Edgar Filing: ANADARKO PETROLEUM CORP

Form 10-K

Index to Financial Statements

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. Yes x No ¨.

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨.

Indicate by check mark if 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 ¨ No x.

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).

Index to Financial Statements

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

Index to Financial Statements

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, see Acquisitions and Divestitures and Outlook 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

Index to Financial Statements

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

Index to Financial Statements

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

Index to Financial Statements

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 in Financial Results and Gathering, Processing and Marketing Strategies under Item 7 of this Form 10-K. Additional detail of production costs is contained in the Supplemental Information under Item 8 of this Form 10-K. Information on major customers is contained in Note 15 of the Notes 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

Index to Financial Statements

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
	Natural Gas (MMcf/d)	Oil and NGLs (MBbls/d)	Total (MBOE/d)		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.

Index to Financial Statements

LOGO


	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

Index to Financial Statements

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.

Index to Financial Statements

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.

Index to Financial Statements

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.

Index to Financial Statements

LOGO

Producing

Undeveloped

Developed

Wells

(Net

)

(Net

)

(Net

)

Offshore Acreage:

Gulf of
Mexico

Western

1,386,142

63,911

Central

979,690

45,646

Eastern

265,536

1,152

California

2,785

908

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

Index to Financial Statements

Properties and Activities — Algeria

Overview Anadarko is engaged in exploration, development and production activities in Algeria’s Sahara Desert. At the end of 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 see Risk Factors under Item 1a and Other 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.

Index to Financial Statements

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 see Other Developments under Item 7 of this Form 10-K.

Qatar The Company had interests in 1,549,000 undeveloped lease acres and 19,000 developed acres in Qatar at year-end 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.

Index to Financial Statements

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

Index to Financial Statements

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

Index to Financial Statements

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

Index to Financial Statements

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, see Note 10 — Sale of Future Hard Minerals Royalty Revenues of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Segment and Geographic Information

Information on operations by segment and geographic location is contained in Note 16 of the Notes 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.

Index to Financial Statements

Regulatory Matters and Additional Factors Affecting Business

See Risk Factors under Item 1a of this Form 10-K.

Title to Properties

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

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

Capital Spending

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

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


	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,

Index to Financial Statements

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.

Index to Financial Statements

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, see Outlook 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 Policies under 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

Index to Financial Statements

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, see Legal Proceedings under Item 3 of this Form 10-K.

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

Our business is subject to all of the operating risks normally associated with the exploration for and production, 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.

Index to Financial Statements

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 see Other 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,

Index to Financial Statements

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.

Index to Financial Statements

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

Index to Financial Statements

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.

Index to Financial Statements

Item 2. Properties

Information on Properties is contained in Item 1 of this Form 10-K and in Note 20 — Commitments of the Notes to Consolidated Financial Statements under 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.

Index to Financial Statements

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.

Index to Financial Statements

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.

Index to Financial Statements

PART II

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

Information on the market price and cash dividends declared per share of common stock is included in Corporate Information in the Anadarko Petroleum Corporation 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, see Dividends under Item 7 and Note 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.

Index to Financial Statements

Performance Graph

The following performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the 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

LOGO


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

Index to Financial Statements

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 in Management’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

Index to Financial Statements

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. See Acquisitions and Divestitures, Outlook and Discontinued 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%

Index to Financial Statements

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. See Energy Price Risk under Item 7a and Note 9 — Financial Instruments under Item 8 of this Form 10-K.

Index to Financial Statements

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.

Index to Financial Statements

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.

Index to Financial Statements

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.

Index to Financial Statements

—

Other taxes increased 61%. The increase includes a $103 million accrual for the estimated impact of a new Algerian exceptional profits tax. See Other 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.

Index to Financial Statements

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 see Acquisitions and Divestitures and Debt below and Interest 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.

Index to Financial Statements

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. See Outlook. 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.

Index to Financial Statements

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. See Discontinued Operations.

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

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 the Supplemental 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

Index to Financial Statements

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.

Index to Financial Statements

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%.

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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.

Index to Financial Statements

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

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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%

Index to Financial Statements

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.

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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.

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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

Index to Financial Statements

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. See Supplemental Information under Item 8 of this Form 10-K.

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

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.

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. See Energy Price Risk under Item 7a of this Form 10-K.

In an effort to protect the Company from commodity price risk stemming from the 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

Index to Financial Statements

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

Index to Financial Statements

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 in Outlook that 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, see Note 8 — Debt and Interest Expense of the Notes to Consolidated Financial Statements under 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.

Index to Financial Statements

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.

Index to Financial Statements

The Company’s 2006 exploration and development drilling program is discussed in Oil and Gas Properties and Activities under 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.

Index to Financial Statements

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 see Risk 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.

Index to Financial Statements

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.

Index to Financial Statements

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.

Index to Financial Statements

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 see Note 20 — Commitments of the Notes to Consolidated Financial Statements under 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.

Index to Financial Statements

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. See Critical 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, see Note 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 and Note 22 — Contingencies of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Index to Financial Statements

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.

Index to Financial Statements

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.

Index to 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 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

Index to Financial Statements

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.

Index to Financial Statements

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, see Note 1 — Summary of Significant Accounting Policies, Note 8 — Debt and Note 9 — Financial Instruments of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Energy Price Risk The Company’s most significant market risk is the pricing for natural gas, crude oil 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, see Gathering, 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.

Index to Financial Statements

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

Index to Financial Statements

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 in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, we believe that as of December 31, 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

Index to Financial Statements

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Anadarko Petroleum Corporation:

We have audited management’s assessment, included in the accompanying Management’s Assessment of Internal Control Over Financial Reporting, that Anadarko Petroleum Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

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

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

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 in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal 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

Index to Financial Statements

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

Index to Financial Statements

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 in Internal 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

Index to Financial Statements

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.

Index to Financial Statements

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.

Index to Financial Statements

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		—			—