development costs		(266	)		(520	)		154			(632	)		420			(212	)
Extensions, discoveries, additions and improved recovery, less related costs		410			113			—			523			—			523
Development costs incurred during the period		1,021			66			12			1,099			191			1,290
Revisions of previous quantity estimates		(2,708	)		(267	)		(22	)		(2,997	)		(13	)		(3,010	)
Purchases of minerals in place		16,390			—			850			17,240			38			17,278
Sales of minerals in place		—			—			(1,073	)		(1,073	)		(4,638	)		(5,711	)
Accretion of discount		3,016			915			126			4,057			408			4,465
Net change in income taxes		27			403			195			625			1,088			1,713
Other		686			(138	)		7			555			—			555
End of year	$	21,354		$	3,512		$	767		$	25,633		$	—		$	25,633
2005
Beginning of year	$	11,923		$	4,115		$	810		$	16,848		$	1,801		$	18,649
Sales and transfers of oil and gas produced, net of production costs		(3,601	)		(1,225	)		(253	)		(5,079	)		(722	)		(5,801	)
Net changes in prices and production costs		10,736			3,732			771			15,239			1,809			17,048
Changes in estimated future development costs		(255	)		(235	)		14			(476	)		(259	)		(735	)
Extensions, discoveries, additions and improved recovery, less related costs		2,826			120			—			2,946			648			3,594
Development costs incurred during the period		874			45			57			976			76			1,052
Revisions of previous quantity estimates		(48	)		(465	)		(688	)		(1,201	)		(104	)		(1,305	)
Purchases of minerals in place		73			—			—			73			4			77
Sales of minerals in place		(324	)		—			(51	)		(375	)		(8	)		(383	)
Accretion of discount		1,828			650			118			2,596			241			2,837
Net change in income taxes		(4,043	)		(1,034	)		(75	)		(5,152	)		(478	)		(5,630	)
Other		(233	)		35			106			(92	)		(19	)		(111	)
End of year	$	19,756		$	5,738		$	809		$	26,303		$	2,989		$	29,292

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Changes in Standardized Measure of Discounted Future Net Cash Flows

Relating to Proved Oil and Gas Reserves (Continued)

	United States			Algeria			Other Int’l			Total Continuing Operations			Discontinued Operations			Total
millions
2004
Beginning of year	$	12,496		$	2,991		$	758		$	16,245		$	2,538		$	18,783
Sales and transfers of oil and gas produced, net of production costs		(3,171	)		(705	)		(160	)		(4,036	)		(689	)		(4,725	)
Net changes in prices and production costs		1,495			1,962			272			3,729			(75	)		3,654
Changes in estimated future development costs		(527	)		(23	)		(46	)		(596	)		(84	)		(680	)
Extensions, discoveries, additions and improved recovery, less related costs		4,233			73			—			4,306			507			4,813
Development costs incurred during the period		818			36			66			920			158			1,078
Revisions of previous quantity estimates		(707	)		(118	)		(122	)		(947	)		(124	)		(1,071	)
Purchases of minerals in place		28			—			—			28			7			35
Sales of minerals in place		(4,118	)		—			—			(4,118	)		(785	)		(4,903	)
Accretion of discount		1,876			471			103			2,450			329			2,779
Net change in income taxes		(89	)		(663	)		(104	)		(856	)		143			(713	)
Other		(411	)		91			43			(277	)		(124	)		(401	)
End of year	$	11,923		$	4,115		$	810		$	16,848		$	1,801		$	18,649

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ANADARKO PETROLEUM CORPORATION

SUPPLEMENTAL QUARTERLY INFORMATION

(Unaudited)

Quarterly Financial Data

The following table shows summary quarterly financial data for 2006 and 2005. Certain amounts for prior years have been reclassified to conform to the current presentation.

millions except share amounts	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2006
Revenues	$	1,701	$	1,809	$	3,498	$	3,179
Operating income	$	966	$	968	$	2,156	$	797
Income from continuing operations	$	565	$	663	$	1,382	$	186
Income from discontinued operations, net of taxes	$	96	$	152	$	79	$	1,731
Net income	$	661	$	815	$	1,461	$	1,917
Net income available to common stockholders	$	660	$	814	$	1,461	$	1,916
Earnings per share:
Income from continuing operations – basic	$	1.23	$	1.44	$	3.00	$	0.40
Income from continuing operations – diluted	$	1.22	$	1.43	$	2.98	$	0.40
Income from discontinued operations, net of taxes – basic	$	0.21	$	0.33	$	0.17	$	3.75
Income from discontinued operations, net of taxes – diluted	$	0.20	$	0.33	$	0.17	$	3.73
Net income available to common stockholders – basic	$	1.43	$	1.77	$	3.18	$	4.14
Net income available to common stockholders – diluted	$	1.42	$	1.76	$	3.15	$	4.13
Average number common shares outstanding – basic		460		459		460		462
Average number common shares outstanding – diluted		465		463		463		464
2005
Revenues	$	1,351	$	1,394	$	1,525	$	1,917
Operating income	$	740	$	757	$	883	$	1,155
Income from continuing operations	$	428	$	439	$	532	$	674
Income from discontinued operations, net of taxes	$	63	$	68	$	66	$	201
Net income	$	491	$	507	$	598	$	875
Net income available to common stockholders	$	490	$	506	$	596	$	874
Earnings per share:
Income from continuing operations — basic	$	0.90	$	0.93	$	1.13	$	1.45
Income from continuing operations — diluted	$	0.89	$	0.92	$	1.12	$	1.43
Income from discontinued operations, net of taxes — basic	$	0.13	$	0.14	$	0.14	$	0.43
Income from discontinued operations, net of taxes — diluted	$	0.13	$	0.14	$	0.14	$	0.43
Net income available to common stockholders — basic	$	1.03	$	1.07	$	1.27	$	1.88
Net income available to common stockholders — diluted	$	1.03	$	1.06	$	1.25	$	1.87
Average number common shares outstanding — basic		474		472		471		464
Average number common shares outstanding — diluted		478		477		476		469

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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, 2006.

Management’s Annual Report on Internal Control Over Financial Reporting

SeeManagement’s Assessment of Internal Control Over Financial Reportingunder Item 8 of this Form 10-K.

Attestation Report of the Registered Public Accounting Firm

SeeReport of Independent Registered Public Accounting Firmunder Item 8 of this Form 10-K.

Changes in Internal Control Over Financial Reporting

Except for the potential changes noted in the following paragraph relating to the Kerr McGee and Western acquisitions, there were no changes in Anadarko’s internal controls over financial reporting during the fourth quarter of 2006 that materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

In August 2006, the Company completed the acquisitions of Kerr-McGee and Western. Management continues to integrate the acquired companies’ historical internal control over financial reporting with the Company’s internal control over financial reporting. This integration will lead to changes in these controls in future fiscal periods but management does not yet know whether these changes will materially affect the Company’s internal control over financial reporting. Management expects the integration process to be completed during 2007.

Item 9b. Other Information

None.

PART III

Item 10.  Directors, Executive Officers and Corporate Governance

SeeAnadarko Board of Directors, Corporate Governance—Committees of the Board, Corporate Governance—Audit Committee andSection 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 16, 2007 (to be filed with the Securities and Exchange Commission prior to April 30, 2007), each of which is incorporated herein by reference.

127

See list ofExecutive Officers of the Registrant under Item 4 of this Form 10-K, which is incorporated herein by reference.

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

SeeCorporate Governance—Compensation and Benefits Committee Interlocks and Insider Participation, Corporate Governance—Director Compensation, Corporate Governance—Director Compensation Table for the Last Fiscal Year, Executive Compensation—Compensation and Benefits Committee Report on 2006 Executive Compensation, Compensation Discussion and Analysis, Executive Compensation and Transactions with Management and Others in the Proxy Statement, each of which is incorporated herein by reference. The Compensation and Benefits Committee Report and related information incorporated by reference herein shall not be deemed “soliciting material” or to be “filed” with the Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.

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

SeeStock 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, 2006:

Plan category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights	(b) Weighted-average exercise price of outstanding options, warrants and rights		(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column(a))
Equity compensation plans approved by security holders	6,645,955	$	31.78	11,609,743
Equity compensation plans not approved by security holders	—		—	—
Total	6,645,955	$	31.78	11,609,743

Item 13.  Certain Relationships and Related Transactions, and Director Independence

SeeCorporate Governance—Board of Directors andTransactions with Management and Othersin the Proxy Statement, each of which is incorporated herein by reference.

Item 14.  Principal Accounting Fees and Services

SeeIndependent Auditorin the Proxy Statement, which is incorporated herein by reference.

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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 60.

(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 Number	Description	Originally Filed as Exhibit	File Number
2(a)	Agreement and Plan of Merger dated as of June 22, 2006, among Anadarko Petroleum Corporation, APC Merger Sub, Inc. and Western Gas Resources, Inc.	2.1 to Form 8-K dated June 26, 2006	1-8968
(b)	Amendment No. 1 to Agreement and Plan of Merger dated as of June 22, 2006, among Anadarko Petroleum Corporation, APC Merger Sub, Inc. and Western Gas Resources, Inc.	2.1 to Form 8-K dated July 12, 2006	1-8968
(c)	Agreement and Plan of Merger dated as of June 22, 2006, among Anadarko Petroleum Corporation, APC Acquisition Sub, Inc. and Kerr-McGee Corporation	2.2 to Form 8-K dated June 26, 2006	1-8968
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	3.1 to Form 8-K dated February 16, 2007	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
(d)	Certificate of Amendment of Anadarko’s Restated Certificate of Incorporation	3(d) to Form 10-Q for quarter ended June 30, 2006	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
(d)	364-Day Term Loan Agreement, dated as of August 10, 2006, among Anadarko Petroleum Corporation and the Lenders	10.2 to Form 8-K dated August 15, 2006	1-8968
(e)	Underwriting Agreement, dated September 14, 2006, among Anadarko Petroleum Corporation and the Underwriters	1.1 to Form 8-K dated September 19, 2006	1-8968
(f)	Trustee Indenture dated as of September 19, 2006, Anadarko Petroleum Corporation to The Bank of New York Trust Company, N.A.	4.1 to Form 8-K dated September 19, 2006	1-8968

129

Exhibit Number	Description	Originally Filed as Exhibit	File Number
4(g)	Second Supplemental Indenture dated October 4, 2006, among Anadarko Petroleum Corporation, Kerr-McGee Corporation, and Citibank, N.A.	4.1 to Form 8-K dated October 5, 2006	1-8968
(h)	Ninth Supplemental Indenture dated October 4, 2006, among Anadarko Petroleum Corporation, Kerr-McGee Corporation, and Citibank, N.A.	4.2 to Form 8-K dated October 5, 2006	1-8968
10(a)(i)	Form of Voting Agreement dated as of June 22, 2006 for proposed Agreement and Plan of Merger with Western Gas Resources, Inc.	10.1 to Form 8-K dated June 26, 2006	1-8968
(ii)	Notice of Termination between Maritimes & Northeast Pipeline Limited Partnership and Anadarko Canada LNG Marketing Corp. dated September 8, 2006	10.1 to Form 8-K dated September 13, 2006	1-8968
(iii)	Notice of Termination between Maritimes & Northeast Pipeline, L.L.C. and Anadarko LNG Marketing LLC dated September 8, 2006	10.2 to Form 8-K dated September 13, 2006	1-8968
10(b)(i)	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
(ii)	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
(iii)	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
(iv)	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
(v)	1998 Director Stock Plan of Anadarko Petroleum Corporation, effective January 30, 1998	Appendix A to DEF 14A filed March 16, 1998	1-8968
(vi)	Form of Anadarko Petroleum Corporation 1998 Director Stock Plan Stock Option Agreement	10.1 to Form 8-K dated November 17, 2005	1-8968
(vii)	1993 Stock Incentive Plan	10(b)(xii) to Form 10-K for year ended December 31, 1993	1-8968
(viii)	First Amendment to Anadarko Petroleum Corporation 1993 Stock Incentive Plans	Appendix A to DEF 14A filed March 12, 1997	1-8968
(ix)	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
(x)	Anadarko Petroleum Corporation 1993 Stock Incentive Plan Stock Option Agreement	10(a) to Form 10-Q for quarter ended March 31, 1996	1-8968
(xi)	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

130

Exhibit Number	Description	Originally Filed as Exhibit	File Number
10(b)(xii)	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
(xiii)	Anadarko Petroleum Corporation Amended and Restated 1999 Stock Incentive Plan	Appendix A to DEF 14A filed March 18, 2005	1-8968
(xiv)	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
(xv)	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
(xvi)	Form of Stock Option Agreement — 1999 Stock Incentive Plan (UK Nationals)	10.4 to Form 8-K dated November 17, 2005	1-8968
(xvii)	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
(xviii)	Anadarko Petroleum Corporation 1999 Stock Incentive Plan Performance Share Agreement	10(b) to Form 10-Q for quarter ended March 31, 2004	1-8968
(xix)	Anadarko Petroleum Corporation 1999 Stock Incentive Plan Performance Unit Agreement	10.1 to Form 8-K dated December 14, 2004	1-8968
(xx)	Form of Anadarko Petroleum Corporation 1999 Stock Incentive Plan Performance Unit Agreement	10.1 to Form 8-K dated December 9, 2005	1-8968
(xxi)	Form of Anadarko Petroleum Corporation 1999 Stock Incentive Plan Performance Unit Agreement	10.2 to Form 8-K dated December 11, 2006	1-8968
(xxii)	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
(xxiii)	Annual Incentive Bonus Plan, as amended January 1, 2004	Appendix C to DEF 14A filed March 12, 2004	1-8968
(xxiv)	Key Employee Change of Control Contract	10(b)(xxii) to Form 10-K for year ended December 31, 1997	1-8968
(xxv)	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
(xxvi)	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
(xxvii)	Employment Agreement — James T. Hackett	10.1 to Form 8-K dated December 11, 2006	1-8968
(xviii)	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
(xxix)	Anadarko Retirement Restoration Plan, effective January 1, 1995	10(b)(xix) to Form 10-K for year ended December 31, 1995	1-8968

131

Exhibit Number	Description	Originally Filed as Exhibit	File Number
10(b)(xxx)	Anadarko Savings Restoration Plan, effective January 1, 1995	10(b)(xx) to Form 10-K for year ended December 31, 1995	1-8968
(xxxi)	First Amendment to Anadarko Retirement Restoration Plan, effective July 31, 2003	10(b)(xxxiii) to Form 10-K for year ended December 31, 2005	1-8968
(xxxii)	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
(xxxiii)	Amendment to Amended and Restated Anadarko Savings Restoration Plan, effective January 1, 2005	10(b)(xxxv) to Form 10-K for year ended December 31, 2005	1-8968
(xxxiv)	Anadarko Petroleum Corporation Estate Enhancement Program	10(b)(xxxiv) to Form 10-K for year ended December 31, 1998	1-8968
(xxxv)	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
(xxxvi)	Estate Enhancement Program Agreements effective November 29, 2000	10(b)(xxxxii) to Form 10-K for year ended December 31, 2000	1-8968
(xxxvii)	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
(xxxviii)	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
(xxxix)	Management Disability Plan — Plan Summary	10(b)(xxxiii) to Form 10-K for year ended December 31, 2002	1-8968
(xl)	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
(xli)	Anadarko Petroleum Corporation Officer Severance Plan	10(b)(iv) to Form 10-Q for quarter ended September 30, 2003	1-8968
(xlii)	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
(xliii)	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

132

Exhibit Number	Description	Originally Filed as Exhibit	File Number
10(b)(xliv)	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
(xlv)	Director and Officer Indemnification Agreement	10 to Form 8-K dated September 3, 2004	1-8968
(xlvi)	Summary of Director Compensation	10.1 to Form 8-K dated May 17, 2005	1-8968
(xlvii)	Summary of Material Terms of Employment — R. A. Walker	10.1 to Form 8-K dated August 11, 2005	1-8968
(xlviii)	Summary of Material Terms of Employment — Bruce W. Busmire	10.1 to Form 8-K dated May 4, 2006	1-8968
(xlix)	Retention Agreement between Anadarko Petroleum Corporation and Charles A. Meloy dated August 10, 2006	10.1 to Form 8-K dated August 15, 2006	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 2006 Annual Report to Stockholders
*21	List of Significant Subsidiaries
*23.1	Consent of KPMG LLP
*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	2006 Reports 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.

133

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
February 27, 2007	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 27, 2007.

	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/    BRUCE W. BUSMIRE         (Bruce W. Busmire)	Vice President, Chief Accounting Officer
(iv) Directors:*
	ROBERT J. ALLISON, JR. LARRY BARCUS JAMES L. BRYAN JOHN R. BUTLER, JR. LUKE R. CORBETT 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)

134